Stone Energy (SGY) 10-K 26 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Feb. 22, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Entity Registrant Name	STONE ENERGY CORP
Trading Symbol	SGY
Entity Central Index Key	904,080
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		56,849,335
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 695.9

CONSOLIDATED BALANCE SHEET

CONSOLIDATED BALANCE SHEET - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 10,759	$ 74,488	$ 331,224	$ 279,526
Restricted cash	0	177,647
Accounts receivable	48,031	120,359
Fair value of derivative contracts	38,576	139,179
Current income tax receivable	46,174	7,212
Inventory	535	3,709
Other current assets	6,346	8,118
Total current assets	150,421	530,712
Oil and gas properties, full cost method of accounting:
Proved	9,375,898	8,817,268
Less: accumulated depreciation, depletion and amortization	(8,603,955)	(6,970,631)
Net proved oil and gas properties	771,943	1,846,637
Unevaluated	440,043	567,365
Other property and equipment, net of accumulated depreciation of $27,424 and $24,091, respectively	29,289	32,340
Fair value of derivative contracts	0	14,333
Other assets, net of accumulated depreciation and amortization of $4,376 and $3,560, respectively	18,473	18,470
Total assets	1,410,169	3,009,857
Current liabilities:
Accounts payable to vendors	82,207	132,629
Undistributed oil and gas proceeds	5,992	23,232
Accrued interest	9,022	9,022
Deferred taxes	0	20,119
Asset retirement obligations	21,291	69,400
Other current liabilities	40,712	49,505
Total current liabilities	159,224	303,907
Long-term debt	1,060,955	1,032,281
Deferred taxes	0	286,343
Asset retirement obligations	204,575	247,009
Other long-term liabilities	25,204	38,714
Total liabilities	$ 1,449,958	$ 1,908,254
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 150,000,000 shares; issued 55,302,325 and 54,884,542 shares, respectively	$ 553	$ 549
Treasury stock (16,582 shares, at cost)	(860)	(860)
Additional paid-in capital	1,648,189	1,633,307
Accumulated deficit	(1,705,623)	(614,708)
Accumulated other comprehensive income	17,952	83,315	$ (2,062)	$ 28,833
Total stockholders’ equity	(39,789)	1,101,603
Total liabilities and stockholders’ equity	$ 1,410,169	$ 3,009,857

CONSOLIDATED BALANCE SHEET (Par

CONSOLIDATED BALANCE SHEET (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Other property and equipment, accumulated depreciation	$ 27,424	$ 24,091
Other assets, accumulated depreciation and amortization	$ 4,376	$ 3,560
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares issued (in shares)	55,302,325	54,884,542
Treasury stock, shares (in shares)	16,582	16,582

CONSOLIDATED STATEMENT OF OPERA

CONSOLIDATED STATEMENT OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenue:
Oil production									$ 416,497	$ 516,104	$ 715,104
Natural gas production									83,509	166,494	190,580
Natural gas liquids production									32,322	85,642	60,687
Other operational income									4,369	7,951	7,808
Derivative income, net									7,952	19,351	0
Total operating revenue	$ 110,499	$ 132,196	$ 149,525	$ 153,498	$ 184,780	$ 183,213	$ 207,046	$ 223,830	544,649	795,542	974,179
Operating expenses:
Lease operating expenses									100,139	176,495	201,153
Transportation, processing and gathering expenses									58,847	64,951	42,172
Production taxes									6,877	12,151	15,029
Depreciation, depletion and amortization									281,688	340,006	350,574
Write-down of oil and gas properties	351,062	295,679	224,294	491,412	304,062	47,130	0	0	1,362,447	351,192	0
Accretion expense									25,988	28,411	33,575
Salaries, general and administrative expenses									69,384	66,451	59,524
Franchise tax settlement									0	0	12,590
Incentive compensation expense									2,242	10,361	15,340
Other operational expenses									2,360	862	151
Derivative expense, net									0	0	2,090
Total operating expenses									1,909,972	1,050,880	732,198
Income (loss) from operations	(342,759)	(297,209)	(228,161)	(497,194)	(286,147)	(34,356)	16,613	48,552	(1,365,323)	(255,338)	241,981
Other (income) expenses:
Interest expense									43,928	38,855	32,837
Interest income									(580)	(574)	(1,695)
Other income									(1,783)	(2,332)	(2,799)
Other expense									434	274	0
Loss on early extinguishment of debt									0	0	27,279
Total other expenses									41,999	36,223	55,622
Income (loss) before income taxes									(1,407,322)	(291,561)	186,359
Provision (benefit) for income taxes:
Current									(44,096)	159	(10,904)
Deferred									(272,311)	(102,177)	79,629
Total income taxes									(316,407)	(102,018)	68,725
Net income (loss)	$ (318,656)	$ (291,965)	$ (152,906)	$ (327,388)	$ (190,515)	$ (29,415)	$ 4,444	$ 25,943	$ (1,090,915)	$ (189,543)	$ 117,634
Basic earnings (loss) per share (in usd per share)	$ (5.76)	$ (5.28)	$ (2.77)	$ (5.93)	$ (3.47)	$ (0.54)	$ 0.08	$ 0.52	$ (19.75)	$ (3.60)	$ 2.36
Diluted earnings (loss) per share (in usd per share)	$ (5.76)	$ (5.28)	$ (2.77)	$ (5.93)	$ (3.47)	$ (0.54)	$ 0.08	$ 0.52	$ (19.75)	$ (3.60)	$ 2.36
Average shares outstanding (in shares)									55,250	52,721	48,693
Average shares outstanding assuming dilution (in shares)									55,250	52,721	48,735

CONSOLIDATED STATEMENT OF COMPR

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (318,656)	$ (291,965)	$ (152,906)	$ (327,388)	$ (190,515)	$ (29,415)	$ 4,444	$ 25,943	$ (1,090,915)	$ (189,543)	$ 117,634
Other comprehensive income (loss), net of tax effect:
Derivatives									(62,758)	88,178	(30,228)
Foreign currency translation									(2,605)	(2,801)	(667)
Comprehensive income (loss)									$ (1,156,278)	$ (104,166)	$ 86,739

CONSOLIDATED STATEMENT OF CASH

CONSOLIDATED STATEMENT OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ (1,090,915)	$ (189,543)	$ 117,634
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	281,688	340,006	350,574
Write-down of oil and gas properties	1,362,447	351,192	0
Accretion expense	25,988	28,411	33,575
Deferred income tax (benefit) provision	(272,311)	(102,177)	79,629
Settlement of asset retirement obligations	(72,382)	(56,409)	(83,854)
Non-cash stock compensation expense	12,324	11,325	10,347
Excess tax benefits	(1,586)	0	(156)
Non-cash derivative (income) expense	16,440	(18,028)	2,239
Loss on early extinguishment of debt	0	0	27,279
Non-cash interest expense	17,788	16,661	16,219
Change in current income taxes	(37,377)	158	2,767
(Increase) decrease in accounts receivable	43,724	51,611	(4,683)
(Increase) decrease in other current assets	1,767	(6,244)	1,752
Decrease in inventory	1,304	0	583
Increase (decrease) in accounts payable	(14,582)	(3,419)	402
Increase (decrease) in other current liabilities	(25,936)	(19,152)	42,451
Other	(907)	(3,251)	(2,553)
Net cash provided by operating activities	247,474	401,141	594,205
Cash flows from investing activities:
Investment in oil and gas properties	(522,047)	(927,247)	(663,299)
Proceeds from sale of oil and gas properties, net of expenses	22,839	242,914	48,821
Investment in fixed and other assets	(1,549)	(10,182)	(6,816)
Change in restricted funds	179,467	(178,072)	(1,742)
Net cash used in investing activities	(321,290)	(872,587)	(623,036)
Cash flows from financing activities:
Proceeds from bank borrowings	5,000	0	0
Repayments of bank borrowings	(5,000)	0	0
Proceeds from building loan	11,770	0	0
Proceeds from issuance of senior notes	0	0	489,250
Net proceeds from issuance of common stock	0	225,999	0
Deferred financing costs	(68)	(3,371)	(9,065)
Redemption of senior notes	0	0	(396,014)
Excess tax benefits	1,586	0	156
Net payments for share-based compensation	(3,127)	(7,182)	(3,733)
Net cash provided by financing activities	10,161	215,446	80,594
Effect of exchange rate changes on cash	(74)	(736)	(65)
Net change in cash and cash equivalents	(63,729)	(256,736)	51,698
Cash and cash equivalents, beginning of year	74,488	331,224	279,526
Cash and cash equivalents, end of year	10,759	74,488	331,224
Supplemental cash flow information:
Cash paid for interest, net of amount capitalized	(34,394)	(14,076)	(29,883)
Cash (paid) refunded for income taxes	$ 7,212	$ (1)	$ 13,670

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Treasury Stock	Additional Paid-In Capital	Accumulated Deficit	Accumulated Other Comprehensive Income (Loss)
Beginning Balance at Dec. 31, 2012	$ 872,133	$ 484	$ (860)	$ 1,386,475	$ (542,799)	$ 28,833
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	117,634				117,634
Adjustment for fair value accounting of derivatives, net of tax	(30,228)
Foreign currency translation adjustment	(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)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(189,543)				(189,543)
Adjustment for fair value accounting of derivatives, net of tax	88,178
Foreign currency translation adjustment	(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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(1,090,915)				(1,090,915)
Adjustment for fair value accounting of derivatives, net of tax	(62,758)
Foreign currency translation adjustment	(2,605)
Exercise of stock options and vesting of restricted stock	(2,638)	4		(2,642)
Amortization of stock compensation expense	17,524			17,524
Net tax impact from stock option exercises and restricted stock vesting	0
Ending Balance at Dec. 31, 2015	$ (39,789)	$ 553	$ (860)	$ 1,648,189	$ (1,705,623)	$ 17,952

ORGANIZATION AND SUMMARY OF SIG

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	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 this 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 and Utica shales in Appalachia. We were incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508. We have additional offices in New Orleans, Louisiana, Houston, Texas and Morgantown, West Virginia. A summary of significant accounting policies followed in the preparation of the accompanying consolidated financial statements is set forth below. Basis of Presentation: The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Energy Offshore, L.L.C. (“Stone Offshore”), Stone Energy Holding, L.L.C., Stone Energy Canada, U.L.C., SEO A LLC and SEO B LLC. All intercompany balances have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation (see Note 11 - Long-Term Debt ). 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, 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, 2015 and 2014 , 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. 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 entitlements 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 2013 , 2014 and 2015 , 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. 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 natural gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments are recorded in our balance sheet at fair value and subsequent 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. 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.

GOING CONCERN

GOING CONCERN	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
GOING CONCERN	GOING CONCERN: The accompanying consolidated financial statements have been prepared assuming the company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the company be unable to continue as a going concern. The level of our indebtedness of $1,137,000 and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. At December 31, 2015, we were in compliance with all of our financial covenants under our bank credit facility and the indentures governing our outstanding notes. However, given the lower commodity prices and our reduced hedged position in 2016, we anticipate that we could exceed the Consolidated Funded Debt to consolidated EBITDA financial ratio covenant of 3.75 to 1 set forth in our bank credit agreement at the end of the first quarter of 2016, which would require us to seek a waiver or amendment from our bank lenders. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it may result in an event of default and an acceleration under our other debt instruments. These conditions raise substantial doubt about our ability to continue as a going concern. We are currently in discussions with our banks regarding an amendment to our bank credit facility to address this potential covenant issue. We cannot provide any assurances that we will reach an agreement with the lenders under our bank credit facility on a waiver or amendment on a timely basis, or on satisfactory terms, to alleviate any non-compliance with our debt covenants. Additionally, we have $1,075,000 of senior indebtedness that we need to restructure or pay down. We are in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives through a private restructuring, asset sales and a prepackaged bankruptcy filing. We cannot provide any assurances that we will be able to complete a private restructuring or asset sales on satisfactory terms to provide the liquidity to restructure or pay down our senior indebtedness.

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
EARNINGS PER SHARE	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, 2015 2014 2013 Income (numerator): Basic: Net income (loss) $ (1,090,915 ) $ (189,543 ) $ 117,634 Net income attributable to participating securities — — (2,817 ) Net income (loss) attributable to common stock - basic $ (1,090,915 ) $ (189,543 ) $ 114,817 Diluted: Net income (loss) $ (1,090,915 ) $ (189,543 ) $ 117,634 Net income attributable to participating securities — — (2,815 ) Net income (loss) attributable to common stock - diluted $ (1,090,915 ) $ (189,543 ) $ 114,819 Weighted average shares (denominator): Weighted average shares - basic 55,250 52,721 48,693 Dilutive effect of stock options — — 42 Weighted average shares - diluted 55,250 52,721 48,735 Basic earnings (loss) per share $ (19.75 ) $ (3.60 ) $ 2.36 Diluted earnings (loss) per share $ (19.75 ) $ (3.60 ) $ 2.36 All outstanding stock options were considered antidilutive during the years ended December 31, 2015 ( 145,000 shares) and December 31, 2014 ( 205,000 shares) because we had a net loss for such periods. 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 shares during the year ended December 31, 2013 . During the years ended December 31, 2015 , 2014 and 2013 , approximately 418,000 , 384,000 and 358,000 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. For the years ended December 31, 2015 and 2014, the 2017 Convertible Notes had no dilutive effect in the diluted earnings per share computation as we had a net loss for such years. For the year ended December 31, 2013 , the average price of our common stock was less than the effective conversion price for such notes, resulting in no dilutive effect in the diluted earnings per share computation under the treasury stock method. For the years ended December 31, 2015 , 2014 and 2013 , 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.

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE	12 Months Ended
	Dec. 31, 2015
Receivables [Abstract]
ACCOUNTS RECEIVABLE	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, 2015 2014 Other co-venturers $ 4,639 $ 16,291 Trade 26,224 60,263 Unbilled accounts receivable 1,736 33,052 Other 15,432 10,753 Total accounts receivable $ 48,031 $ 120,359

CONCENTRATIONS

CONCENTRATIONS	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
CONCENTRATIONS	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 natural gas revenue during the indicated periods: Year Ended December 31, 2015 2014 2013 Phillips 66 Company 53 % 31 % 35 % Shell Trading (US) Company 13 % 32 % 33 % The maximum amount of credit risk exposure at December 31, 2015 relating to these customers was $20,826 . 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 natural gas production. Production and Reserve Volumes- Unaudited Approximately 99% of our estimated proved reserves at December 31, 2015 and 56% of our production during 2015 were associated with our GOM deep water, conventional shelf and deep gas properties. Approximately 1% of our estimated proved reserves at December 31, 2015 and 44% of our production during 2015 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, 2015
Business Combinations [Abstract]
DIVESTITURES	DIVESTITURES: On January 16, 2014, we completed the sale 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 . 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 . 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 were included in our balance sheet as restricted cash at December 31, 2014. Compliance with provisions under the Qualified Trust Agreement and Exchange Agreement provided 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.

DERIVATIVE INSTRUMENTS AND HEDG

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	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. We have entered into fixed-price swaps and costless collars with various counterparties for a portion of our expected 2016 oil and natural gas production from the Gulf Coast Basin. Our fixed-price oil swap settlements and oil collar 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. Collar contracts typically require payments by us if the NYMEX average closing price is above the ceiling price or payments to us if the NYMEX average closing price is below the floor price. Our fixed-price swap contracts are with The Toronto-Dominion Bank, The Bank of Nova Scotia and Natixis. Our oil collar contract is with The Bank of Nova Scotia. All of our derivative transactions have been carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The counterparties to all of our derivative instruments have an "investment grade" credit rating. We monitor the credit ratings of our derivative counterparties on an ongoing basis. Although we have entered into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, we may not realize the benefit of some of our derivative instruments and incur a loss. At December 31, 2015, two counterparties accounted for approximately 86% of our contracted volumes. All of our derivative instruments are with lenders under our bank credit facility. The following tables illustrate our derivative positions for calendar year 2016 as of February 22, 2016 : Fixed-Price Swaps (NYMEX) Natural Gas Oil Daily Volume (MMBtus/d) Swap Price ($/MMBtu) Daily Volume (Bbls/d) Swap Price ($/Bbl) 2016 10,000 4.110 1,000 49.75 2016 10,000 4.120 1,000 52.78 2016 1,000 90.00 Costless Collar (NYMEX) Oil Daily Volume (Bbls/d) Floor Price ($) Ceiling Price ($) 2016 1,000 45.00 54.75 All of our derivative instruments at December 31, 2013 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 certain contracts for the months of August through December 2014 and 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, 2015 , we had accumulated other comprehensive income of $24,025 , net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of December 31, 2015 .The $24,025 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, 2015 and 2014 : Fair Value of Derivatives Qualifying as Hedging Instruments at December 31, 2015 Asset Derivatives Liability Derivatives Description Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity contracts Current assets: Fair value of derivative contracts $ 38,576 Current liabilities: Fair value of derivative contracts — Long-term assets: Fair value of derivative contracts — Long-term liabilities: Fair value of derivative contracts — $ 38,576 $ — 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 $ — 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, 2015 , 2014 and 2013 : Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations for the Years Ended December 31, 2015, 2014, and 2013 Derivatives in Cash Flow Hedging Relationships Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion) (a) Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) Location Location 2015 2015 2015 Commodity contracts $ 52,630 Operating revenue - oil/natural gas production $ 149,955 Derivative income (expense), net $ 2,713 Total $ 52,630 $ 149,955 $ 2,713 2014 2014 2014 Commodity contracts $ 136,097 Operating revenue - oil/natural gas production $ 526 Derivative income (expense), net $ 5,721 Total $ 136,097 $ 526 $ 5,721 2013 2013 2013 Commodity contracts $ (26,945 ) Operating revenue - oil/natural gas production $ 20,289 Derivative income (expense), net $ (2,090 ) Total $ (26,945 ) $ 20,289 $ (2,090 ) (a) For the year ended December 31, 2015 , effective hedging contracts increased oil revenue by $135,617 and increased natural gas revenue by $14,338 . For the year ended December 31, 2014 , effective hedging contracts increased oil revenue by $7,929 and (decreased) natural gas revenue by $7,403 . For the year ended December 31, 2013 , effective hedging contracts increased oil revenue by $3,520 and increased natural gas revenue by $16,769 . 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, 2015 and 2014 : Fair Value of Derivatives Not Qualifying as Hedging Instruments Description Balance Sheet Location December 31, 2015 December 31, 2014 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 years ended December 31, 2015 and 2014 . All of our derivatives for the year ended December 31, 2013 qualified as hedging instruments. Gain (Loss) Recognized in Derivative Income (Expense) Year Ended Description December 31, 2015 December 31, 2014 Commodity contracts: Cash settlements $ 17,385 $ 1,484 Change in fair value (12,146 ) 12,146 Total gain on non-qualifying derivatives $ 5,239 $ 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, 2015 and 2014, all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	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, 2015 and 2014 , 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, and our collar contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars were the volatility impacts in the pricing model as it relates to the call portion of the collar. 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. We had no liabilities measured at fair value on a recurring basis at December 31, 2015 and 2014. The following tables present our assets that are measured at fair value on a recurring basis at December 31, 2015 and 2014: Fair Value Measurements at December 31, 2015 Assets Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Marketable securities (Other assets) $ 8,499 $ 8,499 $ — $ — Derivative contracts 38,576 — 36,603 1,973 Total $ 47,075 $ 8,499 $ 36,603 $ 1,973 Fair Value Measurements at December 31, 2014 Assets Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Marketable securities (Other assets) $ 8,425 $ 8,425 $ — $ — Derivative contracts 153,512 — 153,512 — Total $ 161,937 $ 8,425 $ 153,512 $ — The table below presents a reconciliation for assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the year ended December 31, 2015 . Hedging Contracts, net Balance as of January 1, 2015 $ — Total gains/(losses) (realized or unrealized): Included in earnings 63 Included in other comprehensive income 1,910 Purchases, sales, issuances and settlements — Transfers in and out of Level 3 — Balance as of December 31, 2015 $ 1,973 The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at December 31, 2015 $ 63 The fair value of cash and cash equivalents approximated book value at December 31, 2015 and 2014 . As of December 31, 2015 and 2014 , the fair value of the liability component of the 2017 Convertible Notes was approximately $217,117 and $252,587 , respectively. As of December 31, 2015 and 2014 , the fair value of the 7 1 ⁄ 2 % Senior Notes due 2022 (the “2022 Notes”) was approximately $271,250 and $664,563 , 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 (see Note 11 – Long-Term Debt ) at inception and at December 31, 2015 and 2014 . 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, 2015
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS: The change in our asset retirement obligations during the years ended December 31, 2015 , 2014 and 2013 is set forth below: Year Ended December 31, 2015 2014 2013 Asset retirement obligations as of the beginning of the year, including current portion $ 316,409 $ 502,513 $ 488,302 Liabilities incurred 15,933 28,606 19,043 Liabilities settled (72,713 ) (55,839 ) (79,695 ) Divestment of properties (248 ) (137,801 ) (9,245 ) Accretion expense 25,988 28,411 33,575 Revision of estimates (59,503 ) (49,481 ) 50,533 Asset retirement obligations as of the end of the year, including current portion $ 225,866 $ 316,409 $ 502,513

