Stone Energy (SGY) 10-K 9 Mar 18 2017 FY Annual report Financial data

DOCUMENT AND ENTITY INFORMATION

DOCUMENT AND ENTITY INFORMATION - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Mar. 09, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	STONE ENERGY CORPORATION
Trading Symbol	SGY
Entity Central Index Key	904,080
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		19,998,701
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 161.2

CONSOLIDATED BALANCE SHEET

CONSOLIDATED BALANCE SHEET - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 263,495
Restricted cash	18,742
Accounts receivable	39,258
Fair value of derivative contracts	879
Current income tax receivable	36,260
Other current assets	7,138
Total current assets	365,772
Oil and gas properties, full cost method of accounting:
Proved	713,157
Less: accumulated depreciation, depletion and amortization	(353,462)
Net proved oil and gas properties	359,695
Unevaluated	102,187
Other property and equipment, net of accumulated depreciation of $2,561 and $27,418, respectively	17,275
Other assets, net of accumulated depreciation and amortization of $5,360 at December 31, 2016	13,844
Total assets	858,773
Current liabilities:
Accounts payable to vendors	54,226
Undistributed oil and gas proceeds	5,142
Accrued interest	1,685
Fair value of derivative contracts	8,969
Asset retirement obligations	79,300
Current portion of long-term debt	425
Other current liabilities	22,579
Total current liabilities	172,326
Long-term debt	235,502
Asset retirement obligations	133,801
Fair value of derivative contracts	3,085
Other long-term liabilities	5,891
Total liabilities not subject to compromise	550,605
Liabilities subject to compromise	0
Total liabilities	550,605
Commitments and contingencies
Stockholders’ equity:
Common stock, value	200
Additional paid-in capital	555,607
Accumulated deficit	(247,639)
Total stockholders’ equity	308,168
Total liabilities and stockholders’ equity	$ 858,773
Predecessor
Current assets:
Cash and cash equivalents		$ 190,581
Restricted cash		0
Accounts receivable		48,464
Fair value of derivative contracts		0
Current income tax receivable		26,086
Other current assets		10,151
Total current assets		275,282
Oil and gas properties, full cost method of accounting:
Proved		9,616,236
Less: accumulated depreciation, depletion and amortization		(9,178,442)
Net proved oil and gas properties		437,794
Unevaluated		373,720
Other property and equipment, net of accumulated depreciation of $2,561 and $27,418, respectively		26,213
Other assets, net of accumulated depreciation and amortization of $5,360 at December 31, 2016		26,474
Total assets		1,139,483
Current liabilities:
Accounts payable to vendors		19,981
Undistributed oil and gas proceeds		15,073
Accrued interest		809
Fair value of derivative contracts		0
Asset retirement obligations		88,000
Current portion of long-term debt		408
Other current liabilities		18,602
Total current liabilities		142,873
Long-term debt		352,376
Asset retirement obligations		154,019
Fair value of derivative contracts		0
Other long-term liabilities		17,315
Total liabilities not subject to compromise		666,583
Liabilities subject to compromise		1,110,182
Total liabilities		1,776,765
Commitments and contingencies
Stockholders’ equity:
Common stock, value		56
Predecessor treasury stock (1,658 shares, at cost)		(860)
Additional paid-in capital		1,659,731
Accumulated deficit		(2,296,209)
Total stockholders’ equity		(637,282)
Total liabilities and stockholders’ equity		$ 1,139,483

CONSOLIDATED BALANCE SHEET (Par

CONSOLIDATED BALANCE SHEET (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Other property and equipment, accumulated depreciation	$ 2,561
Other assets, accumulated depreciation and amortization	$ 0
Common stock, par value (in usd per share)	$ 0.01
Common stock, shares authorized (in shares)	60,000,000
Common stock, shares issued (in shares)	19,998,019
Treasury stock, shares (in shares)	0
Predecessor
Other property and equipment, accumulated depreciation		$ 27,418
Other assets, accumulated depreciation and amortization		$ 5,360
Common stock, par value (in usd per share)		$ 0.01
Common stock, shares authorized (in shares)		30,000,000
Common stock, shares issued (in shares)		5,610,020
Treasury stock, shares (in shares)		1,658