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES: An analysis of our deferred taxes follows: As of December 31, 2015 2014 Tax effect of temporary differences: Net operating loss carryforwards $ 31,624 $ 99,615 Oil and gas properties – full cost 76,766 (476,367 ) Asset retirement obligations 79,618 113,907 Stock compensation 5,199 5,603 Hedges (13,598 ) (54,439 ) Accrued incentive compensation 1,234 6,185 Other (722 ) (966 ) Total deferred tax assets (liabilities) 180,121 (306,462 ) Valuation allowance (180,121 ) — Net deferred tax liabilities $ — $ (306,462 ) We estimate that we had ($44,096) , $159 and ($10,904) of current federal income tax expense (benefit) for the years ended December 31, 2015, 2014 and 2013, respectively. For the years ended December 31, 2015, 2014 and 2013, we recorded deferred income tax expense (benefits) of ($272,311) , ($102,177) and $79,629 , respectively. The deferred income tax benefits were a result of our losses before income taxes attributable primarily to ceiling test write-downs of our oil and gas properties (see Note 17 - Supplemental Information on Oil and Natural Gas Operations - Unaudited ). We had current income tax receivables of $46,174 and $7,212 at December 31, 2015 and 2014 , respectively, both of which were expected tax refunds from the carryback of net operating losses to previous tax years. For tax reporting purposes, net operating loss carryforwards totaled approximately $97,225 at December 31, 2015 . If not utilized, the majority of such carryforwards would expire in 2035 . In addition, we had approximately $1,056 in statutory depletion deductions available for tax reporting purposes that may be carried forward indefinitely. Recognition of a deferred tax asset associated with these and other carryforwards is dependent upon our evaluation that it is more likely than not that the asset will ultimately be realized. As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred over the past several quarters, we determined during 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a $180,121 valuation allowance against a portion of our deferred tax assets. Our assessment of the realizability of our deferred tax assets is based on the weight of all available evidence, both positive and negative, including future reversals of deferred tax liabilities. 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, 2015 2014 2013 Income tax expense computed at the statutory federal income tax rate 35.0% 35.0% 35.0% State taxes 0.6 1.0 1.0 Change in valuation allowance (12.8) — — IRC Sec. 162(m) limitation (0.1) (0.5) 0.8 Tax deficits on stock compensation (0.1) (0.2) — Other (0.1) (0.3) 0.1 Effective income tax rate 22.5% 35.0% 36.9% Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to ($35,737) , $49,601 and ($17,003) for the years ended December 31, 2015 , 2014 and 2013 , respectively. As of December 31, 2015 , we had unrecognized tax benefits of $491 . If recognized, all of our unrecognized tax benefits would impact our effective tax rate. A reconciliation of the total amounts of unrecognized tax benefits follows: Total unrecognized tax benefits as of December 31, 2014 $ — Increases (decreases) in unrecognized tax benefits as a result of: Tax positions taken during a prior period 491 Tax positions taken during the current period — Settlements with taxing authorities — Lapse of applicable statute of limitations — Total unrecognized tax benefits as of December 31, 2015 $ 491 Our unrecognized tax benefits pertain to a proposed state income tax audit adjustment. We believe that our unrecognized tax benefits may be reduced to zero within the next 12 months upon completion and ultimate settlement of the examination. It is our policy to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expenses, respectively. We recognized $131 of interest expense and no penalties related to uncertain tax positions for the year ended December 31, 2015 . No such amounts were recognized for the year ended December 31, 2014. The liabilities for unrecognized tax benefits and accrued interest payable are components of other current liabilities on our balance sheet. The tax years 2012 through 2015 remain subject to examination by major tax jurisdictions.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT: Long-term debt consisted of the following at: December 31, 2015 2014 1 3 ⁄ 4 % Senior Convertible Notes due 2017 $ 279,244 $ 262,791 7 1 ⁄ 2 % Senior Notes due 2022 770,009 769,490 Revolving credit facility — — 4.20% Building Loan 11,702 — Total long-term debt $ 1,060,955 $ 1,032,281 Revolving Credit Facility 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 2015. As of December 31, 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. As of February 22, 2016 , we had $50,000 of outstanding borrowings under the bank credit facility and $19,221 in letters of credit had been issued pursuant to the bank credit facility, leaving $430,779 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. As of December 31, 2015, the bank credit facility was guaranteed by Stone Offshore, SEO A LLC and SEO B LLC (collectively, the "Guarantor Subsidiaries"). The borrowing base under the bank credit facility is redetermined semi-annually, typically 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, due to a redetermination of our borrowing base, our outstanding bank credit facility borrowings plus any outstanding letters of credit exceed our redetermined borrowing base (referred to as a borrowing base deficiency), we could be required to repay such borrowing base deficiency. Our agreement with the banks allows us to cure a borrowing base deficiency through any combination of the following actions: (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; and/or (3) arrange to pay the deficiency in six equal monthly installments. The bank credit facility is collateralized by substantially all of the assets of Stone and its material subsidiaries. We are required to mortgage, and grant a security interest in, our oil and natural gas reserves representing at least 80% of the discounted present value of the future net cash flows from our 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, 2015 , our Consolidated Funded Debt to consolidated EBITDA ratio was 3.09 to 1 and our consolidated EBITDA to consolidated Net Interest Expense ratio was approximately 7.91 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, 2015 . Building Loan On November 20, 2015, we entered into an $11,802 term loan agreement (the "Building Loan"), maturing on December 20, 2030. The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of $73 commencing on December 20, 2015. The Building Loan is collaterized by our two Lafayette, Louisiana office buildings. Under the financial covenants of the Building Loan, we must maintain a ratio of EBITDA to Net Interest Expense of not less than 2.00 to 1.00. As of December 31, 2015, our EBITDA to Net Interest Expense ratio was 7.91 to 1. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities. 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, based on an initial conversion rate of 2.3445 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, 2015 , our closing share price was $4.29 . 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. 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. The 2017 Convertible Notes will be due on March 1, 2017, unless earlier converted or repurchased by us at the option of the holder(s), and interest is payable on the 2017 Convertible Notes each March 1 and September 1. On the maturity date, each holder will be entitled to receive $1 in cash for each $1 in principal amount of 2017 Convertible Notes, together with any accrued and unpaid interest to, but excluding, the maturity date. 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, 2015 , the carrying amount of the liability component of the 2017 Convertible Notes was $279,244 and $1,750 had been accrued in connection with the March 1, 2016 interest payment. During the year ended December 31, 2015 , we recognized $15,019 of interest expense for the amortization of the discount and $1,434 of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. 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 $12,599 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, 2015 , 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, SEO A LLC, SEO B LLC 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. 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, 2015 , $7,266 had been accrued in connection with the May 15, 2016 interest payment. Deferred Financing Cost and Interest Cost In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-03, " Interest - Imputation of Interest, Simplifying the Presentation of Debt Issuance Costs " which requires the presentation of debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability and not as a separate asset. In August 2015, the guidance was further clarified to state that debt issuance costs related to line-of-credit arrangements could be reported as a deferred asset and subsequently amortized ratably over the term of the line-of-credit agreement. We have elected to early adopt this standard effective December 31, 2015. As a result of our early adoption of ASU 2015-03, deferred financing costs, net of accumulated amortization, related to the 2017 Convertible Notes, 2022 Notes and Building Loan were reclassified from other assets to a direct deduction from the carrying amount of the debt liabilities. At December 31, 2015 and 2014 , approximately $6,869 and $8,754 , respectively, of unamortized deferred financing costs were deducted from the carrying amount of the related debt liabilities for the 2017 Convertible Notes, 2022 Notes and Building Loan. The deferred financing costs, net of accumulated amortization, of $2,845 and $3,661 at December 31, 2015 and 2014, respectively, related to the bank credit facility remain classified as other assets. 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 Building Loan are being amortized using the effective interest method over the term of the Building Loan. The costs associated with the bank credit facility are being amortized on a straight-line basis over the term of the facility. Total interest cost incurred, before capitalization, on all obligations for the years ended December 31, 2015 , 2014 and 2013 was $85,267 , $84,577 and $79,697 respectively.

ACCUMULATED OTHER COMPREHENSIVE

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS): Changes in accumulated other comprehensive income (loss) by component for the years ended December 31, 2015 , 2014 and 2013 were as follows: Cash Flow Hedges Foreign Currency Items Total For the Year Ended December 31, 2015 Beginning balance, net of tax $ 86,783 $ (3,468 ) $ 83,315 Other comprehensive income (loss) before reclassifications: Change in fair value of derivatives 52,630 — 52,630 Foreign currency translations — (2,605 ) (2,605 ) Income tax effect (19,096 ) — (19,096 ) Net of tax 33,534 (2,605 ) 30,929 Amounts reclassified from accumulated other comprehensive income: Operating revenue: oil/natural gas production 149,955 — 149,955 Derivative income, net 1,170 — 1,170 Income tax effect (54,833 ) — (54,833 ) Net of tax 96,292 — 96,292 Other comprehensive loss, net of tax (62,758 ) (2,605 ) (65,363 ) Ending balance, net of tax $ 24,025 $ (6,073 ) $ 17,952 Cash Flow Hedges Foreign Currency Items Total 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/natural 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 Hedges Foreign Currency Items Total 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/natural 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 )

SHARE-BASED COMPENSATION

SHARE-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
SHARE-BASED COMPENSATION	SHARE-BASED COMPENSATION: We currently maintain the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan, as amended from time to time (the “2009 Plan”). 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 (a) “incentive” stock options as defined in Section 422 of the Code, (b) stock options that do not constitute incentive stock options (“non-statutory” stock options), (c) stock appreciation rights in conjunction with an incentive or non-statutory stock option, (d) restricted stock, (e) restricted stock units, (f) dividend equivalents, (g) other stock-based awards, (h) conversion awards, and (i) cash awards, any of which may be further designated as performance awards (collectively referred to as “awards”). See Note 16 - Employee Benefit Plans-Stock Incentive Plans for more information. No stock options have been granted pursuant to the 2009 Plan since its initial effective date on May 28, 2009; however, we have previously granted options under the 2004 Plan that remain outstanding. Stock options previously granted to 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. We have granted restricted stock awards under the 2009 Plan, which awards typically vest over a one -year or 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, 2015 , we incurred $17,917 of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $5,593 was capitalized into oil and gas properties. 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. 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, 2015 , 2014 or 2013 . A summary of stock option activity during the year ended December 31, 2015 is as follows (amounts in table represent actual values except where indicated otherwise): Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Term Aggregate Intrinsic Value (in thousands) Options outstanding, beginning of period 204,974 $ 33.94 Granted — — Exercised — — Forfeited — — Expired (60,500 ) 50.68 Options outstanding, end of period 144,474 26.92 2.1 years $ — Options exercisable, end of period 144,474 26.92 2.1 years — Options unvested, end of period — — — — Exercise prices for stock options outstanding at December 31, 2015 range from $6.97 to $47.75 . A summary of stock option activity during the year ended December 31, 2014 is as follows (amounts in table represent actual values except where indicated otherwise): Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Term Aggregate Intrinsic Value (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 — — — — A summary of stock option activity during the year ended December 31, 2013 is as follows (amounts in table represent actual values except where indicated otherwise): Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Term Aggregate Intrinsic Value (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 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, 2015 , we issued 1,420,475 shares of restricted stock valued at $23,722 . 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 . A summary of the restricted stock activity under the 2009 Plan for the years ended December 31, 2015 , 2014 and 2013 is as follows (amounts in table represent actual values): 2015 2014 2013 Number of Restricted Shares Wgtd. Avg. Fair Value Per Share Number of Restricted Shares Wgtd. Avg. Fair Value Per Share Number of Restricted Shares Wgtd. Avg. Fair Value Per Share Restricted stock outstanding, beginning of period 1,303,106 $ 29.95 1,258,053 $ 23.92 1,108,874 $ 27.56 Issuances 1,420,475 16.70 674,904 36.44 848,498 20.61 Lapse of restrictions (638,582 ) 29.60 (598,796 ) 24.57 (534,041 ) 25.45 Forfeitures (278,442 ) 22.39 (31,055 ) 30.19 (165,278 ) 26.43 Restricted stock outstanding, end of period 1,806,557 $ 20.83 1,303,106 $ 29.95 1,258,053 $ 23.92 As of December 31, 2015 , there was $20,423 of unrecognized compensation cost related to all non-vested share-based compensation arrangements under the 2009 Plan. That cost is being amortized on a straight-line basis over the vesting period and is expected to be recognized over a weighted-average period of 1.7 years . Under U.S. GAAP, if tax deductions exceed book compensation expense, then excess tax benefits are credited to additional paid-in capital to the extent realized. If book compensation expense exceeds tax deductions, the tax deficit results in either a reduction in additional paid-in capital 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 $0 , ($54) and ($884) in 2015 , 2014 and 2013 , respectively. Additionally, during 2015 and 2014 , $1,314 and $609 of tax deficits were charged to income tax expense, respectively.

SHARE REPURCHASE PROGRAM

SHARE REPURCHASE PROGRAM	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
SHARE REPURCHASE PROGRAM	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. Additionally, shares are sometimes withheld from certain employees and nonemployee directors to pay taxes associated with the vesting of restricted stock. These withheld shares are not issued or considered common stock repurchases under our authorized share repurchase program. Through December 31, 2015 , 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, 2015 , 2014 and 2013 .

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	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 2021 . 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 exces s of 12 months at December 31, 2015 were as follows: 2016 $ 2,022 2017 809 2018 612 2019 453 2020 453 2021 113 Payments related to our lease obligations for the years ended December 31, 2015 , 2014 and 2013 were approximately $2,076 , $966 and $597 , respectively. Other Commitments and Contingencies We are contingently liable to surety insurance companies in the amount of $223,441 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 $185,680 to be incurred over the next 3 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 ("OCS") waters, with higher amounts of up to $150,000 in certain limited circumstances where the BOEM believes such a level is justified by the risks posed by the operations, or if the worst case oil-spill discharge volume possible at the facility may exceed the applicable threshold volumes specified under the BOEM’s final rule. In addition, the BOEM has finalized rules that raise OPA's damages liability cap from $75,000 to $133,650 . In September 2015, the BOEM issued its "Draft Guidance" describing revised supplemental bonding procedures the agency plans to use to impose financial assurance obligations for decommissioning activities on the federal OCS. Once the Draft Guidance is finalized, the BOEM will issue these supplemental bonding changes in a revised Notice to Lessees (" NTL") in replacement of an existing NTL on supplemental bonding that was made effective on August 28, 2008. Among other things, the Draft Guidance proposes to eliminate the “waiver” exemption currently allowed by BOEM, whereby certain operators on the OCS projecting a relatively large net worth and meeting certain other criteria have the option of being exempted from posting bonds or other acceptable assurances for such operator’s decommissioning obligations. Currently, qualifying operators may self-insure to meet supplemental bonding requirements, but only so long as the cumulative decommissioning liability amount being self-insured by the operator is no more than 50% of the operator’s net worth. Under the Draft Guidance, this waiver option would be eliminated and operators would only be able to self-insure for an amount that is no more than 10% of their tangible net worth. 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. On August 2, 2013, Kimmeridge Energy Exploration Fund, L.P. (“Kimmeridge”) filed a lawsuit against Stone in the 15t h Judicial District Court in Lafayette Parish, Louisiana seeking damages in the amount of $18,373 plus interest, costs and attorney fees. Kimmeridge alleged that Stone was obligated to pay Kimmeridge (1) $1,119 for brokerage costs incurred pursuant to a letter of understanding and (2) $17,254 pursuant to a letter of intent which, according to Kimeridge's pleadings, required Stone to negotiate in good faith and close an acquisition of mineral interests in the Illinois basin. The court granted summary judgment in favor of Stone, limiting damages on Kimmeridge’s $17,254 claim to $1,000 and reducing Stone's exposure at trial for both claims to $2,119 . During the three months ended June 30, 2015, Stone and Kimmeridge settled both claims for an amount within the previously disclosed range of loss (between $0 and $2,119 ).