CONSOLIDATED STATEMENT OF OPERA

CONSOLIDATED STATEMENT OF OPERATIONS - USD ($) shares in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenue:
Oil production		$ 211,792,000
Natural gas production		18,874,000
Natural gas liquids production		9,610,000
Other operational income		10,008,000
Derivative income, net		0
Total operating revenue		250,284,000
Operating expenses:
Lease operating expenses		49,800,000
Transportation, processing and gathering expenses		4,084,000
Production taxes		629,000
Depreciation, depletion and amortization		99,890,000
Write-down of oil and gas properties		256,435,000
Accretion expense		21,151,000
Salaries, general and administrative expenses		47,817,000
Incentive compensation expense		8,045,000
Restructuring fees		739,000
Other operational expenses		3,359,000
Derivative expense, net		13,388,000
Total operating expenses		505,337,000
Gain (loss) on Appalachia Properties divestiture		(105,000)
Income (loss) from operations		(255,158,000)
Other (income) expense:
Interest expense		11,744,000
Interest income		(998,000)
Other income		(1,156,000)
Other expense		1,230,000
Reorganization items, net		0
Total other (income) expense		10,820,000
Income (loss) before income taxes		(265,978,000)
Provision (benefit) for income taxes:
Current		(18,339,000)
Deferred		0
Total income taxes		(18,339,000)
Net income (loss)		$ (247,639,000)
Basic income (loss) per share (in usd per share)		$ (12.38)
Diluted income (loss) per share (in usd per share)		$ (12.38)
Average shares outstanding (in shares)		19,997
Average shares outstanding assuming dilution (in shares)		19,997
Predecessor
Operating revenue:
Oil production	$ 45,837,000		$ 281,246,000	$ 416,497,000
Natural gas production	13,476,000		64,601,000	83,509,000
Natural gas liquids production	8,706,000		28,888,000	32,322,000
Other operational income	903,000		2,657,000	4,369,000
Derivative income, net	0		0	7,952,000
Total operating revenue	68,922,000		377,392,000	544,649,000
Operating expenses:
Lease operating expenses	8,820,000		79,650,000	100,139,000
Transportation, processing and gathering expenses	6,933,000		27,760,000	58,847,000
Production taxes	682,000		3,148,000	6,877,000
Depreciation, depletion and amortization	37,429,000		220,079,000	281,688,000
Write-down of oil and gas properties	0		357,431,000	1,362,447,000
Accretion expense	5,447,000		40,229,000	25,988,000
Salaries, general and administrative expenses	9,629,000		58,928,000	69,384,000
Incentive compensation expense	2,008,000		13,475,000	2,242,000
Restructuring fees	0		29,597,000	0
Other operational expenses	530,000		55,453,000	2,360,000
Derivative expense, net	1,778,000		810,000	0
Total operating expenses	73,256,000		886,560,000	1,909,972,000
Gain (loss) on Appalachia Properties divestiture	213,453,000		0	0
Income (loss) from operations	209,119,000		(509,168,000)	(1,365,323,000)
Other (income) expense:
Interest expense	0		64,458,000	43,928,000
Interest income	(45,000)		(550,000)	(580,000)
Other income	(315,000)		(1,439,000)	(1,783,000)
Other expense	13,336,000		596,000	434,000
Reorganization items, net	(437,744,000)		10,947,000	0
Total other (income) expense	(424,768,000)		74,012,000	41,999,000
Income (loss) before income taxes	633,887,000		(583,180,000)	(1,407,322,000)
Provision (benefit) for income taxes:
Current	3,570,000		(5,674,000)	(44,096,000)
Deferred	0		13,080,000	(272,311,000)
Total income taxes	3,570,000		7,406,000	(316,407,000)
Net income (loss)	$ 630,317,000		$ (590,586,000)	$ (1,090,915,000)
Basic income (loss) per share (in usd per share)	$ 110.99		$ (105.63)	$ (197.45)
Diluted income (loss) per share (in usd per share)	$ 110.99		$ (105.63)	$ (197.45)
Average shares outstanding (in shares)	5,634		5,591	5,525
Average shares outstanding assuming dilution (in shares)	5,634		5,591	5,525

CONSOLIDATED STATEMENT OF COMPR

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net income (loss)		$ (247,639)
Other comprehensive income (loss), net of tax effect:
Derivatives		0
Foreign currency translation		0
Comprehensive income (loss)		$ (247,639)
Predecessor
Net income (loss)	$ 630,317		$ (590,586)	$ (1,090,915)
Other comprehensive income (loss), net of tax effect:
Derivatives	0		(24,025)	(62,758)
Foreign currency translation	0		6,073	(2,605)
Comprehensive income (loss)	$ 630,317		$ (608,538)	$ (1,156,278)