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2015
Compensation Related Costs [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS: We have entered into deferred compensation and disability agreements with certain of our current and former officers. The benefits under the deferred compensation agreements vest after certain periods of employment, and at December 31, 2015 , the liability for such vested benefits was approximately $1,125 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 $2,242 , $10,361 , and $15,340 , net of amounts capitalized, for each of the years ended December 31, 2015 , 2014 and 2013 , respectively, related to incentive compensation bonuses to be paid under the revised plan. Stock Incentive Plans We currently maintain the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan, as amended from time to time (the “2009 Plan”). 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 (a) “incentive” stock options as defined in Section 422 of the Code, (b) stock options that do not constitute incentive stock options (“non-statutory” stock options), (c) stock appreciation rights in conjunction with an incentive or non-statutory stock option, (d) restricted stock, (e) restricted stock units, (f) dividend equivalents, (g) other stock-based awards, (h) conversion awards, and (i) cash awards, any of which may be further designated as performance awards (collectively referred to as “awards”). The 2009 Plan eliminated 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 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. At the 2015 Annual Meeting of Stockholders, the stockholders approved the Second Amendment (the “Second Amendment”) to the 2009 Plan and the Third Amendment (the "Third Amendment") to the 2009 Plan. The Second Amendment provides, among other things, for an increase in the number of shares of our common stock reserved for issuance under the 2009 Plan by 1,600,000 shares, effective May 21, 2015, and for an extension of the term of the 2009 Plan to May 21, 2025. The Third Amendment sets forth the material terms of the 2009 Plan (i.e., the eligible employees, business criteria and maximum annual per person compensation limits) for purposes of complying with certain requirements of Section 162(m) of the Internal Revenue Code. The Third Amendment does not change the employees eligible to receive compensation under the 2009 Plan, but does (i) allow Stone to grant cash awards (which may or may not be designated as performance awards) under the 2009 Plan, (ii) impose a fixed share number limit on stock-based awards and a fixed dollar limit on cash awards granted during any calendar year under the 2009 Plan to certain individuals, and (iii) add additional business criteria that may be utilized in setting performance goals under the 2009 Plan. The Third Amendment also became effective as of May 21, 2015. On December 17, 2015, Stone amended and restated the 2009 Plan to incorporate all prior amendments to the 2009 Plan (including the Second Amendment and the Third Amendment) and certain other non-material changes to the 2009 Plan. At December 31, 2015 , we had approximately 2,082,434 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 direction 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, 2015 , 2014 and 2013 , Stone contributed $1,553 , $1,989 and $1,793 , 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. In addition, the Board may elect to make discretionary profit sharing contributions to the plan. To date there have been no matching or discretionary profit sharing 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, 2015 and 2014 , plan assets of $8,499 and $8,425 , 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 “specified 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 6 months ; (iii) a pro-rated portion of the employee’s targeted bonus for the year, and (iv) reasonable outplacement services consistent with current HR practices. 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) cash-out of 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 OIL

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED	SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS – UNAUDITED: At December 31, 2015 , 2014 and 2013 , our oil and gas properties were located in the United States and Canada. 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, 2015 2014 2013 Oil and gas properties – United States, proved and unevaluated: Balance, beginning of year $ 9,348,054 $ 8,517,873 $ 7,692,261 Costs incurred during the year (capitalized): Acquisition costs, net of sales of unevaluated properties (14,158 ) 44,634 70,903 Exploratory costs 104,169 270,850 297,113 Development costs (1) 266,982 438,334 378,242 Salaries, general and administrative costs 27,984 33,975 32,815 Interest 41,339 45,722 46,860 Less: overhead reimbursements (913 ) (3,334 ) (321 ) Total costs incurred during the year, net of divestitures 425,403 830,181 825,612 Balance, end of year $ 9,773,457 $ 9,348,054 $ 8,517,873 Accumulated DD&A: Balance, beginning of year $ (6,970,631 ) $ (5,908,760 ) $ (5,510,166 ) Provision for DD&A (277,088 ) (335,987 ) (346,827 ) Write-down of oil and gas properties (1,314,817 ) (351,192 ) — Sale of proved properties 1,064 (374,692 ) (51,767 ) Balance, end of year $ (8,561,472 ) $ (6,970,631 ) $ (5,908,760 ) Net capitalized costs – United States, proved and unevaluated $ 1,211,985 $ 2,377,423 $ 2,609,113 DD&A per Mcfe $ 3.19 $ 3.59 $ 3.43 (1) Includes capitalized asset retirement costs of ($43,901), ($20,305) and $54,737, respectively. Costs incurred during the year (expensed): Lease operating expenses $ 100,139 $ 176,495 $ 201,153 Transportation, processing and gathering expenses 58,847 64,951 42,172 Production taxes 6,877 12,151 15,029 Accretion expense 25,988 28,411 33,575 Expensed costs – United States $ 191,851 $ 282,008 $ 291,929 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 March 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $491,412 based on 12-month average prices, net of applicable differentials, of $78.99 per Bbl of oil, $2.96 per Mcf of natural gas and $28.82 per Bbl of natural gas liquids ("NGLs"). At June 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $179,125 based on 12-month average prices, net of applicable differentials, of $68.68 per Bbl of oil, $2.47 per Mcf of natural gas and $29.13 per Bbl of NGLs. At September 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $295,679 based on 12-month average prices, net of applicable differentials, of $57.76 per Bbl of oil, $2.44 per Mcf of natural gas and $23.04 per Bbl of NGLs. At December 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $348,601 based on 12-month average prices, net of applicable differentials, of $51.16 per Bbl of oil, $2.19 per Mcf of natural gas and $16.40 per Bbl of NGLs. The March 31, June 30, September 30 and December 31, 2015 write-downs were decreased by $28,687 , $47,784 , $42,652 and $24,797 , respectively, as a result of hedges. 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 12-month average prices, net of applicable differentials, of $94.94 per Bbl of oil, $4.19 per Mcf of natural gas and $41.33 per Bbl of NGLs. 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 12-month average prices, net of applicable differentials, of $89.46 per Bbl of oil, $3.68 per Mcf of natural gas and $36.79 per Bbl of NGLs. 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: 2015 2014 2013 Net costs incurred (evaluated) during year: Acquisition costs $ (115,767 ) $ (42,384 ) $ 30,271 Exploration costs (16,315 ) (186,308 ) 188,830 Capitalized interest 41,339 45,722 46,860 $ (90,743 ) $ (182,970 ) $ 265,961 During 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Upon a more complete evaluation of this project and in response to the significant decline in commodity prices over the last year, we have discontinued our business development effort in Canada. Accordingly, we recognized a full impairment of our Canadian oil and gas properties in 2015. The following table discloses certain financial data relative to our oil and gas activities located in Canada: Year Ended December 31, 2015 2014 2013 Oil and gas properties – Canada: Balance, beginning of year $ 36,579 $ 10,583 $ — Costs incurred during the year (capitalized): Acquisition costs (2,862 ) 6,956 8,764 Exploratory costs 8,767 19,040 1,819 Total costs incurred during the year 5,905 25,996 10,583 Balance, end of year (fully evaluated at December 31, 2015 and unevaluated at December 31, 2014 and 2013) $ 42,484 $ 36,579 $ 10,583 Accumulated DD&A: Balance, beginning of year $ — $ — $ — Foreign currency translation adjustment 5,146 $ — — Write-down of oil and gas properties (47,630 ) $ — — Balance, end of year $ (42,484 ) $ — $ — Net capitalized costs – Canada $ — $ 36,579 $ 10,583 The following table discloses financial data associated with unevaluated costs (United States) at December 31, 2015 : Balance as of Net Costs Incurred During the Year Ended December 31, December 31, 2015 2015 2014 2013 2012 and prior Acquisition costs $ 173,902 $ (33,623 ) $ (5,118 ) $ 40,535 $ 172,108 Exploration costs 148,518 41,936 42,899 42,186 21,497 Capitalized interest 117,623 20,257 23,538 24,162 49,666 Total unevaluated costs $ 440,043 $ 28,570 $ 61,319 $ 106,883 $ 243,271 Approximately 95 specifically identified drilling projects are included in unevaluated costs at December 31, 2015 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, 2015 , 2014 and 2013 totaled $41,339 , $45,722 and $46,860 , respectively. Proved Oil and Natural Gas Quantities Our estimated net proved oil and natural gas reserves at December 31, 2015 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 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, 2015 , 2014 and 2013 are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a historical 12-month average pricing assumption. Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Oil, Natural Gas and NGLs (MMcfe) 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 Revisions of previous estimates (6,818 ) (20,777 ) (362,102 ) (527,675 ) Extensions, discoveries and other additions 862 11 1,499 6,738 Purchase of producing properties 685 1,808 26,136 41,095 Sale of reserves (859 ) — (1,061 ) (6,213 ) Production (5,991 ) (2,401 ) (36,457 ) (86,809 ) Estimated proved reserves as of December 31, 2015 30,276 6,458 121,858 342,260 Estimated proved developed reserves: 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 as of December 31, 2015 21,734 4,784 90,262 249,366 Estimated proved undeveloped reserves: 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 as of December 31, 2015 8,542 1,674 31,596 92,894 The following narrative provides the reasons for the significant changes in the quantities of our estimated proved reserves by year. Year Ended December 31, 2015. Revisions of previous estimates were primarily the result of the significant decline in commodity prices resulting in uneconomic reserves ( 570 Bcfe) primarily in Appalachia, slightly offset by positive well performance ( 42 Bcfe). Purchase of producing properties related to increases in our net revenue and working interests in multiple wells in the Mary field in Appalachia resulting from the finalization of participation elections made by partners and potential partners in certain units. 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 related 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). 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, 2015 . 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 2015 average historical 12-month oil and natural gas prices, net of applicable differentials, were $51.16 per Bbl of oil, $16.40 per Bbl of NGLs and $2.19 per Mcf of natural gas. The 2014 average 12-month oil and natural 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 natural gas. The 2013 average 12-month oil and natural 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 natural 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, 2015 2014 2013 Future cash inflows $ 1,921,329 $ 6,635,751 $ 7,040,928 Future production costs (651,396 ) (2,413,004 ) (2,062,657 ) Future development costs (679,355 ) (1,511,687 ) (1,431,101 ) Future income taxes — (609,516 ) (884,637 ) Future net cash flows 590,578 2,101,544 2,662,533 10% annual discount 13,259 (682,752 ) (977,531 ) Standardized measure of discounted future net cash flows $ 603,837 $ 1,418,792 $ 1,685,002 Changes in Standardized Measure Year Ended December 31, 2015 2014 2013 Standardized measure at beginning of year $ 1,418,792 $ 1,685,002 $ 1,513,859 Sales and transfers of oil, natural gas and NGLs produced, net of production costs (340,477 ) (486,232 ) (708,017 ) Changes in price, net of future production costs (237,747 ) (864,118 ) 229,425 Extensions and discoveries, net of future production and development costs 1,573 549,649 155,592 Changes in estimated future development costs, net of development costs incurred during the period 731,115 203,026 28,684 Revisions of quantity estimates (1,458,652 ) (27,495 ) 281,558 Accretion of discount 174,456 222,009 202,087 Net change in income taxes 325,768 209,323 (28,084 ) Purchases of reserves in-place 3,493 — — Sales of reserves in-place — (152,787 ) 15,531 Changes in production rates due to timing and other (14,484 ) 80,415 (5,633 ) Net increase (decrease) in standardized measure (814,955 ) (266,210 ) 171,143 Standardized measure at end of year $ 603,837 $ 1,418,792 $ 1,685,002

SUMMARIZED QUARTERLY FINANCIAL

SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED	SUMMARIZED QUARTERLY FINANCIAL INFORMATION – UNAUDITED: The results of operations by quarter are as follows: 2015 Quarter Ended March 31 June 30 September 30 December 31 Operating revenue $ 153,498 $ 149,525 $ 132,196 $ 110,499 Loss from operations (497,194 ) (228,161 ) (297,209 ) (342,759 ) Net loss (327,388 ) (152,906 ) (291,965 ) (318,656 ) Basic loss per share $ (5.93 ) $ (2.77 ) $ (5.28 ) $ (5.76 ) Diluted loss per share $ (5.93 ) $ (2.77 ) $ (5.28 ) $ (5.76 ) Write-down of oil and gas properties before income tax effect $ 491,412 $ 224,294 $ 295,679 $ 351,062 Write-down of oil and gas properties net of income tax effect 314,504 143,548 189,235 224,680 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 ) (286,147 ) Net income (loss) 25,943 4,444 (29,415 ) (190,515 ) 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 ) Write-down of oil and gas properties before income tax effect $ — $ — $ 47,130 $ 304,062 Write-down of oil and gas properties net of income tax effect — — 30,163 194,600

RECENTLY ISSUED ACCOUNTING STAN

RECENTLY ISSUED ACCOUNTING STANDARDS	12 Months Ended
	Dec. 31, 2015
Accounting Changes and Error Corrections [Abstract]
RECENTLY ISSUED ACCOUNTING STANDARDS	RECENTLY ISSUED ACCOUNTING STANDARDS: In May 2014, the FASB issued 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 standard may be applied retrospectively or using a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. In August 2015, the FASB issued ASU 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for interim and annual periods beginning on or after December 31, 2017. 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. In August 2014, the FASB issued ASU 2014-15, " Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40)" . The guidance will require management to evaluate whether there are conditions and events that raise substantial doubt about the company's ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Additionally, management will be required to provide certain footnote disclosures if it concludes that substantial doubt exists or when it plans to alleviate substantial doubt about the company's ability to continue as a going concern. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter.

GUARANTOR FINANCIAL STATEMENTS

GUARANTOR FINANCIAL STATEMENTS	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
GUARANTOR FINANCIAL STATEMENTS	GUARANTOR FINANCIAL STATEMENTS: Our Guarantor Subsidiaries, including Stone Offshore, SEO A LLC and SEO B LLC, are unconditional guarantors 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, 2015 and 2014 and for the years ended December 31, 2015 , 2014 and 2013 on an issuer (parent company), Guarantor Subsidiaries, Non-Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities. CCONDENSED CONSOLIDATING BALANCE SHEET DECEMBER 31, 2015 (In thousands) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 9,681 $ 2 $ 1,076 $ — $ 10,759 Accounts receivable 10,597 39,190 — (1,756 ) 48,031 Fair value of derivative contracts — 38,576 — — 38,576 Current income tax receivable 46,174 — — — 46,174 Inventory 535 — — — 535 Other current assets 6,313 — 33 — 6,346 Total current assets 73,300 77,768 1,109 (1,756 ) 150,421 Oil and gas properties, full cost method: Proved 1,875,152 7,458,262 42,484 — 9,375,898 Less: accumulated DD&A (1,874,622 ) (6,686,849 ) (42,484 ) — (8,603,955 ) Net proved oil and gas properties 530 771,413 — — 771,943 Unevaluated 253,308 186,735 — — 440,043 Other property and equipment, net 29,289 — — — 29,289 Other assets, net 16,612 826 1,035 — 18,473 Investment in subsidiary 745,033 — 1,088 (746,121 ) — Total assets $ 1,118,072 $ 1,036,742 $ 3,232 $ (747,877 ) $ 1,410,169 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable to vendors $ 16,063 $ 67,901 $ — $ (1,757 ) $ 82,207 Undistributed oil and gas proceeds 5,216 776 — — 5,992 Accrued interest 9,022 — — — 9,022 Asset retirement obligations — 20,400 891 — 21,291 Other current liabilities 40,161 551 — — 40,712 Total current liabilities 70,462 89,628 891 (1,757 ) 159,224 Long-term debt 1,060,955 — — — 1,060,955 Asset retirement obligations 1,240 203,335 — — 204,575 Other long-term liabilities 25,204 — — — 25,204 Total liabilities 1,157,861 292,963 891 (1,757 ) 1,449,958 Commitments and contingencies Stockholders’ equity: Common stock 553 — — — 553 Treasury stock (860 ) — — — (860 ) Additional paid-in capital 1,648,189 1,344,577 109,795 (1,454,372 ) 1,648,189 Accumulated deficit (1,705,623 ) (624,824 ) (95,306 ) 720,130 (1,705,623 ) Accumulated other comprehensive income (loss) 17,952 24,026 (12,148 ) (11,878 ) 17,952 Total stockholders’ equity (39,789 ) 743,779 2,341 (746,120 ) (39,789 ) Total liabilities and stockholders’ equity $ 1,118,072 $ 1,036,742 $ 3,232 $ (747,877 ) $ 1,410,169 CONDENSED CONSOLIDATING BALANCE SHEET DECEMBER 31, 2014 (In thousands) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated 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 12,103 1,360 5,007 — 18,470 Investment in subsidiary 1,050,546 — 41,638 (1,092,184 ) — Total assets $ 2,448,634 $ 1,574,087 $ 83,415 $ (1,096,279 ) $ 3,009,857 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 1,032,281 — — — 1,032,281 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 1,347,031 565,318 — (4,095 ) 1,908,254 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 $ 2,448,634 $ 1,574,087 $ 83,415 $ (1,096,279 ) $ 3,009,857 * Deferred income taxes have been allocated to our Guarantor Subsidiaries where related oil and gas properties reside. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2015 (In thousands) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated Operating revenue: Oil production $ 12,804 $ 403,693 $ — $ — $ 416,497 Natural gas production 41,646 41,863 — — 83,509 Natural gas liquids production 22,375 9,947 — — 32,322 Other operational income 4,369 — — — 4,369 Derivative income, net — 7,952 — — 7,952 Total operating revenue 81,194 463,455 — — 544,649 Operating expenses: Lease operating expenses 16,264 83,872 3 — 100,139 Transportation, processing, and gathering expenses 50,247 8,600 — — 58,847 Production taxes 5,631 1,246 — — 6,877 Depreciation, depletion, amortization 123,724 157,964 — — 281,688 Write-down of oil and gas properties 785,463 529,354 47,630 — 1,362,447 Accretion expense 365 25,623 — — 25,988 Salaries, general and administrative expenses 69,147 201 36 — 69,384 Incentive compensation expense 2,242 — — — 2,242 Other operational expenses 2,360 — — — 2,360 Total operating expenses 1,055,443 806,860 47,669 — 1,909,972 Loss from operations (974,249 ) (343,405 ) (47,669 ) — (1,365,323 ) Other (income) expenses: Interest expense 43,907 21 — — 43,928 Interest income (327 ) (246 ) (7 ) — (580 ) Other income (617 ) (1,163 ) (3 ) — (1,783 ) Other expense 434 — — — 434 Loss from investment in subsidiaries 231,783 — 47,659 (279,442 ) — Total other (income) expenses 275,180 (1,388 ) 47,649 (279,442 ) 41,999 Loss before taxes (1,249,429 ) (342,017 ) (95,318 ) 279,442 (1,407,322 ) Provision (benefit) for income taxes: Current (44,096 ) — — — (44,096 ) Deferred (114,418 ) (157,893 ) — — (272,311 ) Total income taxes (158,514 ) (157,893 ) — — (316,407 ) Net loss $ (1,090,915 ) $ (184,124 ) $ (95,318 ) $ 279,442 $ (1,090,915 ) Comprehensive loss $ (1,156,278 ) $ (184,124 ) $ (95,318 ) $ 279,442 $ (1,156,278 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2014 (In thousands) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated 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 expenses 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 Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated 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 expenses 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 CASH FLOWS YEAR ENDED DECEMBER 31, 2015 (In thousands) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated Cash flows from operating activities: Net loss $ (1,090,915 ) $ (184,124 ) $ (95,318 ) $ 279,442 $ (1,090,915 ) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization 123,724 157,964 — — 281,688 Write-down of oil and gas properties 785,463 529,354 47,630 — 1,362,447 Accretion expense 365 25,623 — — 25,988 Deferred income tax benefit (114,418 ) (157,893 ) — — (272,311 ) Settlement of asset retirement obligations (15 ) (72,367 ) — — (72,382 ) Non-cash stock compensation expense 12,324 — — — 12,324 Excess tax benefits (1,586 ) — — — (1,586 ) Non-cash derivative expense — 16,440 — — 16,440 Non-cash interest expense 17,788 — — — 17,788 Change in current income taxes (37,377 ) — — — (37,377 ) Non-cash loss from investment in subsidiaries 231,783 — 47,659 (279,442 ) — Change in intercompany receivables/payables 9,744 (19,486 ) 9,742 — — Decrease in accounts receivable 34,609 9,084 31 — 43,724 (Increase) decrease in other current assets 1,799 — (32 ) — 1,767 (Increase) decrease in inventory (1,394 ) 2,698 — — 1,304 Decrease in accounts payable (7,471 ) (7,111 ) — — (14,582 ) Increase (decrease) in other current liabilities (25,989 ) 53 — — (25,936 ) Other 256 (1,163 ) — — (907 ) Net cash (used in) provided by operating activities (61,310 ) 299,072 9,712 — 247,474 Cash flows from investing activities: Investment in oil and gas properties (188,154 ) (323,359 ) (10,534 ) — (522,047 ) Proceeds from sale of oil and gas properties, net of expenses — 22,839 — — 22,839 Investment in fixed and other assets (1,549 ) — — — (1,549 ) Change in restricted funds 177,647 — 1,820 — 179,467 Investment in subsidiaries — — (9,714 ) 9,714 — Net cash used in investing activities (12,056 ) (300,520 ) (18,428 ) 9,714 (321,290 ) Cash flows from financing activities: Proceeds from bank borrowings 5,000 — — — 5,000 Repayments of bank borrowings (5,000 ) — — — (5,000 ) Deferred financing costs (68 ) — — — (68 ) Proceeds from building loan 11,770 — — — 11,770 Equity proceeds from parent — — 9,714 (9,714 ) — Excess tax benefits 1,586 — — — 1,586 Net payments for share-based compensation (3,127 ) — — — (3,127 ) Net cash provided by financing activities 10,161 — 9,714 (9,714 ) 10,161 Effect of exchange rate changes on cash — — (74 ) — (74 ) Net change in cash and cash equivalents (63,205 ) (1,448 ) 924 — (63,729 ) Cash and cash equivalents, beginning of period 72,886 1,450 152 — 74,488 Cash and cash equivalents, end of period $ 9,681 $ 2 $ 1,076 $ — $ 10,759 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2014 (In thousands) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated 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 Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated 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 Change in current income taxes 2,767 — — — 2,767 Non-cash (income) loss from investment in subsidiaries (214,983 ) — 26 214,957 — 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

ORGANIZATION AND SUMMARY OF S28

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation: The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Energy Offshore, L.L.C. (“Stone Offshore”), Stone Energy Holding, L.L.C., Stone Energy Canada, U.L.C., SEO A LLC and SEO B LLC. 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, 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, 2015 and 2014 , 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.
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 entitlements 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 2013 , 2014 and 2015 , 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. 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 natural gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments are recorded in our balance sheet at fair value and subsequent 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.
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.
Recently Issued Accounting Standards	RECENTLY ISSUED ACCOUNTING STANDARDS: In May 2014, the FASB issued 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 standard may be applied retrospectively or using a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. In August 2015, the FASB issued ASU 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for interim and annual periods beginning on or after December 31, 2017. 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. In August 2014, the FASB issued ASU 2014-15, " Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40)" . The guidance will require management to evaluate whether there are conditions and events that raise substantial doubt about the company's ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Additionally, management will be required to provide certain footnote disclosures if it concludes that substantial doubt exists or when it plans to alleviate substantial doubt about the company's ability to continue as a going concern. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter.