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($)	Total	Common Stock	Treasury Stock	Additional Paid-In Capital	Accumulated Deficit	Accumulated Other Comprehensive Income (Loss)
Beginning Balance (Predecessor) at Dec. 31, 2014	$ 1,101,603,000	$ 55,000	$ (860,000)	$ 1,633,801,000	$ (614,708,000)	$ 83,315,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) | Predecessor	(1,090,915,000)				(1,090,915,000)
Adjustment for fair value accounting of derivatives, net of tax | Predecessor	(62,758,000)					(62,758,000)
Adjustment for foreign currency translation, net of tax | Predecessor	(2,605,000)					(2,605,000)
Lapsing of forfeiture restrictions of restricted stock | Predecessor	(2,638,000)			(2,638,000)
Amortization of stock compensation expense | Predecessor	17,524,000			17,524,000
Ending Balance (Predecessor) at Dec. 31, 2015	(39,789,000)	55,000	(860,000)	1,648,687,000	(1,705,623,000)	17,952,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) | Predecessor	(590,586,000)				(590,586,000)
Adjustment for fair value accounting of derivatives, net of tax | Predecessor	(24,025,000)					(24,025,000)
Adjustment for foreign currency translation, net of tax | Predecessor	6,073,000					$ 6,073,000
Lapsing of forfeiture restrictions of restricted stock | Predecessor	(731,000)	1,000		(732,000)
Amortization of stock compensation expense | Predecessor	11,776,000			11,776,000
Ending Balance (Predecessor) at Dec. 31, 2016	(637,282,000)	56,000	(860,000)	1,659,731,000	(2,296,209,000)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) | Predecessor	630,317,000				630,317,000
Adjustment for fair value accounting of derivatives, net of tax | Predecessor	0
Adjustment for foreign currency translation, net of tax | Predecessor	0
Lapsing of forfeiture restrictions of restricted stock | Predecessor	(172,000)			(172,000)
Amortization of stock compensation expense | Predecessor	3,527,000			3,527,000
Issuance of Successor common stock and warrants	554,737,000	200,000		554,537,000
Ending Balance (Predecessor) at Feb. 28, 2017	(3,610,000)	56,000	(860,000)	1,663,086,000	(1,665,892,000)
Ending Balance at Feb. 28, 2017	554,737,000	200,000		554,537,000	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cancellation of Predecessor equity | Predecessor	3,610,000	(56,000)	$ 860,000	(1,663,086,000)	1,665,892,000
Net income (loss)	(247,639,000)				(247,639,000)
Adjustment for fair value accounting of derivatives, net of tax	0
Adjustment for foreign currency translation, net of tax	0
Lapsing of forfeiture restrictions of restricted stock	(19,000)			(19,000)
Amortization of stock compensation expense	1,272,000			1,272,000
Stock issuance costs - Talos combination	(183,000)			(183,000)
Ending Balance at Dec. 31, 2017	$ 308,168,000	$ 200,000		$ 555,607,000	$ (247,639,000)