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 Income (numerator): Basic: Net income (loss) $ (1,090,915 ) $ (189,543 ) $ 117,634 Net income attributable to participating securities — — (2,817 ) Net income (loss) attributable to common stock - basic $ (1,090,915 ) $ (189,543 ) $ 114,817 Diluted: Net income (loss) $ (1,090,915 ) $ (189,543 ) $ 117,634 Net income attributable to participating securities — — (2,815 ) Net income (loss) attributable to common stock - diluted $ (1,090,915 ) $ (189,543 ) $ 114,819 Weighted average shares (denominator): Weighted average shares - basic 55,250 52,721 48,693 Dilutive effect of stock options — — 42 Weighted average shares - diluted 55,250 52,721 48,735 Basic earnings (loss) per share $ (19.75 ) $ (3.60 ) $ 2.36 Diluted earnings (loss) per share $ (19.75 ) $ (3.60 ) $ 2.36

ACCOUNTS RECEIVABLE (Tables)

ACCOUNTS RECEIVABLE (Tables)	12 Months Ended
	Dec. 31, 2015
Receivables [Abstract]
Components of Accounts Receivable	Our accounts receivable are comprised of the following amounts: As of December 31, 2015 2014 Other co-venturers $ 4,639 $ 16,291 Trade 26,224 60,263 Unbilled accounts receivable 1,736 33,052 Other 15,432 10,753 Total accounts receivable $ 48,031 $ 120,359

CONCENTRATIONS (Tables)

CONCENTRATIONS (Tables)	12 Months Ended
	Dec. 31, 2015
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 natural gas revenue during the indicated periods: Year Ended December 31, 2015 2014 2013 Phillips 66 Company 53 % 31 % 35 % Shell Trading (US) Company 13 % 32 % 33 %

DERIVATIVE INSTRUMENTS AND HE32

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Hedging Positions	The following tables illustrate our derivative positions for calendar year 2016 as of February 22, 2016 : Fixed-Price Swaps (NYMEX) Natural Gas Oil Daily Volume (MMBtus/d) Swap Price ($/MMBtu) Daily Volume (Bbls/d) Swap Price ($/Bbl) 2016 10,000 4.110 1,000 49.75 2016 10,000 4.120 1,000 52.78 2016 1,000 90.00 Costless Collar (NYMEX) Oil Daily Volume (Bbls/d) Floor Price ($) Ceiling Price ($) 2016 1,000 45.00 54.75
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, 2015 and 2014 : Fair Value of Derivatives Qualifying as Hedging Instruments at December 31, 2015 Asset Derivatives Liability Derivatives Description Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity contracts Current assets: Fair value of derivative contracts $ 38,576 Current liabilities: Fair value of derivative contracts — Long-term assets: Fair value of derivative contracts — Long-term liabilities: Fair value of derivative contracts — $ 38,576 $ — 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 $ —
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, 2015 , 2014 and 2013 : Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations for the Years Ended December 31, 2015, 2014, and 2013 Derivatives in Cash Flow Hedging Relationships Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion) (a) Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) Location Location 2015 2015 2015 Commodity contracts $ 52,630 Operating revenue - oil/natural gas production $ 149,955 Derivative income (expense), net $ 2,713 Total $ 52,630 $ 149,955 $ 2,713 2014 2014 2014 Commodity contracts $ 136,097 Operating revenue - oil/natural gas production $ 526 Derivative income (expense), net $ 5,721 Total $ 136,097 $ 526 $ 5,721 2013 2013 2013 Commodity contracts $ (26,945 ) Operating revenue - oil/natural gas production $ 20,289 Derivative income (expense), net $ (2,090 ) Total $ (26,945 ) $ 20,289 $ (2,090 ) (a) For the year ended December 31, 2015 , effective hedging contracts increased oil revenue by $135,617 and increased natural gas revenue by $14,338 . For the year ended December 31, 2014 , effective hedging contracts increased oil revenue by $7,929 and (decreased) natural gas revenue by $7,403 . For the year ended December 31, 2013 , effective hedging contracts increased oil revenue by $3,520 and increased natural gas revenue by $16,769 .
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, 2015 and 2014 : Fair Value of Derivatives Not Qualifying as Hedging Instruments Description Balance Sheet Location December 31, 2015 December 31, 2014 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	The following table discloses the before tax effect of our derivatives not qualifying as hedging instruments on the statement of operations for the years ended December 31, 2015 and 2014 . All of our derivatives for the year ended December 31, 2013 qualified as hedging instruments. Gain (Loss) Recognized in Derivative Income (Expense) Year Ended Description December 31, 2015 December 31, 2014 Commodity contracts: Cash settlements $ 17,385 $ 1,484 Change in fair value (12,146 ) 12,146 Total gain on non-qualifying derivatives $ 5,239 $ 13,630

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of Assets and Liabilities Measured at Fair Value Recurring Basis	The following tables present our assets that are measured at fair value on a recurring basis at December 31, 2015 and 2014: Fair Value Measurements at December 31, 2015 Assets Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Marketable securities (Other assets) $ 8,499 $ 8,499 $ — $ — Derivative contracts 38,576 — 36,603 1,973 Total $ 47,075 $ 8,499 $ 36,603 $ 1,973 Fair Value Measurements at December 31, 2014 Assets Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (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, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	The table below presents a reconciliation for assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the year ended December 31, 2015 . Hedging Contracts, net Balance as of January 1, 2015 $ — Total gains/(losses) (realized or unrealized): Included in earnings 63 Included in other comprehensive income 1,910 Purchases, sales, issuances and settlements — Transfers in and out of Level 3 — Balance as of December 31, 2015 $ 1,973 The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at December 31, 2015 $ 63

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	The change in our asset retirement obligations during the years ended December 31, 2015 , 2014 and 2013 is set forth below: Year Ended December 31, 2015 2014 2013 Asset retirement obligations as of the beginning of the year, including current portion $ 316,409 $ 502,513 $ 488,302 Liabilities incurred 15,933 28,606 19,043 Liabilities settled (72,713 ) (55,839 ) (79,695 ) Divestment of properties (248 ) (137,801 ) (9,245 ) Accretion expense 25,988 28,411 33,575 Revision of estimates (59,503 ) (49,481 ) 50,533 Asset retirement obligations as of the end of the year, including current portion $ 225,866 $ 316,409 $ 502,513

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Analysis of Deferred Taxes	An analysis of our deferred taxes follows: As of December 31, 2015 2014 Tax effect of temporary differences: Net operating loss carryforwards $ 31,624 $ 99,615 Oil and gas properties – full cost 76,766 (476,367 ) Asset retirement obligations 79,618 113,907 Stock compensation 5,199 5,603 Hedges (13,598 ) (54,439 ) Accrued incentive compensation 1,234 6,185 Other (722 ) (966 ) Total deferred tax assets (liabilities) 180,121 (306,462 ) Valuation allowance (180,121 ) — Net deferred tax liabilities $ — $ (306,462 )
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, 2015 2014 2013 Income tax expense computed at the statutory federal income tax rate 35.0% 35.0% 35.0% State taxes 0.6 1.0 1.0 Change in valuation allowance (12.8) — — IRC Sec. 162(m) limitation (0.1) (0.5) 0.8 Tax deficits on stock compensation (0.1) (0.2) — Other (0.1) (0.3) 0.1 Effective income tax rate 22.5% 35.0% 36.9%
Summary of Income Tax Contingencies	A reconciliation of the total amounts of unrecognized tax benefits follows: Total unrecognized tax benefits as of December 31, 2014 $ — Increases (decreases) in unrecognized tax benefits as a result of: Tax positions taken during a prior period 491 Tax positions taken during the current period — Settlements with taxing authorities — Lapse of applicable statute of limitations — Total unrecognized tax benefits as of December 31, 2015 $ 491

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-term debt consisted of the following at: December 31, 2015 2014 1 3 ⁄ 4 % Senior Convertible Notes due 2017 $ 279,244 $ 262,791 7 1 ⁄ 2 % Senior Notes due 2022 770,009 769,490 Revolving credit facility — — 4.20% Building Loan 11,702 — Total long-term debt $ 1,060,955 $ 1,032,281

ACCUMULATED OTHER COMPREHENSI37

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 , 2014 and 2013 were as follows: Cash Flow Hedges Foreign Currency Items Total For the Year Ended December 31, 2015 Beginning balance, net of tax $ 86,783 $ (3,468 ) $ 83,315 Other comprehensive income (loss) before reclassifications: Change in fair value of derivatives 52,630 — 52,630 Foreign currency translations — (2,605 ) (2,605 ) Income tax effect (19,096 ) — (19,096 ) Net of tax 33,534 (2,605 ) 30,929 Amounts reclassified from accumulated other comprehensive income: Operating revenue: oil/natural gas production 149,955 — 149,955 Derivative income, net 1,170 — 1,170 Income tax effect (54,833 ) — (54,833 ) Net of tax 96,292 — 96,292 Other comprehensive loss, net of tax (62,758 ) (2,605 ) (65,363 ) Ending balance, net of tax $ 24,025 $ (6,073 ) $ 17,952 Cash Flow Hedges Foreign Currency Items Total 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/natural 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 Hedges Foreign Currency Items Total 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/natural 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 )

SHARE-BASED COMPENSATION (Table

SHARE-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Stock Option Activity under Plan	A summary of stock option activity during the year ended December 31, 2015 is as follows (amounts in table represent actual values except where indicated otherwise): Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Term Aggregate Intrinsic Value (in thousands) Options outstanding, beginning of period 204,974 $ 33.94 Granted — — Exercised — — Forfeited — — Expired (60,500 ) 50.68 Options outstanding, end of period 144,474 26.92 2.1 years $ — Options exercisable, end of period 144,474 26.92 2.1 years — Options unvested, end of period — — — — Exercise prices for stock options outstanding at December 31, 2015 range from $6.97 to $47.75 . A summary of stock option activity during the year ended December 31, 2014 is as follows (amounts in table represent actual values except where indicated otherwise): Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Term Aggregate Intrinsic Value (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 — — — — A summary of stock option activity during the year ended December 31, 2013 is as follows (amounts in table represent actual values except where indicated otherwise): Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Term Aggregate Intrinsic Value (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
Summary of Restricted Stock Activity Under Plan	A summary of the restricted stock activity under the 2009 Plan for the years ended December 31, 2015 , 2014 and 2013 is as follows (amounts in table represent actual values): 2015 2014 2013 Number of Restricted Shares Wgtd. Avg. Fair Value Per Share Number of Restricted Shares Wgtd. Avg. Fair Value Per Share Number of Restricted Shares Wgtd. Avg. Fair Value Per Share Restricted stock outstanding, beginning of period 1,303,106 $ 29.95 1,258,053 $ 23.92 1,108,874 $ 27.56 Issuances 1,420,475 16.70 674,904 36.44 848,498 20.61 Lapse of restrictions (638,582 ) 29.60 (598,796 ) 24.57 (534,041 ) 25.45 Forfeitures (278,442 ) 22.39 (31,055 ) 30.19 (165,278 ) 26.43 Restricted stock outstanding, end of period 1,806,557 $ 20.83 1,303,106 $ 29.95 1,258,053 $ 23.92

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2015
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 exces s of 12 months at December 31, 2015 were as follows: 2016 $ 2,022 2017 809 2018 612 2019 453 2020 453 2021 113

SUPPLEMENTAL INFORMATION ON O40

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 2013 Net costs incurred (evaluated) during year: Acquisition costs $ (115,767 ) $ (42,384 ) $ 30,271 Exploration costs (16,315 ) (186,308 ) 188,830 Capitalized interest 41,339 45,722 46,860 $ (90,743 ) $ (182,970 ) $ 265,961
Financial Data Associated with Unevaluated Costs	The following table discloses financial data associated with unevaluated costs (United States) at December 31, 2015 : Balance as of Net Costs Incurred During the Year Ended December 31, December 31, 2015 2015 2014 2013 2012 and prior Acquisition costs $ 173,902 $ (33,623 ) $ (5,118 ) $ 40,535 $ 172,108 Exploration costs 148,518 41,936 42,899 42,186 21,497 Capitalized interest 117,623 20,257 23,538 24,162 49,666 Total unevaluated costs $ 440,043 $ 28,570 $ 61,319 $ 106,883 $ 243,271
Summary of Estimated Proved Oil and Natural Gas Reserve	The following table sets forth an analysis of the estimated quantities of net proved oil (including condensate), natural gas and 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, 2015 , 2014 and 2013 are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a historical 12-month average pricing assumption. Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Oil, Natural Gas and NGLs (MMcfe) 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 Revisions of previous estimates (6,818 ) (20,777 ) (362,102 ) (527,675 ) Extensions, discoveries and other additions 862 11 1,499 6,738 Purchase of producing properties 685 1,808 26,136 41,095 Sale of reserves (859 ) — (1,061 ) (6,213 ) Production (5,991 ) (2,401 ) (36,457 ) (86,809 ) Estimated proved reserves as of December 31, 2015 30,276 6,458 121,858 342,260 Estimated proved developed reserves: 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 as of December 31, 2015 21,734 4,784 90,262 249,366 Estimated proved undeveloped reserves: 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 as of December 31, 2015 8,542 1,674 31,596 92,894
Summary of Standardized Measure of Discounted Future Net Cash Flows	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, 2015 . 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 2015 average historical 12-month oil and natural gas prices, net of applicable differentials, were $51.16 per Bbl of oil, $16.40 per Bbl of NGLs and $2.19 per Mcf of natural gas. The 2014 average 12-month oil and natural 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 natural gas. The 2013 average 12-month oil and natural 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 natural 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, 2015 2014 2013 Future cash inflows $ 1,921,329 $ 6,635,751 $ 7,040,928 Future production costs (651,396 ) (2,413,004 ) (2,062,657 ) Future development costs (679,355 ) (1,511,687 ) (1,431,101 ) Future income taxes — (609,516 ) (884,637 ) Future net cash flows 590,578 2,101,544 2,662,533 10% annual discount 13,259 (682,752 ) (977,531 ) Standardized measure of discounted future net cash flows $ 603,837 $ 1,418,792 $ 1,685,002 Changes in Standardized Measure Year Ended December 31, 2015 2014 2013 Standardized measure at beginning of year $ 1,418,792 $ 1,685,002 $ 1,513,859 Sales and transfers of oil, natural gas and NGLs produced, net of production costs (340,477 ) (486,232 ) (708,017 ) Changes in price, net of future production costs (237,747 ) (864,118 ) 229,425 Extensions and discoveries, net of future production and development costs 1,573 549,649 155,592 Changes in estimated future development costs, net of development costs incurred during the period 731,115 203,026 28,684 Revisions of quantity estimates (1,458,652 ) (27,495 ) 281,558 Accretion of discount 174,456 222,009 202,087 Net change in income taxes 325,768 209,323 (28,084 ) Purchases of reserves in-place 3,493 — — Sales of reserves in-place — (152,787 ) 15,531 Changes in production rates due to timing and other (14,484 ) 80,415 (5,633 ) Net increase (decrease) in standardized measure (814,955 ) (266,210 ) 171,143 Standardized measure at end of year $ 603,837 $ 1,418,792 $ 1,685,002
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, 2015 2014 2013 Oil and gas properties – United States, proved and unevaluated: Balance, beginning of year $ 9,348,054 $ 8,517,873 $ 7,692,261 Costs incurred during the year (capitalized): Acquisition costs, net of sales of unevaluated properties (14,158 ) 44,634 70,903 Exploratory costs 104,169 270,850 297,113 Development costs (1) 266,982 438,334 378,242 Salaries, general and administrative costs 27,984 33,975 32,815 Interest 41,339 45,722 46,860 Less: overhead reimbursements (913 ) (3,334 ) (321 ) Total costs incurred during the year, net of divestitures 425,403 830,181 825,612 Balance, end of year $ 9,773,457 $ 9,348,054 $ 8,517,873 Accumulated DD&A: Balance, beginning of year $ (6,970,631 ) $ (5,908,760 ) $ (5,510,166 ) Provision for DD&A (277,088 ) (335,987 ) (346,827 ) Write-down of oil and gas properties (1,314,817 ) (351,192 ) — Sale of proved properties 1,064 (374,692 ) (51,767 ) Balance, end of year $ (8,561,472 ) $ (6,970,631 ) $ (5,908,760 ) Net capitalized costs – United States, proved and unevaluated $ 1,211,985 $ 2,377,423 $ 2,609,113 DD&A per Mcfe $ 3.19 $ 3.59 $ 3.43 (1) Includes capitalized asset retirement costs of ($43,901), ($20,305) and $54,737, respectively. Costs incurred during the year (expensed): Lease operating expenses $ 100,139 $ 176,495 $ 201,153 Transportation, processing and gathering expenses 58,847 64,951 42,172 Production taxes 6,877 12,151 15,029 Accretion expense 25,988 28,411 33,575 Expensed costs – United States $ 191,851 $ 282,008 $ 291,929
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, 2015 2014 2013 Oil and gas properties – Canada: Balance, beginning of year $ 36,579 $ 10,583 $ — Costs incurred during the year (capitalized): Acquisition costs (2,862 ) 6,956 8,764 Exploratory costs 8,767 19,040 1,819 Total costs incurred during the year 5,905 25,996 10,583 Balance, end of year (fully evaluated at December 31, 2015 and unevaluated at December 31, 2014 and 2013) $ 42,484 $ 36,579 $ 10,583 Accumulated DD&A: Balance, beginning of year $ — $ — $ — Foreign currency translation adjustment 5,146 $ — — Write-down of oil and gas properties (47,630 ) $ — — Balance, end of year $ (42,484 ) $ — $ — Net capitalized costs – Canada $ — $ 36,579 $ 10,583

SUMMARIZED QUARTERLY FINANCIA41

SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Results of Operations by Quarter	The results of operations by quarter are as follows: 2015 Quarter Ended March 31 June 30 September 30 December 31 Operating revenue $ 153,498 $ 149,525 $ 132,196 $ 110,499 Loss from operations (497,194 ) (228,161 ) (297,209 ) (342,759 ) Net loss (327,388 ) (152,906 ) (291,965 ) (318,656 ) Basic loss per share $ (5.93 ) $ (2.77 ) $ (5.28 ) $ (5.76 ) Diluted loss per share $ (5.93 ) $ (2.77 ) $ (5.28 ) $ (5.76 ) Write-down of oil and gas properties before income tax effect $ 491,412 $ 224,294 $ 295,679 $ 351,062 Write-down of oil and gas properties net of income tax effect 314,504 143,548 189,235 224,680 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 ) (286,147 ) Net income (loss) 25,943 4,444 (29,415 ) (190,515 ) 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 ) Write-down of oil and gas properties before income tax effect $ — $ — $ 47,130 $ 304,062 Write-down of oil and gas properties net of income tax effect — — 30,163 194,600

GUARANTOR FINANCIAL STATEMENTS

GUARANTOR FINANCIAL STATEMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Condensed Consolidating Balance Sheet	CCONDENSED CONSOLIDATING BALANCE SHEET DECEMBER 31, 2015 (In thousands) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 9,681 $ 2 $ 1,076 $ — $ 10,759 Accounts receivable 10,597 39,190 — (1,756 ) 48,031 Fair value of derivative contracts — 38,576 — — 38,576 Current income tax receivable 46,174 — — — 46,174 Inventory 535 — — — 535 Other current assets 6,313 — 33 — 6,346 Total current assets 73,300 77,768 1,109 (1,756 ) 150,421 Oil and gas properties, full cost method: Proved 1,875,152 7,458,262 42,484 — 9,375,898 Less: accumulated DD&A (1,874,622 ) (6,686,849 ) (42,484 ) — (8,603,955 ) Net proved oil and gas properties 530 771,413 — — 771,943 Unevaluated 253,308 186,735 — — 440,043 Other property and equipment, net 29,289 — — — 29,289 Other assets, net 16,612 826 1,035 — 18,473 Investment in subsidiary 745,033 — 1,088 (746,121 ) — Total assets $ 1,118,072 $ 1,036,742 $ 3,232 $ (747,877 ) $ 1,410,169 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable to vendors $ 16,063 $ 67,901 $ — $ (1,757 ) $ 82,207 Undistributed oil and gas proceeds 5,216 776 — — 5,992 Accrued interest 9,022 — — — 9,022 Asset retirement obligations — 20,400 891 — 21,291 Other current liabilities 40,161 551 — — 40,712 Total current liabilities 70,462 89,628 891 (1,757 ) 159,224 Long-term debt 1,060,955 — — — 1,060,955 Asset retirement obligations 1,240 203,335 — — 204,575 Other long-term liabilities 25,204 — — — 25,204 Total liabilities 1,157,861 292,963 891 (1,757 ) 1,449,958 Commitments and contingencies Stockholders’ equity: Common stock 553 — — — 553 Treasury stock (860 ) — — — (860 ) Additional paid-in capital 1,648,189 1,344,577 109,795 (1,454,372 ) 1,648,189 Accumulated deficit (1,705,623 ) (624,824 ) (95,306 ) 720,130 (1,705,623 ) Accumulated other comprehensive income (loss) 17,952 24,026 (12,148 ) (11,878 ) 17,952 Total stockholders’ equity (39,789 ) 743,779 2,341 (746,120 ) (39,789 ) Total liabilities and stockholders’ equity $ 1,118,072 $ 1,036,742 $ 3,232 $ (747,877 ) $ 1,410,169 CONDENSED CONSOLIDATING BALANCE SHEET DECEMBER 31, 2014 (In thousands) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated 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 12,103 1,360 5,007 — 18,470 Investment in subsidiary 1,050,546 — 41,638 (1,092,184 ) — Total assets $ 2,448,634 $ 1,574,087 $ 83,415 $ (1,096,279 ) $ 3,009,857 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 1,032,281 — — — 1,032,281 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 1,347,031 565,318 — (4,095 ) 1,908,254 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 $ 2,448,634 $ 1,574,087 $ 83,415 $ (1,096,279 ) $ 3,009,857 * Deferred income taxes have been allocated to our Guarantor Subsidiaries where related oil and gas properties reside.
Condensed Consolidating Statement of Operations	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2015 (In thousands) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated Operating revenue: Oil production $ 12,804 $ 403,693 $ — $ — $ 416,497 Natural gas production 41,646 41,863 — — 83,509 Natural gas liquids production 22,375 9,947 — — 32,322 Other operational income 4,369 — — — 4,369 Derivative income, net — 7,952 — — 7,952 Total operating revenue 81,194 463,455 — — 544,649 Operating expenses: Lease operating expenses 16,264 83,872 3 — 100,139 Transportation, processing, and gathering expenses 50,247 8,600 — — 58,847 Production taxes 5,631 1,246 — — 6,877 Depreciation, depletion, amortization 123,724 157,964 — — 281,688 Write-down of oil and gas properties 785,463 529,354 47,630 — 1,362,447 Accretion expense 365 25,623 — — 25,988 Salaries, general and administrative expenses 69,147 201 36 — 69,384 Incentive compensation expense 2,242 — — — 2,242 Other operational expenses 2,360 — — — 2,360 Total operating expenses 1,055,443 806,860 47,669 — 1,909,972 Loss from operations (974,249 ) (343,405 ) (47,669 ) — (1,365,323 ) Other (income) expenses: Interest expense 43,907 21 — — 43,928 Interest income (327 ) (246 ) (7 ) — (580 ) Other income (617 ) (1,163 ) (3 ) — (1,783 ) Other expense 434 — — — 434 Loss from investment in subsidiaries 231,783 — 47,659 (279,442 ) — Total other (income) expenses 275,180 (1,388 ) 47,649 (279,442 ) 41,999 Loss before taxes (1,249,429 ) (342,017 ) (95,318 ) 279,442 (1,407,322 ) Provision (benefit) for income taxes: Current (44,096 ) — — — (44,096 ) Deferred (114,418 ) (157,893 ) — — (272,311 ) Total income taxes (158,514 ) (157,893 ) — — (316,407 ) Net loss $ (1,090,915 ) $ (184,124 ) $ (95,318 ) $ 279,442 $ (1,090,915 ) Comprehensive loss $ (1,156,278 ) $ (184,124 ) $ (95,318 ) $ 279,442 $ (1,156,278 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2014 (In thousands) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated 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 expenses 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 Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated 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 expenses 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 Cash Flows	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2015 (In thousands) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated Cash flows from operating activities: Net loss $ (1,090,915 ) $ (184,124 ) $ (95,318 ) $ 279,442 $ (1,090,915 ) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization 123,724 157,964 — — 281,688 Write-down of oil and gas properties 785,463 529,354 47,630 — 1,362,447 Accretion expense 365 25,623 — — 25,988 Deferred income tax benefit (114,418 ) (157,893 ) — — (272,311 ) Settlement of asset retirement obligations (15 ) (72,367 ) — — (72,382 ) Non-cash stock compensation expense 12,324 — — — 12,324 Excess tax benefits (1,586 ) — — — (1,586 ) Non-cash derivative expense — 16,440 — — 16,440 Non-cash interest expense 17,788 — — — 17,788 Change in current income taxes (37,377 ) — — — (37,377 ) Non-cash loss from investment in subsidiaries 231,783 — 47,659 (279,442 ) — Change in intercompany receivables/payables 9,744 (19,486 ) 9,742 — — Decrease in accounts receivable 34,609 9,084 31 — 43,724 (Increase) decrease in other current assets 1,799 — (32 ) — 1,767 (Increase) decrease in inventory (1,394 ) 2,698 — — 1,304 Decrease in accounts payable (7,471 ) (7,111 ) — — (14,582 ) Increase (decrease) in other current liabilities (25,989 ) 53 — — (25,936 ) Other 256 (1,163 ) — — (907 ) Net cash (used in) provided by operating activities (61,310 ) 299,072 9,712 — 247,474 Cash flows from investing activities: Investment in oil and gas properties (188,154 ) (323,359 ) (10,534 ) — (522,047 ) Proceeds from sale of oil and gas properties, net of expenses — 22,839 — — 22,839 Investment in fixed and other assets (1,549 ) — — — (1,549 ) Change in restricted funds 177,647 — 1,820 — 179,467 Investment in subsidiaries — — (9,714 ) 9,714 — Net cash used in investing activities (12,056 ) (300,520 ) (18,428 ) 9,714 (321,290 ) Cash flows from financing activities: Proceeds from bank borrowings 5,000 — — — 5,000 Repayments of bank borrowings (5,000 ) — — — (5,000 ) Deferred financing costs (68 ) — — — (68 ) Proceeds from building loan 11,770 — — — 11,770 Equity proceeds from parent — — 9,714 (9,714 ) — Excess tax benefits 1,586 — — — 1,586 Net payments for share-based compensation (3,127 ) — — — (3,127 ) Net cash provided by financing activities 10,161 — 9,714 (9,714 ) 10,161 Effect of exchange rate changes on cash — — (74 ) — (74 ) Net change in cash and cash equivalents (63,205 ) (1,448 ) 924 — (63,729 ) Cash and cash equivalents, beginning of period 72,886 1,450 152 — 74,488 Cash and cash equivalents, end of period $ 9,681 $ 2 $ 1,076 $ — $ 10,759 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2014 (In thousands) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated 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 Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated 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 Change in current income taxes 2,767 — — — 2,767 Non-cash (income) loss from investment in subsidiaries (214,983 ) — 26 214,957 — 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

Organization and Summary of S43

Organization and Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2012	Dec. 31, 2014	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		$ 300,000,000		$ 300,000,000
Senior convertible note, stated interest rate	1.75%	1.75%	1.75%
Senior convertible note, maturity year		2,017

Going Concern (Details)

Going Concern (Details) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015USD ($)
Troubled Debt Restructuring, Debtor, Subsequent Periods [Line Items]
Level of indebtedness		$ 1,137,000
Consolidated Funded Debt to consolidated EBITDA financial ratio covenant		3.09
Covenant Compliance [Member]
Troubled Debt Restructuring, Debtor, Subsequent Periods [Line Items]
Consolidated Funded Debt to consolidated EBITDA financial ratio covenant		3.75
Covenant Compliance [Member] | Scenario, Forecast [Member]
Troubled Debt Restructuring, Debtor, Subsequent Periods [Line Items]
Consolidated Funded Debt to consolidated EBITDA financial ratio covenant	3.75
Senior Notes [Member]
Troubled Debt Restructuring, Debtor, Subsequent Periods [Line Items]
Level of indebtedness		$ 1,075,000

Earnings Per Share - Calculatio

Earnings Per Share - Calculation of Basic and Diluted Weighted Average Shares Outstanding and Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Basic:
Net income (loss)	$ (318,656)	$ (291,965)	$ (152,906)	$ (327,388)	$ (190,515)	$ (29,415)	$ 4,444	$ 25,943	$ (1,090,915)	$ (189,543)	$ 117,634
Net income attributable to participating securities									0	0	(2,817)
Net income (loss) attributable to common stock - basic									(1,090,915)	(189,543)	114,817
Diluted:
Net income (loss)	$ (318,656)	$ (291,965)	$ (152,906)	$ (327,388)	$ (190,515)	$ (29,415)	$ 4,444	$ 25,943	(1,090,915)	(189,543)	117,634
Net income attributable to participating securities									0	0	(2,815)
Net income (loss) attributable to common stock - diluted									$ (1,090,915)	$ (189,543)	$ 114,819
Weighted average shares (denominator):
Weighted average shares - basic (in shares)									55,250	52,721	48,693
Dilutive effect of stock options (in shares)									0	0	42
Weighted average shares - diluted (in shares)									55,250	52,721	48,735
Basic earnings (loss) per share (in usd per share)	$ (5.76)	$ (5.28)	$ (2.77)	$ (5.93)	$ (3.47)	$ (0.54)	$ 0.08	$ 0.52	$ (19.75)	$ (3.60)	$ 2.36
Diluted earnings (loss) per share (in usd per share)	$ (5.76)	$ (5.28)	$ (2.77)	$ (5.93)	$ (3.47)	$ (0.54)	$ 0.08	$ 0.52	$ (19.75)	$ (3.60)	$ 2.36

Earnings Per Share - Additional

Earnings Per Share - Additional Information (Detail) - shares	1 Months Ended	12 Months Ended
	May. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Weighted Average Shares Used In Computing Earnings Per Share [Line Items]
Antidilutive stock options outstanding (in shares)		145,000	205,000	242,000
Shares of common stock issued upon vesting of restricted stock (in shares)		418,000	384,000	358,000
IPO [Member]
Weighted Average Shares Used In Computing Earnings Per Share [Line Items]
Common stock issued (in shares)	5,750,000

Accounts Receivable - Component

Accounts Receivable - Components of Accounts Receivable (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Receivables [Abstract]
Other co-venturers	$ 4,639	$ 16,291
Trade	26,224	60,263
Unbilled accounts receivable	1,736	33,052
Other	15,432	10,753
Total accounts receivable	$ 48,031	$ 120,359

Concentrations - Customers from

Concentrations - Customers from Whom We Derived 10% or More of Total Oil and Gas Revenue (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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] | Phillips 66 Company [Member]
Concentration Risk [Line Items]
Customers from whom 10% or more revenue derived	53.00%	31.00%	35.00%
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	13.00%	32.00%	33.00%

Concentrations - Additional Inf

Concentrations - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Unusual Risk or Uncertainty [Line Items]
Maximum amount of credit risk exposure	$ 20,826
GOM Deep Water, Conventional Shelf and Deep Gas Properties [Member]
Unusual Risk or Uncertainty [Line Items]
Production associated with properties	56.00%
Estimated proved reserves derived	99.00%
Appalachian Properties [Member]
Unusual Risk or Uncertainty [Line Items]
Production associated with properties	44.00%
Estimated proved reserves derived	1.00%

Divestitures - Additional Infor

Divestitures - Additional Information (Detail) - USD ($) $ in Thousands	Jan. 16, 2014	Jul. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of interest cash consideration			$ 22,839	$ 242,914	$ 48,821
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

Derivative Instruments and He51

Derivative Instruments and Hedging Activities - Hedging Positions (Detail) - Subsequent Event [Member] - Designated as Hedging Instrument [Member]	Feb. 22, 2016MBblsMMBTU$ / MMBTU$ / bbl
2016 Hedging Position One [Member] | Fixed Price Swaps [Member] | Oil (MBbls) [Member]
Derivatives, Fair Value [Line Items]
Daily Volume | MBbls	1,000
Swap Price | $ / bbl	49.75
2016 Hedging Position One [Member] | Fixed Price Swaps [Member] | Natural Gas (MMcfe) [Member]
Derivatives, Fair Value [Line Items]
Daily Volume | MMBTU	10,000
Swap Price | $ / MMBTU	4.110
2016 Hedging Position Two [Member] | Fixed Price Swaps [Member] | Oil (MBbls) [Member]
Derivatives, Fair Value [Line Items]
Daily Volume | MBbls	1,000
Swap Price | $ / MMBTU	52.78
2016 Hedging Position Two [Member] | Fixed Price Swaps [Member] | Natural Gas (MMcfe) [Member]
Derivatives, Fair Value [Line Items]
Daily Volume | MMBTU	10,000
Swap Price | $ / MMBTU	4.120
2016 Hedging Position Three [Member] | Fixed Price Swaps [Member] | Oil (MBbls) [Member]
Derivatives, Fair Value [Line Items]
Daily Volume | MBbls	1,000
Swap Price | $ / MMBTU	90
2016 Hedging Position Four [Member] | Costless Collar [Member] | Oil (MBbls) [Member]
Derivatives, Fair Value [Line Items]
Daily Volume | MBbls	1,000
Floor Price | $ / bbl	45
Ceiling Price | $ / bbl	54.75

Derivative Instruments and He52

Derivative Instruments and Hedging Activities - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015USD ($)counterparty	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)
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%
Accumulated other comprehensive income	$ 17,952,000	$ 83,315,000	$ (2,062,000)	$ 28,833,000
Accumulated other comprehensive income, to be reclassified into earnings in the next twelve months	24,025,000
Potential impact of the rights of offset	0
Cash Flow Hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated other comprehensive income	$ 24,025,000	$ 86,783,000	$ (1,395,000)	$ 28,833,000
Fixed-Price Swaps And Costless Collars [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Number of counterparties | counterparty	2
Two Counterparties [Member] | Fixed-Price Swaps And Costless Collars [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Counterparty contract volume percentage	86.00%

Derivative Instruments and He53

Derivative Instruments and Hedging Activities - Location and Fair Value Amounts of Derivative Instruments Reported in Balance Sheet (Detail) - Designated as Hedging Instrument [Member] - Commodity Contracts [Member] - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Asset Derivatives
Fair Value of Derivative Instruments, Assets	$ 38,576	$ 141,366
Liability Derivatives
Fair Value of Derivative Instruments, Liabilities	0	0
Current liabilities [Member]
Liability Derivatives
Fair Value of Derivative Instruments, Liabilities	0	0
Long-term liabilities [Member]
Liability Derivatives
Fair Value of Derivative Instruments, Liabilities	0	0
Current Asset [Member]
Asset Derivatives
Fair Value of Derivative Instruments, Assets	38,576	127,033
Long-term assets [Member]
Asset Derivatives
Fair Value of Derivative Instruments, Assets	$ 0	$ 14,333

Derivative Instruments and He54

Derivative Instruments and Hedging Activities - Before Tax Effect of Derivative Instruments in Statement of Operations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Decrease/increase in oil revenue owing to effective hedging contracts	$ 135,617	$ 7,929	$ 3,520
Decrease/increase in gas revenue owing to effective hedging contracts	14,338	7,403	16,769
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives	52,630	136,097	(26,945)
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion)	149,955	526	20,289
Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	2,713	5,721	(2,090)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives	52,630	136,097	(26,945)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Derivative income, net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	2,713	5,721	(2,090)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Operating revenue - oil/gas production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion)	$ 149,955	$ 526	$ 20,289

Derivative Instruments and He55

Derivative Instruments and Hedging Activities - Location and Fair Value Amounts of Derivative Instruments Not Qualifying as Hedging Instruments Reported in Balance Sheet (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Commodity Contracts [Member] | Current Assets [Member]
Asset Derivatives
Fair Value of Derivative Instruments	$ 0	$ 12,146

Derivative Instruments and He56

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 ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Cash settlements	$ 17,385	$ 1,484
Change in fair value	(12,146)	12,146
Total gain on non-qualifying derivatives	$ 5,239	$ 13,630

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Marketable securities (Other assets)	$ 8,499	$ 8,425
Assets, Fair Value, Total	47,075	161,937
Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts	38,576	153,512
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)	8,499	8,425
Assets, Fair Value, Total	8,499	8,425
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts	0	0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Marketable securities (Other assets)	0	0
Assets, Fair Value, Total	36,603	153,512
Significant Other Observable Inputs (Level 2) [Member] | Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts	36,603	153,512
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Marketable securities (Other assets)	0	0
Assets, Fair Value, Total	1,973	0
Fair Value, Inputs, Level 3 [Member] | Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts	$ 1,973	$ 0

FAIR VALUE MEASUREMENTS Fair Va

FAIR VALUE MEASUREMENTS Fair Value Measurements - Asset Unobservable Input Reconciliation (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance as of January 1, 2015	$ 0
Included in earnings	63
Included in other comprehensive income	1,910
Purchases, sales, issuances and settlements	0
Transfers in and out of Level 3	0
Balance as of December 31, 2015	1,973
The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at December 31, 2015	$ 63

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2012
Convertible Notes Due 2017 [Member]
Debt Instrument [Line Items]
Fair value of Convertible Notes	$ 217,117	$ 252,587
7.5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior convertible note, stated interest rate	7.50%	7.50%
Fair value of Notes	$ 271,250	$ 664,563
1.75% Senior Convertible Notes due 2017 [Member]
Debt Instrument [Line Items]
Senior convertible note, stated interest rate	1.75%	1.75%	1.75%

Asset Retirement Obligations -

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations as of the beginning of the year, including current portion	$ 316,409	$ 502,513	$ 488,302
Liabilities incurred	15,933	28,606	19,043
Liabilities settled	(72,713)	(55,839)	(79,695)
Divestment of properties	(248)	(137,801)	(9,245)
Accretion expense	25,988	28,411	33,575
Revision of estimates	(59,503)	(49,481)	50,533
Asset retirement obligations as of the end of the year, including current portion	$ 225,866	$ 316,409	$ 502,513

Income Taxes - Analysis of Defe

Income Taxes - Analysis of Deferred Taxes (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Tax effect of temporary differences:
Net operating loss carryforwards	$ 31,624	$ 99,615
Oil and gas properties – full cost	76,766	(476,367)
Asset retirement obligations	79,618	113,907
Stock compensation	5,199	5,603
Hedges	(13,598)	(54,439)
Accrued incentive compensation	1,234	6,185
Other	(722)	(966)
Total deferred tax assets (liabilities)	180,121	(306,462)
Valuation allowance	(180,121)	0
Net deferred tax liabilities	$ 0	$ (306,462)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Current federal income tax benefit	$ (44,096,000)	$ 159,000	$ (10,904,000)
Deferred	(272,311,000)	(102,177,000)	79,629,000
Current income tax receivable	46,174,000	7,212,000
Operating loss carryforwards	$ 97,225,000
Operating loss carryforwards begins to expire	2,035
Statutory depletion deductions available for tax reporting purposes	$ 1,056,000
Valuation allowance against portion of deferred tax assets	180,121,000	0
Income taxes allocated to other comprehensive income related to oil and gas hedges	(35,737,000)	49,601,000	$ (17,003,000)
Unrecognized tax benefits	491,000	0
Unrecognized tax benefits, interest expense	131,000	0
Unrecognized tax benefits, penalties expense	$ 0	$ 0

Income Taxes - Reconciliation B

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Income tax expense computed at the statutory federal income tax rate	35.00%	35.00%	35.00%
State taxes	0.60%	1.00%	1.00%
Change in valuation allowance	(12.80%)	0.00%	0.00%
IRC Sec. 162(m) limitation	(0.10%)	(0.50%)	0.80%
Tax deficits on stock compensation	(0.10%)	(0.20%)	0.00%
Other	(0.10%)	(0.30%)	0.10%
Effective income tax rate	22.50%	35.00%	36.90%

Income Taxes - Unrecognized Tax

Income Taxes - Unrecognized Tax Benefits (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Total unrecognized tax benefits as of December 31, 2014	$ 0
Tax positions taken during a prior period	491
Tax positions taken during the current period	0
Settlements with taxing authorities	0
Lapse of applicable statute of limitations	0
Total unrecognized tax benefits as of December 31, 2015	$ 491

Long-Term Debt - Long-Term Debt

Long-Term Debt - Long-Term Debt (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Nov. 20, 2015	Dec. 31, 2014	Dec. 31, 2012
Debt Instrument [Line Items]
Long-term debt	$ 1,060,955		$ 1,032,281
Base borrowing and credit facility	0		0
1.75% Senior Convertible Notes due 2017 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 279,244		$ 262,791
Interest rate	1.75%		1.75%	1.75%
7.5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 770,009		$ 769,490
Interest rate	7.50%		7.50%
Building Loan [Member]
Debt Instrument [Line Items]
Long-term debt	$ 11,702		$ 0
Interest rate		4.20%

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail)	Nov. 20, 2015USD ($)instalment	Nov. 27, 2013USD ($)	Nov. 08, 2012USD ($)	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Feb. 22, 2016USD ($)	Oct. 31, 2015USD ($)	Jun. 24, 2014USD ($)	Dec. 31, 2012USD ($)	Mar. 06, 2012USD ($)
Debt Instrument [Line Items]
Base borrowing and credit facility				$ 0	$ 0
Line of Credit Facility, Fair Value of Amount Outstanding				$ 0
Consolidated Funded Debt to consolidated EBITDA financial ratio covenant				3.09
Consolidated EBITDA To Consolidated Net Interest Expense				7.91
Liability component of convertible note				$ 1,060,955,000	1,032,281,000
Proceeds from issuance of senior notes				0	0	$ 489,250,000
Accrued interest payment				9,022,000	9,022,000
Total interest cost incurred				$ 85,267,000	84,577,000	79,697,000
Subsequent Event [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Fair Value of Amount Outstanding							$ 50,000,000
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				Jun. 24, 2014
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				Jul. 1, 2019
Initial bank and availability under facility				$ 480,779,000				$ 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				80.00%
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				3.09 to 1
EBITDA to consolidated net interest ratio				7.91 to 1
Bank debt [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Initial bank and availability under facility							430,779,000
Outstanding borrowing under bank credit facility							$ 19,221,000
Building Loan [Member]
Debt Instrument [Line Items]
Aggregate principal amount of senior notes	$ 11,802,000
Senior convertible note, stated interest rate	4.20%
Number of monthly installments | instalment	180
Monthly installment payment	$ 73,000
EBITDA to Net Interest Expense ratio	2			7.91
Liability component of convertible note				$ 11,702,000	$ 0
4.20% Term Loan due 2030 [Member]
Debt Instrument [Line Items]
Senior convertible note, stated interest rate				4.20%	4.20%
1.75% Senior Convertible Notes due 2017 [Member]
Debt Instrument [Line Items]
Interest Expense, Debt				$ 5,250,000	$ 5,250,000	5,250,000
Aggregate principal amount of senior notes										$ 300,000,000	$ 300,000,000
Senior convertible note, stated interest rate				1.75%	1.75%					1.75%
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				0.023445
Initial conversion price of convertible note 2017 | $ / shares				$ 42.65
Closing share price | $ / shares				$ 4.29
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
Cash share holders receive for each dollar in principle				1
Payment for call option				$ 70,830,000
Anti-dilution adjustments for purchases of call option (in shares) | shares				7,033,470
Strike price per share | $ / shares				$ 55.91
Proceeds from sale of warrants				$ 40,170,000
Liability component of convertible note				279,244,000	$ 262,791,000
Accrued interest payment				1,750,000
Interest expense related to amortization of discount				15,019,000	13,951,000	12,599,000
Amortization of deferred financing costs				1,434,000	$ 1,332,000	$ 1,238,000
Interest expense related to contractual interest coupon of convertible notes				$ 5,250,000
Effective interest rates				7.51%	7.75%	7.04%
Senior Convertible Notes Due Two Thousand Seventeen And Two Thousand And Twenty Two [Member]
Debt Instrument [Line Items]
Deferred Finance Costs, Net				$ 6,869,000	$ 8,754,000
7.5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Aggregate principal amount of senior notes		$ 475,000,000	$ 300,000,000
Senior convertible note, stated interest rate				7.50%	7.50%
Liability component of convertible note				$ 770,009,000	$ 769,490,000
Proceeds from issuance of senior notes		$ 480,195,000	$ 293,203,000
Effective interest rates		3.00%
Accrued interest payment				7,266,000
Other Assets [Member] | 1.75% Senior Convertible Notes due 2017 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs, Net				$ 2,845,000	$ 3,661,000
Covenant Compliance [Member]
Debt Instrument [Line Items]
Consolidated Funded Debt to consolidated EBITDA financial ratio covenant				3.75
Consolidated EBITDA To Consolidated Net Interest Expense				2.5

Accumulated Other Comprehensi67

Accumulated Other Comprehensive Income (Loss) - Schedule of Changes in Accumulated Other Comprehensive Income Loss (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance, net of tax	$ 83,315	$ (2,062)	$ 28,833
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	52,630	136,097	(26,945)
Foreign currency translations	(2,605)	(2,801)	(667)
Income tax effect	(19,096)	(48,995)	9,701
Net of tax	30,929	84,301	(17,911)
Amounts reclassified from accumulated other comprehensive income:
Ending balance, net of tax	17,952	83,315	(2,062)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance, net of tax	83,315	(2,062)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	149,955	526	20,289
Derivative income, net	1,170	(2,208)
Income tax effect	(54,833)	606	(7,305)
Net of tax	96,292	(1,076)	12,984
Other comprehensive loss, net of tax	(65,363)	85,377	(30,895)
Ending balance, net of tax	17,952	83,315	(2,062)
Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance, net of tax	86,783	(1,395)	28,833
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	52,630	136,097	(26,945)
Foreign currency translations	0	0	0
Income tax effect	(19,096)	(48,995)	9,701
Net of tax	33,534	87,102	(17,244)
Amounts reclassified from accumulated other comprehensive income:
Ending balance, net of tax	24,025	86,783	(1,395)
Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance, net of tax	86,783	(1,395)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	149,955	526	20,289
Derivative income, net	1,170	(2,208)
Income tax effect	(54,833)	606	(7,305)
Net of tax	96,292	(1,076)	12,984
Other comprehensive loss, net of tax	(62,758)	88,178	(30,228)
Ending balance, net of tax	24,025	86,783	(1,395)
Foreign Currency Items [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance, net of tax	(3,468)	(667)	0
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	0	0	0
Foreign currency translations	(2,605)	(2,801)	(667)
Income tax effect	0	0	0
Net of tax	(2,605)	(2,801)	(667)
Amounts reclassified from accumulated other comprehensive income:
Ending balance, net of tax		(3,468)	(667)
Foreign Currency Items [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance, net of tax	(3,468)	(667)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	0	0	0
Derivative income, net	0	0
Income tax effect	0	0	0
Net of tax	0	0	0
Other comprehensive loss, net of tax	(2,605)	(2,801)	(667)
Ending balance, net of tax	$ (6,073)	$ (3,468)	$ (667)

Share-Based Compensation - Addi

Share-Based Compensation - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	$ 17,917	$ 17,051	$ 15,425
Share-based compensation capitalized into oil and gas properties	$ 5,593	$ 5,797	$ 5,078
Stock option granted (in shares)	0	0	0
Exercise price of stock options outstanding, minimum	$ 6.97
Exercise price of stock options outstanding, maximum	$ 47.75
Restricted stocks issued, shares (in shares)	1,420,475	674,904	848,498
Restricted stocks issued, value	$ 23,722	$ 24,593	$ 17,487
Unrecognized compensation cost, weighted-average period of recognition	1 year 8 months
Unrecognized compensation cost	$ 20,423
Adjustments to additional paid-in capital related to net tax effect of stock options exercises and restricted stock vesting	0	(54)	(884)
Net tax impact from stock option exercises and restricted stock vesting	$ 1,314	$ 609
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation			15,405
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
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

Share-Based Compensation - Summ

Share-Based Compensation - Summary of Stock Option Activity under Plan (Detail) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Options outstanding
Options outstanding, beginning of period (in shares)	204,974	331,174	411,794
Granted (in shares)	0	0	0
Exercised (in shares)	0	(250)	0
Forfeited (in shares)	0	0	(15,250)
Expired (in shares)	(60,500)	(125,950)	(65,370)
Options outstanding, end of period (in shares)	144,474	204,974	331,174
Options exercisable, end of period (in shares)	144,474	204,974	318,279
Options unvested, end of period (in shares)	0	0	12,895
Options outstanding, weighted average exercise price
Options outstanding, beginning of period (in usd per share)	$ 33.94	$ 39.37	$ 39.04
Granted (in usd per share)	0	0	0
Exercised (in usd per share)	0	46.20	0
Forfeited (in usd per share)	0	0	42.45
Expired (in usd per share)	50.68	48.21	36.56
Options outstanding, end of period (in usd per share)	26.92	33.94	39.37
Options exercisable, end of period (in usd per share)	26.92	33.94	40.62
Options unvested, end of period (in usd per share)	$ 0	$ 0	$ 8.64
Options outstanding
Options outstanding, Weighted Average Term, end of period	2 years 1 month 6 days	2 years 4 months 24 days	2 years 2 months 12 days
Options exercisable, Weighted Average Term, end of period	2 years 1 month 6 days	2 years 4 months 24 days	2 years 1 month 6 days
Options unvested, Weighted Average Term, end of period			5 years
Options outstanding, end of period, aggregate intrinsic value
Options outstanding, end of period	$ 0	$ 531	$ 1,708
Options exercisable, end of period	0	531	1,373
Options unvested, end of period	$ 0	$ 0	$ 335

Share-Based Compensation - Su70

Share-Based Compensation - Summary of Restricted Stock Activity under Plan (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Number of restricted shares
Restricted stock outstanding, beginning of period (in shares)	1,303,106	1,258,053	1,108,874
Issuances (in shares)	1,420,475	674,904	848,498
Lapse of restrictions (in shares)	(638,582)	(598,796)	(534,041)
Forfeitures (in shares)	(278,442)	(31,055)	(165,278)
Restricted stock outstanding, end of period (in shares)	1,806,557	1,303,106	1,258,053
Weighted average fair value
Restricted stock outstanding, beginning of period (in usd per share)	$ 29.95	$ 23.92	$ 27.56
Issuances (in usd per share)	16.70	36.44	20.61
Lapse of restrictions (in usd per share)	29.60	24.57	25.45
Forfeitures (in usd per share)	22.39	30.19	26.43
Restricted stock outstanding, end of period (in usd per share)	$ 20.83	$ 29.95	$ 23.92

Share Repurchase Program - Addi

Share Repurchase Program - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Sep. 24, 2007
Equity [Abstract]
Stock repurchase program authorized aggregate amount		$ 100,000,000
Share repurchased under share repurchase program (in shares)	300,000
Stock repurchase program total cost	$ 7,071,000
Stock repurchase program average price (in usd per share)	$ 23.57

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail)	Jun. 30, 2015USD ($)	Aug. 02, 2013USD ($)	Dec. 31, 2015USD ($)MBbls	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Loss Contingencies [Line Items]
Lease of facilities, maturity year			2,021
Payments related to lease obligations			$ 2,076,000	$ 966,000	$ 597,000
Contingent liability to surety insurance company			223,441,000
Commitments to use drilling rigs and acquisition of seismic data, value			$ 185,680,000
Commitments to use drilling rigs and acquisition of seismic data, period			3 years
Minimum barrels of oil spill to impose financial responsibility under Oil Pollution Act | MBbls			1,000
Minimum financial responsibility oil spill in specified state waters			$ 10,000,000
Minimum financial responsibility oil spill in continental shelf waters			35,000,000
Maximum financial responsibility in amounts if oil spill			150,000,000
Legal settlement		$ 18,373,000
Brokerage Fee Unpaid		1,119,000
Acquisition amount owed		$ 17,254,000
Litigation settlement amount	$ 2,119,000
Minimum potential range contingency loss	0		75,000
Maximum potential range contingency loss	2,119,000		$ 133,650
Second Claim [Member]
Loss Contingencies [Line Items]
Litigation settlement amount	$ 1,000,000

Commitments and Contingencies73

Commitments and Contingencies - Minimum Net Annual Commitments Under all Leases, Subleases and Contracts with Non-Cancelable Terms in Excess of 12 Months (Detail) $ in Thousands	Dec. 31, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,016	$ 2,022
2,017	809
2,018	612
2,019	453
2,020	453
2,021	$ 113

Employee Benefit Plans - Additi

Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 07, 2007	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	May. 21, 2015
Employee Benefit And Retirement Plans [Line Items]
Liability of vested benefits recorded in other long term liabilities		$ 1,125
Expenses related to incentive compensation bonus		$ 2,242	$ 10,361	$ 15,340
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		$ 1,553	1,989	$ 1,793
Maximum Percentage of Deferred Compensation plan		100.00%
Plan assets included in other assets		$ 8,499	$ 8,425
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%	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
2009 plan [Member]
Employee Benefit And Retirement Plans [Line Items]
Additional number of common stock to be issued under incentive stock options (in shares)					1,600,000
Additional shares available for issuance (in shares)		2,082,434
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

Supplemental Information on O75

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Financial Data Related to Oil and Gas Producing Activities (Detail) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015USD ($)$ / Mcfe	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)$ / Mcfe	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)$ / Mcfe	Dec. 31, 2014USD ($)$ / Mcfe	Dec. 31, 2013USD ($)$ / Mcfe
Accumulated DD&A:
Balance, beginning of year					$ (6,970,631)					$ (6,970,631)
Provision for DD&A										(281,688)	$ (340,006)	$ (350,574)
Foreign currency translation adjustment										2,605	2,801	667
Write-down of oil and gas properties		$ (351,062)	$ (295,679)	$ (224,294)	(491,412)	$ (304,062)	$ (47,130)	$ 0	$ 0	(1,362,447)	(351,192)	0
Balance, end of year		(8,603,955)				(6,970,631)				(8,603,955)	(6,970,631)
Net proved oil and gas properties		771,943				1,846,637				771,943	1,846,637
Lease operating expenses										100,139	176,495	201,153
Transportation, processing and gathering expenses										58,847	64,951	42,172
Production taxes										6,877	12,151	15,029
Accretion expense										25,988	28,411	33,575
United States [Member]
Oil and gas properties, proved and unevaluated:
Balance, beginning of year					9,348,054				8,517,873	9,348,054	8,517,873	7,692,261
Costs incurred during the year (capitalized):
Acquisition costs, net of sales of unevaluated properties										(14,158)	44,634	70,903
Exploratory costs										104,169	270,850	297,113
Development costs	[1]									266,982	438,334	378,242
Salaries, general and administrative costs										27,984	33,975	32,815
Interest										41,339	45,722	46,860
Less: overhead reimbursements										(913)	(3,334)	(321)
Total costs incurred during the year										425,403	830,181	825,612
Balance, end of year		9,773,457				9,348,054				9,773,457	9,348,054	8,517,873
Accumulated DD&A:
Balance, beginning of year					(6,970,631)				(5,908,760)	(6,970,631)	(5,908,760)	(5,510,166)
Provision for DD&A										(277,088)	(335,987)	(346,827)
Write-down of oil and gas properties										(1,314,817)	(351,192)	0
Sale of proved properties										1,064	(374,692)	(51,767)
Balance, end of year		(8,561,472)				(6,970,631)				(8,561,472)	(6,970,631)	(5,908,760)
Net proved oil and gas properties		$ 1,211,985				$ 2,377,423				$ 1,211,985	$ 2,377,423	$ 2,609,113
DD&A per Mcfe | $ / Mcfe		3.19				3.59				3.19	3.59	3.43
Lease operating expenses										$ 100,139	$ 176,495	$ 201,153
Transportation, processing and gathering expenses										58,847	64,951	42,172
Production taxes										6,877	12,151	15,029
Accretion expense										25,988	28,411	33,575
Expensed costs - United States										191,851	282,008	291,929
Canada [Member]
Oil and gas properties, proved and unevaluated:
Balance, beginning of year					36,579				10,583	36,579	10,583	0
Costs incurred during the year (capitalized):
Acquisition costs										(2,862)	6,956	8,764
Exploratory costs										8,767	19,040	1,819
Total costs incurred during the year										5,905	25,996	10,583
Balance, end of year		$ 42,484				$ 36,579				42,484	36,579	10,583
Accumulated DD&A:
Balance, beginning of year					$ 0				$ 0	0	0	0
Foreign currency translation adjustment										5,146	0	0
Write-down of oil and gas properties										(47,630)	0	0
Balance, end of year		(42,484)				0				(42,484)	0	0
Net proved oil and gas properties		$ 0				$ 36,579				$ 0	$ 36,579	$ 10,583
[1]	Includes capitalized asset retirement costs of ($43,901), ($20,305) and $54,737, respectively.

Supplemental Information on O76

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Financial Data Related to Oil and Gas Producing Activities (non-printing) (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Asset retirement costs included in development cost	$ (43,901)	$ (20,305)	$ 54,737

Supplemental Information on O77

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Additional Information (Detail) MBbls in Thousands, $ in Thousands	Dec. 31, 2015USD ($)Project$ / bbl$ / Bngl$ / Mcf	Sep. 30, 2015USD ($)$ / bbl$ / Bngl$ / Mcf	Jun. 30, 2015USD ($)$ / bbl$ / Bngl$ / Mcf	Mar. 31, 2015USD ($)$ / bbl$ / Bngl$ / Mcf	Dec. 31, 2014USD ($)$ / bbl$ / Mcf	Sep. 30, 2014USD ($)$ / bbl$ / Mcf	Dec. 31, 2015USD ($)Project$ / bbl$ / Bngl$ / Mcf	Sep. 30, 2015USD ($)$ / bbl$ / Bngl$ / Mcf	Jun. 30, 2015USD ($)$ / bbl$ / Bngl$ / Mcf	Mar. 31, 2015USD ($)$ / bbl$ / Bngl$ / Mcf	Dec. 31, 2014USD ($)$ / bbl$ / Mcf	Sep. 30, 2014USD ($)$ / bbl$ / Mcf	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)Project$ / bbl$ / Bngl$ / McfMBblsMMcf	Dec. 31, 2014USD ($)$ / bbl$ / McfMBblsMMcf	Dec. 31, 2013USD ($)$ / bbl$ / McfMBblsMMcf
Reserve Quantities [Line Items]
Average 12-month oil prices net of differentials | $ / bbl	51.16	57.76	68.68	78.99	89.46	94.94	51.16	57.76	68.68	78.99	89.46	94.94			51.16	89.46	102.21
Increase in written down value of oil and gas properties | $					$ 13,342	$ 29,001
Average 12-month gas prices net of differentials | $ / Mcf	2.19	2.44	2.47	2.96	3.68	4.19	2.19	2.44	2.47	2.96	3.68	4.19			2.19	3.68	3.66
Write-down of oil and gas properties before income tax effect | $							$ 351,062	$ 295,679	$ 224,294	$ 491,412	$ 304,062	$ 47,130	$ 0	$ 0	$ 1,362,447	$ 351,192	$ 0
Interest costs capitalized on unevaluated properties | $															$ 41,339	$ 45,722	$ 46,860
Specifically identified drilling projects | Project	95						95								95
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]
Write-down of oil and gas properties before income tax effect | $	$ 348,601	$ 295,679	$ 179,125	$ 491,412	$ 304,062	$ 47,130
Natural Gas Liquids (MBbls) [Member]
Reserve Quantities [Line Items]
Increase in written down value of oil and gas properties | $							$ 24,797	$ 42,652	$ 47,784	$ 28,687
Average 12-month gas prices net of differentials	16.40	23.04	29.13	28.82	36.79	41.33	16.40	23.04	29.13	28.82	36.79	41.33			16.40	36.79
Extensions, discoveries and other additions | MBbls															11	7,521	4,395
Sale of reserves primarily related to sale | MBbls															0	556	0
Revisions of previous estimates | MBbls															(20,777)	(331)	2,439
Average 12-month natural gas liquids prices net of differentials | $ / bbl	16.40				36.79		16.40				36.79				16.40	36.79	37.59
Scenario, Adjustment [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates															(570)		18
Well Performance [Member] | Scenario, Adjustment [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates															42		55
Appalachia Drilling Program [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions																118	117
Sale of reserves primarily related to sale																15
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

Supplemental Information on O78

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Net Costs Incurred on Unevaluated Properties (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Acquisition costs evaluated during the year	$ (115,767)	$ (42,384)	$ 30,271
Exploration costs evaluated during the year	(16,315)	(186,308)	188,830
Capitalized interest costs evaluated during the year	41,339	45,722	46,860
Total costs incurred during the year, net of divestitures	$ (90,743)	$ (182,970)	$ 265,961

Supplemental Information on O79

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Financial Data Associated with Unevaluated Costs (Detail) - Unevaluated Costs [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	$ 173,902
Exploration costs	148,518
Capitalized interest	117,623
Total unevaluated costs	440,043
Acquisition costs	(33,623)	$ (5,118)	$ 40,535	$ 172,108
Exploration costs	41,936	42,899	42,186	21,497
Capitalized interest	20,257	23,538	24,162	49,666
Total unevaluated costs	$ 28,570	$ 61,319	$ 106,883	$ 243,271

Supplemental Information on O80

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Summary of Estimated Proved Oil and Natural Gas Reserve (Detail) MMcf in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2015MBblsMMcf	Dec. 31, 2014MBblsMMcf	Dec. 31, 2013MBblsMMcf
Oil (MBbls) [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Estimated proved reserves, beginning balance | MBbls	42,397	43,827	44,918
Revisions of previous estimates | MBbls	(6,818)	(624)	3,606
Extensions, discoveries and other additions | MBbls	862	9,650	2,367
Purchase of producing properties | MBbls	685
Sale of reserves | MBbls	(859)	(4,888)	(170)
Production | MBbls	(5,991)	(5,568)	(6,894)
Estimated proved reserves, ending balance | MBbls	30,276	42,397	43,827
Estimated proved developed reserves | MBbls	21,734	22,957	27,920
Estimated proved undeveloped reserves | MBbls	8,542	19,440	15,907
Natural Gas Liquids (MBbls) [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Estimated proved reserves, beginning balance | MBbls	27,817	23,297	18,066
Revisions of previous estimates | MBbls	(20,777)	(331)	2,439
Extensions, discoveries and other additions | MBbls	11	7,521	4,395
Purchase of producing properties | MBbls	1,808
Sale of reserves | MBbls	0	(556)	0
Production | MBbls	(2,401)	(2,114)	(1,603)
Estimated proved reserves, ending balance | MBbls	6,458	27,817	23,297
Estimated proved developed reserves | MBbls	4,784	13,743	11,569
Estimated proved undeveloped reserves | MBbls	1,674	14,074	11,728
Natural Gas (MMcfe) [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Estimated proved reserves, beginning balance | MMcf	493,843	460,766	395,374
Revisions of previous estimates | MMcf	(362,102)	(4,631)	36,006
Extensions, discoveries and other additions | MMcf	1,499	131,617	79,729
Purchase of producing properties | MMcf	26,136
Sale of reserves | MMcf	(1,061)	(46,483)	(214)
Production | MMcf	(36,457)	(47,426)	(50,129)
Estimated proved reserves, ending balance | MMcf	121,858	493,843	460,766
Estimated proved developed reserves | MMcf	90,262	249,924	246,946
Estimated proved undeveloped reserves | MMcf	31,596	243,919	213,820
Oil And Natural Gas (MMcfe) [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Estimated proved reserves, beginning balance | MMcf	915,124	863,513	773,285
Revisions of previous estimates | MMcf	(527,675)	(10,362)	72,275
Extensions, discoveries and other additions | MMcf	6,738	234,639	120,299
Purchase of producing properties | MMcf	41,095
Sale of reserves | MMcf	(6,213)	(79,151)	(1,235)
Production | MMcf	(86,809)	(93,515)	(101,111)
Estimated proved reserves, ending balance | MMcf	342,260	915,124	863,513
Estimated proved developed reserves | MMcf	249,366	470,118	483,885
Estimated proved undeveloped reserves | MMcf	92,894	445,006	379,628

Supplemental Information on O81

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Summary of Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Future cash inflows				$ 1,921,329	$ 6,635,751	$ 7,040,928
Future production costs				(651,396)	(2,413,004)	(2,062,657)
Future development costs				(679,355)	(1,511,687)	(1,431,101)
Future income taxes				0	(609,516)	(884,637)
Future net cash flows				590,578	2,101,544	2,662,533
10% annual discount				13,259	(682,752)	(977,531)
Standardized measure of discounted future net cash flows	$ 1,418,792	$ 1,685,002	$ 1,513,859	$ 603,837	$ 1,418,792	$ 1,685,002
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure at beginning of year	1,418,792	1,685,002	1,513,859
Sales and transfers of oil, gas and NGLs produced, net of production costs	(340,477)	(486,232)	(708,017)
Changes in price, net of future production costs	(237,747)	(864,118)	229,425
Extensions and discoveries, net of future production and development costs	1,573	549,649	155,592
Changes in estimated future development costs, net of development costs incurred during the period	731,115	203,026	28,684
Revisions of quantity estimates	(1,458,652)	(27,495)	281,558
Accretion of discount	174,456	222,009	202,087
Net change in income taxes	325,768	209,323	(28,084)
Purchases of reserves in-place	3,493	0	0
Sales of reserves in-place	0	(152,787)	15,531
Changes in production rates due to timing and other	(14,484)	80,415	(5,633)
Net increase (decrease) in standardized measure	(814,955)	(266,210)	171,143
Standardized measure at end of year	$ 603,837	$ 1,418,792	$ 1,685,002

Summarized Quarterly Financia82

Summarized Quarterly Financial Information - Unaudited - Results of Operations by Quarter (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Operating revenue	$ 110,499	$ 132,196	$ 149,525	$ 153,498	$ 184,780	$ 183,213	$ 207,046	$ 223,830	$ 544,649	$ 795,542	$ 974,179
Loss from operations	(342,759)	(297,209)	(228,161)	(497,194)	(286,147)	(34,356)	16,613	48,552	(1,365,323)	(255,338)	241,981
Net income (loss)	$ (318,656)	$ (291,965)	$ (152,906)	$ (327,388)	$ (190,515)	$ (29,415)	$ 4,444	$ 25,943	$ (1,090,915)	$ (189,543)	$ 117,634
Basic earnings (loss) per share (in usd per share)	$ (5.76)	$ (5.28)	$ (2.77)	$ (5.93)	$ (3.47)	$ (0.54)	$ 0.08	$ 0.52	$ (19.75)	$ (3.60)	$ 2.36
Diluted earnings (loss) per share (in usd per share)	$ (5.76)	$ (5.28)	$ (2.77)	$ (5.93)	$ (3.47)	$ (0.54)	$ 0.08	$ 0.52	$ (19.75)	$ (3.60)	$ 2.36
Write-down of oil and gas properties before income tax effect	$ 351,062	$ 295,679	$ 224,294	$ 491,412	$ 304,062	$ 47,130	$ 0	$ 0	$ 1,362,447	$ 351,192	$ 0
Write-down of oil and gas properties net of income tax effect	$ 224,680	$ 189,235	$ 143,548	$ 314,504	$ 194,600	$ 30,163	$ 0	$ 0

Summarized Quarterly Financia83

Summarized Quarterly Financial Information - Unaudited - Results of Operations by Quarter (non-printing) (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Write-down of oil and gas properties, before tax	$ 351,062	$ 295,679	$ 224,294	$ 491,412	$ 304,062	$ 47,130	$ 0	$ 0	$ 1,362,447	$ 351,192	$ 0
Franchise tax settlement									0	0	12,590
Loss on early extinguishment of debt, before tax									$ 0	$ 0	$ 27,279

Guarantor Financial Statement84

Guarantor Financial Statements - Condensed Consolidating Balance Sheet (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 10,759	$ 74,488	$ 331,224	$ 279,526
Restricted cash	0	177,647
Accounts receivable	48,031	120,359
Fair value of derivative contracts	38,576	139,179
Current income tax receivable	46,174	7,212
Deferred taxes		0
Inventory	535	3,709
Other current assets	6,346	8,118
Total current assets	150,421	530,712
Oil and gas properties, full cost method:
Proved	9,375,898	8,817,268
Less: accumulated DD&A	(8,603,955)	(6,970,631)
Net proved oil and gas properties	771,943	1,846,637
Unevaluated	440,043	567,365
Other property and equipment, net	29,289	32,340
Fair value of derivative contracts	0	14,333
Other assets, net	18,473	18,470
Investment in subsidiary	0	0
Total assets	1,410,169	3,009,857
Current liabilities:
Accounts payable to vendors	82,207	132,629
Undistributed oil and gas proceeds	5,992	23,232
Accrued interest	9,022	9,022
Deferred taxes	0	20,119
Asset retirement obligations	21,291	69,400
Other current liabilities	40,712	49,505
Total current liabilities	159,224	303,907
Long-term debt	1,060,955	1,032,281
Deferred taxes	0	286,343
Asset retirement obligations	204,575	247,009
Other long-term liabilities	25,204	38,714
Total liabilities	$ 1,449,958	$ 1,908,254
Commitments and contingencies
Stockholders’ equity:
Common stock	$ 553	$ 549
Treasury stock	(860)	(860)
Additional paid-in capital	1,648,189	1,633,307
Accumulated deficit	(1,705,623)	(614,708)
Accumulated other comprehensive income	17,952	83,315	(2,062)	28,833
Total stockholders’ equity	(39,789)	1,101,603
Total liabilities and stockholders’ equity	1,410,169	3,009,857
Parent [Member]
Current assets:
Cash and cash equivalents	9,681	72,886	246,294	228,398
Restricted cash		177,647
Accounts receivable	10,597	73,711
Fair value of derivative contracts	0	0
Current income tax receivable	46,174	7,212
Deferred taxes		4,095
Inventory	535	1,011
Other current assets	6,313	8,112
Total current assets	73,300	344,674
Oil and gas properties, full cost method:
Proved	1,875,152	1,689,802
Less: accumulated DD&A	(1,874,622)	(970,387)
Net proved oil and gas properties	530	719,415
Unevaluated	253,308	289,556
Other property and equipment, net	29,289	32,340
Fair value of derivative contracts		0
Other assets, net	16,612	12,103
Investment in subsidiary	745,033	1,050,546
Total assets	1,118,072	2,448,634
Current liabilities:
Accounts payable to vendors	16,063	74,756
Undistributed oil and gas proceeds	5,216	22,158
Accrued interest	9,022	9,022
Deferred taxes		0
Asset retirement obligations	0	0
Other current liabilities	40,161	49,306
Total current liabilities	70,462	155,242
Long-term debt	1,060,955	1,032,281
Deferred taxes		117,206
Asset retirement obligations	1,240	3,588
Other long-term liabilities	25,204	38,714
Total liabilities	$ 1,157,861	$ 1,347,031
Commitments and contingencies
Stockholders’ equity:
Common stock	$ 553	$ 549
Treasury stock	(860)	(860)
Additional paid-in capital	1,648,189	1,633,307
Accumulated deficit	(1,705,623)	(614,708)
Accumulated other comprehensive income	17,952	83,315
Total stockholders’ equity	(39,789)	1,101,603
Total liabilities and stockholders’ equity	1,118,072	2,448,634
Guarantor Subsidiary [Member]
Current assets:
Cash and cash equivalents	2	1,450	84,290	51,128
Restricted cash		0
Accounts receivable	39,190	46,615
Fair value of derivative contracts	38,576	139,179
Current income tax receivable	0	0
Deferred taxes		0
Inventory	0	2,698
Other current assets	0	0
Total current assets	77,768	189,942
Oil and gas properties, full cost method:
Proved	7,458,262	7,127,466
Less: accumulated DD&A	(6,686,849)	(6,000,244)
Net proved oil and gas properties	771,413	1,127,222
Unevaluated	186,735	241,230
Other property and equipment, net	0	0
Fair value of derivative contracts		14,333
Other assets, net	826	1,360
Investment in subsidiary	0	0
Total assets	1,036,742	1,574,087
Current liabilities:
Accounts payable to vendors	67,901	57,873
Undistributed oil and gas proceeds	776	1,074
Accrued interest	0	0
Deferred taxes		24,214
Asset retirement obligations	20,400	69,400
Other current liabilities	551	199
Total current liabilities	89,628	152,760
Long-term debt	0	0
Deferred taxes		169,137
Asset retirement obligations	203,335	243,421
Other long-term liabilities	0	0
Total liabilities	$ 292,963	$ 565,318
Commitments and contingencies
Stockholders’ equity:
Common stock	$ 0	$ 0
Treasury stock	0	0
Additional paid-in capital	1,344,577	1,362,684
Accumulated deficit	(624,824)	(440,699)
Accumulated other comprehensive income	24,026	86,784
Total stockholders’ equity	743,779	1,008,769
Total liabilities and stockholders’ equity	1,036,742	1,574,087
Non-Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	1,076	152	640	0
Restricted cash		0
Accounts receivable	0	33
Fair value of derivative contracts	0	0
Current income tax receivable	0	0
Deferred taxes		0
Inventory	0	0
Other current assets	33	6
Total current assets	1,109	191
Oil and gas properties, full cost method:
Proved	42,484	0
Less: accumulated DD&A	(42,484)	0
Net proved oil and gas properties	0	0
Unevaluated	0	36,579
Other property and equipment, net	0	0
Fair value of derivative contracts		0
Other assets, net	1,035	5,007
Investment in subsidiary	1,088	41,638
Total assets	3,232	83,415
Current liabilities:
Accounts payable to vendors	0	0
Undistributed oil and gas proceeds	0	0
Accrued interest	0	0
Deferred taxes		0
Asset retirement obligations	891	0
Other current liabilities	0	0
Total current liabilities	891	0
Long-term debt	0	0
Deferred taxes		0
Asset retirement obligations	0	0
Other long-term liabilities	0	0
Total liabilities	$ 891	$ 0
Commitments and contingencies
Stockholders’ equity:
Common stock	$ 0	$ 0
Treasury stock	0	0
Additional paid-in capital	109,795	90,339
Accumulated deficit	(95,306)	12
Accumulated other comprehensive income	(12,148)	(6,936)
Total stockholders’ equity	2,341	83,415
Total liabilities and stockholders’ equity	3,232	83,415
Eliminations [Member]
Current assets:
Cash and cash equivalents	0	0	$ 0	$ 0
Restricted cash		0
Accounts receivable	(1,756)	0
Fair value of derivative contracts	0	0
Current income tax receivable	0	0
Deferred taxes		(4,095)
Inventory	0	0
Other current assets	0	0
Total current assets	(1,756)	(4,095)
Oil and gas properties, full cost method:
Proved	0	0
Less: accumulated DD&A	0	0
Net proved oil and gas properties	0	0
Unevaluated	0	0
Other property and equipment, net	0	0
Fair value of derivative contracts		0
Other assets, net	0	0
Investment in subsidiary	(746,121)	(1,092,184)
Total assets	(747,877)	(1,096,279)
Current liabilities:
Accounts payable to vendors	(1,757)	0
Undistributed oil and gas proceeds	0	0
Accrued interest	0	0
Deferred taxes		(4,095)
Asset retirement obligations	0	0
Other current liabilities	0	0
Total current liabilities	(1,757)	(4,095)
Long-term debt	0	0
Deferred taxes		0
Asset retirement obligations	0	0
Other long-term liabilities	0	0
Total liabilities	$ (1,757)	$ (4,095)
Commitments and contingencies
Stockholders’ equity:
Common stock	$ 0	$ 0
Treasury stock	0	0
Additional paid-in capital	(1,454,372)	(1,453,023)
Accumulated deficit	720,130	440,687
Accumulated other comprehensive income	(11,878)	(79,848)
Total stockholders’ equity	(746,120)	(1,092,184)
Total liabilities and stockholders’ equity	$ (747,877)	$ (1,096,279)

Guarantor Financial Statement85

Guarantor Financial Statements - Condensed Consolidating Statement of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenue:
Oil production									$ 416,497	$ 516,104	$ 715,104
Natural gas production									83,509	166,494	190,580
Natural gas liquids production									32,322	85,642	60,687
Other operational income									4,369	7,951	7,808
Derivative income, net									7,952	19,351	0
Total operating revenue	$ 110,499	$ 132,196	$ 149,525	$ 153,498	$ 184,780	$ 183,213	$ 207,046	$ 223,830	544,649	795,542	974,179
Operating expenses:
Lease operating expenses									100,139	176,495	201,153
Transportation, processing and gathering expenses									58,847	64,951	42,172
Production taxes									6,877	12,151	15,029
Depreciation, depletion, amortization									281,688	340,006	350,574
Write-down of oil and gas properties	351,062	295,679	224,294	491,412	304,062	47,130	0	0	1,362,447	351,192	0
Accretion expense									25,988	28,411	33,575
Salaries, general and administrative expenses									69,384	66,451	59,524
Franchise tax settlement									0	0	12,590
Incentive compensation expense									2,242	10,361	15,340
Other operational expenses									2,360	862	151
Derivative expense, net									0	0	2,090
Total operating expenses									1,909,972	1,050,880	732,198
Income (loss) from operations	(342,759)	(297,209)	(228,161)	(497,194)	(286,147)	(34,356)	16,613	48,552	(1,365,323)	(255,338)	241,981
Other (income) expenses:
Interest expense									43,928	38,855	32,837
Interest income									(580)	(574)	(1,695)
Other income									(1,783)	(2,332)	(2,799)
Other expense									434	274	0
Loss on early extinguishment of debt									0	0	27,279
Loss from investment in subsidiaries									0	0	0
Total other expenses									41,999	36,223	55,622
Income (loss) before income taxes									(1,407,322)	(291,561)	186,359
Provision (benefit) for income taxes:
Current									(44,096)	159	(10,904)
Deferred									(272,311)	(102,177)	79,629
Total income taxes									(316,407)	(102,018)	68,725
Net income (loss)	$ (318,656)	$ (291,965)	$ (152,906)	$ (327,388)	$ (190,515)	$ (29,415)	$ 4,444	$ 25,943	(1,090,915)	(189,543)	117,634
Comprehensive income (loss)									(1,156,278)	(104,166)	86,739
Parent [Member]
Operating revenue:
Oil production									12,804	29,701	30,475
Natural gas production									41,646	86,812	68,895
Natural gas liquids production									22,375	61,200	32,293
Other operational income									4,369	7,551	7,163
Derivative income, net									0	0
Total operating revenue									81,194	185,264	138,826
Operating expenses:
Lease operating expenses									16,264	18,719	14,680
Transportation, processing and gathering expenses									50,247	53,028	28,322
Production taxes									5,631	8,324	6,229
Depreciation, depletion, amortization									123,724	138,313	93,579
Write-down of oil and gas properties									785,463	351,192
Accretion expense									365	230	372
Salaries, general and administrative expenses									69,147	66,430	59,473
Franchise tax settlement											12,590
Incentive compensation expense									2,242	10,361	15,340
Other operational expenses									2,360	669	38
Derivative expense, net											0
Total operating expenses									1,055,443	647,266	230,623
Income (loss) from operations									(974,249)	(462,002)	(91,797)
Other (income) expenses:
Interest expense									43,907	38,810	32,816
Interest income									(327)	(333)	(1,480)
Other income									(617)	(836)	(875)
Other expense									434	274
Loss on early extinguishment of debt											27,279
Loss from investment in subsidiaries									231,783	(133,336)	(214,983)
Total other expenses									275,180	(95,421)	(157,243)
Income (loss) before income taxes									(1,249,429)	(366,581)	65,446
Provision (benefit) for income taxes:
Current									(44,096)	159	(10,904)
Deferred									(114,418)	(177,197)	(41,284)
Total income taxes									(158,514)	(177,038)	(52,188)
Net income (loss)									(1,090,915)	(189,543)	117,634
Comprehensive income (loss)									(1,156,278)	(104,166)	86,739
Guarantor Subsidiary [Member]
Operating revenue:
Oil production									403,693	486,403	684,629
Natural gas production									41,863	79,682	121,685
Natural gas liquids production									9,947	24,442	28,394
Other operational income									0	400	645
Derivative income, net									7,952	19,351
Total operating revenue									463,455	610,278	835,353
Operating expenses:
Lease operating expenses									83,872	157,776	186,473
Transportation, processing and gathering expenses									8,600	11,923	13,850
Production taxes									1,246	3,827	8,800
Depreciation, depletion, amortization									157,964	201,693	256,995
Write-down of oil and gas properties									529,354	0
Accretion expense									25,623	28,181	33,203
Salaries, general and administrative expenses									201	4	5
Franchise tax settlement											0
Incentive compensation expense									0	0	0
Other operational expenses									0	193	113
Derivative expense, net											2,090
Total operating expenses									806,860	403,597	501,529
Income (loss) from operations									(343,405)	206,681	333,824
Other (income) expenses:
Interest expense									21	45	21
Interest income									(246)	(192)	(195)
Other income									(1,163)	(1,496)	(1,924)
Other expense									0	0
Loss on early extinguishment of debt											0
Loss from investment in subsidiaries									0	0	0
Total other expenses									(1,388)	(1,643)	(2,098)
Income (loss) before income taxes									(342,017)	208,324	335,922
Provision (benefit) for income taxes:
Current									0	0	0
Deferred									(157,893)	75,020	120,913
Total income taxes									(157,893)	75,020	120,913
Net income (loss)									(184,124)	133,304	215,009
Comprehensive income (loss)									(184,124)	133,304	215,009
Non-Guarantor Subsidiaries [Member]
Operating revenue:
Oil production									0	0	0
Natural gas production									0	0	0
Natural gas liquids production									0	0	0
Other operational income									0	0	0
Derivative income, net									0	0
Total operating revenue									0	0	0
Operating expenses:
Lease operating expenses									3	0	0
Transportation, processing and gathering expenses									0	0	0
Production taxes									0	0	0
Depreciation, depletion, amortization									0	0	0
Write-down of oil and gas properties									47,630	0
Accretion expense									0	0	0
Salaries, general and administrative expenses									36	17	46
Franchise tax settlement											0
Incentive compensation expense									0	0	0
Other operational expenses									0	0	0
Derivative expense, net											0
Total operating expenses									47,669	17	46
Income (loss) from operations									(47,669)	(17)	(46)
Other (income) expenses:
Interest expense									0	0	0
Interest income									(7)	(49)	(20)
Other income									(3)	0	0
Other expense									0	0
Loss on early extinguishment of debt											0
Loss from investment in subsidiaries									47,659	(32)	26
Total other expenses									47,649	(81)	6
Income (loss) before income taxes									(95,318)	64	(52)
Provision (benefit) for income taxes:
Current									0	0	0
Deferred									0	0	0
Total income taxes									0	0	0
Net income (loss)									(95,318)	64	(52)
Comprehensive income (loss)									(95,318)	64	(52)
Eliminations [Member]
Operating revenue:
Oil production									0	0	0
Natural gas production									0	0	0
Natural gas liquids production									0	0	0
Other operational income									0	0	0
Derivative income, net									0	0
Total operating revenue									0	0	0
Operating expenses:
Lease operating expenses									0	0	0
Transportation, processing and gathering expenses									0	0	0
Production taxes									0	0	0
Depreciation, depletion, amortization									0	0	0
Write-down of oil and gas properties									0	0
Accretion expense									0	0	0
Salaries, general and administrative expenses									0	0	0
Franchise tax settlement											0
Incentive compensation expense									0	0	0
Other operational expenses									0	0	0
Derivative expense, net											0
Total operating expenses									0	0	0
Income (loss) from operations									0	0	0
Other (income) expenses:
Interest expense									0	0	0
Interest income									0	0	0
Other income									0	0	0
Other expense									0	0
Loss on early extinguishment of debt											0
Loss from investment in subsidiaries									(279,442)	133,368	214,957
Total other expenses									(279,442)	133,368	214,957
Income (loss) before income taxes									279,442	(133,368)	(214,957)
Provision (benefit) for income taxes:
Current									0	0	0
Deferred									0	0	0
Total income taxes									0	0	0
Net income (loss)									279,442	(133,368)	(214,957)
Comprehensive income (loss)									$ 279,442	$ (133,368)	$ (214,957)

Guarantor Financial Statement86

Guarantor Financial Statements - Condensed Consolidating Statement of Cash Flows (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ (318,656)	$ (291,965)	$ (152,906)	$ (327,388)	$ (190,515)	$ (29,415)	$ 4,444	$ 25,943	$ (1,090,915)	$ (189,543)	$ 117,634
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization									281,688	340,006	350,574
Write-down of oil and gas properties	351,062	$ 295,679	$ 224,294	491,412	304,062	$ 47,130	$ 0	0	1,362,447	351,192	0
Accretion expense									25,988	28,411	33,575
Deferred income tax (benefit) provision									(272,311)	(102,177)	79,629
Settlement of asset retirement obligations									(72,382)	(56,409)	(83,854)
Non-cash stock compensation expense									12,324	11,325	10,347
Excess tax benefits									(1,586)	0	(156)
Non-cash derivative income									16,440	(18,028)	2,239
Loss on early extinguishment of debt									0	0	27,279
Non-cash interest expense									17,788	16,661	16,219
Change in current income taxes									(37,377)	158	2,767
Non-cash income from investment in subsidiaries									0	0	0
Change in intercompany receivables/payables									0	0	0
(Increase) decrease in accounts receivable									43,724	51,611	(4,683)
(Increase) decrease in other current assets									1,767	(6,244)	1,752
(Increase) decrease in inventory									1,304	0	583
Decrease in accounts payable									(14,582)	(3,419)	402
Increase (decrease) in other current liabilities									(25,936)	(19,152)	42,451
Other									(907)	(3,251)	(2,553)
Net cash provided by operating activities									247,474	401,141	594,205
Cash flows from investing activities:
Investment in oil and gas properties									(522,047)	(927,247)	(663,299)
Proceeds from sale of oil and gas properties, net of expenses									22,839	242,914	48,821
Investment in fixed and other assets									(1,549)	(10,182)	(6,816)
Change in restricted funds									179,467	(178,072)	(1,742)
Investment in subsidiaries									0	0	0
Net cash used in investing activities									(321,290)	(872,587)	(623,036)
Cash flows from financing activities:
Proceeds from bank borrowings									5,000	0	0
Proceeds from issuance of common stock									0	225,999	0
Repayments of bank borrowings									(5,000)	0	0
Proceeds from issuance of senior notes									0	0	489,250
Deferred financing costs									(68)	(3,371)	(9,065)
Proceeds from building loan									11,770	0	0
Redemption of senior notes									0	0	(396,014)
Excess tax benefits									1,586	0	156
Equity proceeds from parent									0	0	0
Net payments for share-based compensation									(3,127)	(7,182)	(3,733)
Net cash provided by financing activities									10,161	215,446	80,594
Effect of exchange rate changes on cash									(74)	(736)	(65)
Net change in cash and cash equivalents									(63,729)	(256,736)	51,698
Cash and cash equivalents, beginning of year				74,488				331,224	74,488	331,224	279,526
Cash and cash equivalents, end of year	10,759				74,488				10,759	74,488	331,224
Parent [Member]
Cash flows from operating activities:
Net income (loss)									(1,090,915)	(189,543)	117,634
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization									123,724	138,313	93,579
Write-down of oil and gas properties									785,463	351,192
Accretion expense									365	230	372
Deferred income tax (benefit) provision									(114,418)	(177,197)	(41,284)
Settlement of asset retirement obligations									(15)	(201)	0
Non-cash stock compensation expense									12,324	11,325	10,347
Excess tax benefits									(1,586)		(156)
Non-cash derivative income									0	0	0
Loss on early extinguishment of debt											27,279
Non-cash interest expense									17,788	16,661	16,219
Change in current income taxes									(37,377)	158	2,767
Non-cash income from investment in subsidiaries									231,783	(133,336)	(214,983)
Change in intercompany receivables/payables									9,744	114,056	186,903
(Increase) decrease in accounts receivable									34,609	1,131	(15,630)
(Increase) decrease in other current assets									1,799	(6,238)	1,752
(Increase) decrease in inventory									(1,394)	2,415	583
Decrease in accounts payable									(7,471)	(662)	(1,052)
Increase (decrease) in other current liabilities									(25,989)	(16,946)	40,543
Other									256	(1,755)	419
Net cash provided by operating activities									(61,310)	109,603	225,292
Cash flows from investing activities:
Investment in oil and gas properties									(188,154)	(338,731)	(273,474)
Proceeds from sale of oil and gas properties, net of expenses									0	28,103	6,300
Investment in fixed and other assets									(1,549)	(10,182)	(6,816)
Change in restricted funds									177,647	(177,647)	0
Investment in subsidiaries									0	0	(14,000)
Net cash used in investing activities									(12,056)	(498,457)	(287,990)
Cash flows from financing activities:
Proceeds from bank borrowings									5,000
Proceeds from issuance of common stock										225,999
Repayments of bank borrowings									(5,000)
Proceeds from issuance of senior notes											489,250
Deferred financing costs									(68)	(3,371)	(9,065)
Proceeds from building loan									11,770
Redemption of senior notes											(396,014)
Excess tax benefits									1,586		156
Equity proceeds from parent									0	0	0
Net payments for share-based compensation									(3,127)	(7,182)	(3,733)
Net cash provided by financing activities									10,161	215,446	80,594
Effect of exchange rate changes on cash									0	0	0
Net change in cash and cash equivalents									(63,205)	(173,408)	17,896
Cash and cash equivalents, beginning of year				72,886				246,294	72,886	246,294	228,398
Cash and cash equivalents, end of year	9,681				72,886				9,681	72,886	246,294
Guarantor Subsidiary [Member]
Cash flows from operating activities:
Net income (loss)									(184,124)	133,304	215,009
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization									157,964	201,693	256,995
Write-down of oil and gas properties									529,354	0
Accretion expense									25,623	28,181	33,203
Deferred income tax (benefit) provision									(157,893)	75,020	120,913
Settlement of asset retirement obligations									(72,367)	(56,208)	(83,854)
Non-cash stock compensation expense									0	0	0
Excess tax benefits									0		0
Non-cash derivative income									16,440	(18,028)	2,239
Loss on early extinguishment of debt											0
Non-cash interest expense									0	0	0
Change in current income taxes									0	0	0
Non-cash income from investment in subsidiaries									0	0	0
Change in intercompany receivables/payables									(19,486)	(145,250)	(186,947)
(Increase) decrease in accounts receivable									9,084	50,514	10,947
(Increase) decrease in other current assets									0	0	0
(Increase) decrease in inventory									2,698	(2,415)	0
Decrease in accounts payable									(7,111)	(2,757)	1,454
Increase (decrease) in other current liabilities									53	(2,206)	1,908
Other									(1,163)	(1,496)	(2,972)
Net cash provided by operating activities									299,072	260,352	368,895
Cash flows from investing activities:
Investment in oil and gas properties									(323,359)	(558,003)	(378,254)
Proceeds from sale of oil and gas properties, net of expenses									22,839	214,811	42,521
Investment in fixed and other assets									0	0	0
Change in restricted funds									0	0	0
Investment in subsidiaries									0	0	0
Net cash used in investing activities									(300,520)	(343,192)	(335,733)
Cash flows from financing activities:
Proceeds from bank borrowings									0
Proceeds from issuance of common stock										0
Repayments of bank borrowings									0
Proceeds from issuance of senior notes											0
Deferred financing costs									0	0	0
Proceeds from building loan									0
Redemption of senior notes											0
Excess tax benefits									0		0
Equity proceeds from parent									0	0	0
Net payments for share-based compensation									0	0	0
Net cash provided by financing activities									0	0	0
Effect of exchange rate changes on cash									0	0	0
Net change in cash and cash equivalents									(1,448)	(82,840)	33,162
Cash and cash equivalents, beginning of year				1,450				84,290	1,450	84,290	51,128
Cash and cash equivalents, end of year	2				1,450				2	1,450	84,290
Non-Guarantor Subsidiaries [Member]
Cash flows from operating activities:
Net income (loss)									(95,318)	64	(52)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization									0	0	0
Write-down of oil and gas properties									47,630	0
Accretion expense									0	0	0
Deferred income tax (benefit) provision									0	0	0
Settlement of asset retirement obligations									0	0	0
Non-cash stock compensation expense									0	0	0
Excess tax benefits									0		0
Non-cash derivative income									0	0	0
Loss on early extinguishment of debt											0
Non-cash interest expense									0	0	0
Change in current income taxes									0	0	0
Non-cash income from investment in subsidiaries									47,659	(32)	26
Change in intercompany receivables/payables									9,742	31,194	44
(Increase) decrease in accounts receivable									31	(34)	0
(Increase) decrease in other current assets									(32)	(6)	0
(Increase) decrease in inventory									0	0	0
Decrease in accounts payable									0	0	0
Increase (decrease) in other current liabilities									0	0	0
Other									0	0	0
Net cash provided by operating activities									9,712	31,186	18
Cash flows from investing activities:
Investment in oil and gas properties									(10,534)	(30,513)	(11,571)
Proceeds from sale of oil and gas properties, net of expenses									0	0	0
Investment in fixed and other assets									0	0	0
Change in restricted funds									1,820	(425)	(1,742)
Investment in subsidiaries									(9,714)	(31,696)	(13,404)
Net cash used in investing activities									(18,428)	(62,634)	(26,717)
Cash flows from financing activities:
Proceeds from bank borrowings									0
Proceeds from issuance of common stock										0
Repayments of bank borrowings									0
Proceeds from issuance of senior notes											0
Deferred financing costs									0	0	0
Proceeds from building loan									0
Redemption of senior notes											0
Excess tax benefits									0		0
Equity proceeds from parent									9,714	31,696	27,404
Net payments for share-based compensation									0	0	0
Net cash provided by financing activities									9,714	31,696	27,404
Effect of exchange rate changes on cash									(74)	(736)	(65)
Net change in cash and cash equivalents									924	(488)	640
Cash and cash equivalents, beginning of year				152				640	152	640	0
Cash and cash equivalents, end of year	1,076				152				1,076	152	640
Eliminations [Member]
Cash flows from operating activities:
Net income (loss)									279,442	(133,368)	(214,957)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization									0	0	0
Write-down of oil and gas properties									0	0
Accretion expense									0	0	0
Deferred income tax (benefit) provision									0	0	0
Settlement of asset retirement obligations									0	0	0
Non-cash stock compensation expense									0	0	0
Excess tax benefits									0		0
Non-cash derivative income									0	0	0
Loss on early extinguishment of debt											0
Non-cash interest expense									0	0	0
Change in current income taxes									0	0	0
Non-cash income from investment in subsidiaries									(279,442)	133,368	214,957
Change in intercompany receivables/payables									0	0	0
(Increase) decrease in accounts receivable									0	0	0
(Increase) decrease in other current assets									0	0	0
(Increase) decrease in inventory									0	0	0
Decrease in accounts payable									0	0	0
Increase (decrease) in other current liabilities									0	0	0
Other									0	0	0
Net cash provided by operating activities									0	0	0
Cash flows from investing activities:
Investment in oil and gas properties									0	0	0
Proceeds from sale of oil and gas properties, net of expenses									0	0	0
Investment in fixed and other assets									0	0	0
Change in restricted funds									0	0	0
Investment in subsidiaries									9,714	31,696	27,404
Net cash used in investing activities									9,714	31,696	27,404
Cash flows from financing activities:
Proceeds from bank borrowings									0
Proceeds from issuance of common stock										0
Repayments of bank borrowings									0
Proceeds from issuance of senior notes											0
Deferred financing costs									0	0	0
Proceeds from building loan									0
Redemption of senior notes											0
Excess tax benefits									0		0
Equity proceeds from parent									(9,714)	(31,696)	(27,404)
Net payments for share-based compensation									0	0	0
Net cash provided by financing activities									(9,714)	(31,696)	(27,404)
Effect of exchange rate changes on cash									0	0	0
Net change in cash and cash equivalents									0	0	0
Cash and cash equivalents, beginning of year				$ 0				$ 0	0	0	0
Cash and cash equivalents, end of year	$ 0				$ 0				$ 0	$ 0	$ 0