CONSOLIDATED STATEMENT OF CASH

CONSOLIDATED STATEMENT OF CASH FLOWS - USD ($)	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income (loss)		$ (247,639,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		99,890,000
Write-down of oil and gas properties		256,435,000
Accretion expense		21,151,000
Deferred income tax provision (benefit)		0
(Gain) loss on sale of oil and gas properties		105,000
Settlement of asset retirement obligations		(80,671,000)
Non-cash stock compensation expense		1,252,000
Excess tax benefits		0
Non-cash derivative expense		15,548,000
Non-cash interest expense		4,000
Non-cash reorganization items		0
Other non-cash expense		1,245,000
Change in current income taxes		(13,744,000)
(Increase) decrease in accounts receivable		2,455,000
(Increase) decrease in other current assets		4,648,000
Decrease in inventory		0
Increase (decrease) in accounts payable		17,113,000
Increase (decrease) in other current liabilities		10,677,000
Investment in derivative contracts		(2,416,000)
Other		3,023,000
Net cash provided by (used in) operating activities		89,076,000
Cash flows from investing activities:
Investment in oil and gas properties		(65,282,000)
Proceeds from sale of oil and gas properties, net of expenses		20,633,000
Investment in fixed and other assets		(163,000)
Change in restricted funds		56,805,000
Net cash provided by (used in) investing activities		11,993,000
Cash flows from financing activities:
Proceeds from bank borrowings		0
Repayments of bank borrowings		0
Proceeds from building loan		0
Repayments of building loan		(337,000)
Cash payment to noteholders		0
Stock issuance costs - Talos combination		(184,000)
Debt issuance costs		0
Excess tax benefits		0
Net payments for share-based compensation		(19,000)
Net cash provided by (used in) financing activities		(540,000)
Effect of exchange rate changes on cash		0
Net change in cash and cash equivalents		100,529,000
Cash and cash equivalents, beginning of period		162,966,000
Cash and cash equivalents, end of period	$ 162,966,000	263,495,000
Supplemental cash flow information:
Cash paid for interest, net of amount capitalized		(10,256,000)
Cash refunded for income taxes, net of amounts paid		5,420,000
Predecessor
Cash flows from operating activities:
Net income (loss)	630,317,000		$ (590,586,000)	$ (1,090,915,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	37,429,000		220,079,000	281,688,000
Write-down of oil and gas properties	0		357,431,000	1,362,447,000
Accretion expense	5,447,000		40,229,000	25,988,000
Deferred income tax provision (benefit)	0		13,080,000	(272,311,000)
(Gain) loss on sale of oil and gas properties	(213,453,000)		0	0
Settlement of asset retirement obligations	(3,641,000)		(20,514,000)	(72,382,000)
Non-cash stock compensation expense	2,645,000		8,443,000	12,324,000
Excess tax benefits	0		0	(1,586,000)
Non-cash derivative expense	1,778,000		1,471,000	16,440,000
Non-cash interest expense	0		18,404,000	17,788,000
Non-cash reorganization items	(458,677,000)		8,332,000	0
Other non-cash expense	172,000		6,248,000	0
Change in current income taxes	3,570,000		20,088,000	(37,377,000)
(Increase) decrease in accounts receivable	6,354,000		(1,412,000)	43,724,000
(Increase) decrease in other current assets	(2,274,000)		(3,493,000)	1,767,000
Decrease in inventory	0		0	1,304,000
Increase (decrease) in accounts payable	(4,652,000)		1,026,000	(14,582,000)
Increase (decrease) in other current liabilities	(9,653,000)		9,897,000	(25,936,000)
Investment in derivative contracts	(3,736,000)		0	0
Other	2,490,000		(10,135,000)	(907,000)
Net cash provided by (used in) operating activities	(5,884,000)		78,588,000	247,474,000
Cash flows from investing activities:
Investment in oil and gas properties	(8,754,000)		(237,952,000)	(522,047,000)
Proceeds from sale of oil and gas properties, net of expenses	505,383,000		0	22,839,000
Investment in fixed and other assets	(61,000)		(1,266,000)	(1,549,000)
Change in restricted funds	(75,547,000)		1,046,000	179,467,000
Net cash provided by (used in) investing activities	421,021,000		(238,172,000)	(321,290,000)
Cash flows from financing activities:
Proceeds from bank borrowings	0		477,000,000	5,000,000
Repayments of bank borrowings	(341,500,000)		(135,500,000)	(5,000,000)
Proceeds from building loan	0		0	11,770,000
Repayments of building loan	(24,000)		(423,000)	0
Cash payment to noteholders	(100,000,000)		0	0
Stock issuance costs - Talos combination	0		0	0
Debt issuance costs	(1,055,000)		(900,000)	(68,000)
Excess tax benefits	0		0	1,586,000
Net payments for share-based compensation	(173,000)		(762,000)	(3,127,000)
Net cash provided by (used in) financing activities	(442,752,000)		339,415,000	10,161,000
Effect of exchange rate changes on cash	0		(9,000)	(74,000)
Net change in cash and cash equivalents	(27,615,000)		179,822,000	(63,729,000)
Cash and cash equivalents, beginning of period	190,581,000	$ 162,966,000	10,759,000	74,488,000
Cash and cash equivalents, end of period	162,966,000		190,581,000	10,759,000
Supplemental cash flow information:
Cash paid for interest, net of amount capitalized	0		(32,130,000)	(34,394,000)
Cash refunded for income taxes, net of amounts paid	$ 0		$ 25,762,000	$ 7,212,000

ORGANIZATION AND SUMMARY OF SIG

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Operations Stone Energy Corporation (“Stone” or the “Company”) is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the Gulf of Mexico (the “GOM”) Basin since our incorporation in 1993 and have established technical and operational expertise in this area. We leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific plays of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. At December 31, 2016, we had producing properties and acreage in the Marcellus and Utica Shales in Appalachia. In connection with our restructuring efforts, we completed the sale of the Appalachia Properties (as defined in Note 2 – Reorganization ) to EQT Corporation, through its wholly owned subsidiary EQT Production Company (“EQT”), on February 27, 2017 for net cash consideration of approximately $522.5 million . See Note 2 – Reorganization and Note 4 – Divestiture for additional information on the sale of the Appalachia Properties. 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 an additional office in New Orleans, Louisiana. Pending Combination with Talos On November 21, 2017, Stone and certain of its subsidiaries entered into a series of related agreements pertaining to a business combination with Talos Energy LLC (“Talos Energy”) and its indirect wholly owned subsidiary Talos Production LLC (“Talos Production” and, together with Talos Energy, “Talos”). Talos Energy is controlled indirectly by entities controlled by Apollo Management VII, L.P. (“Apollo VII”), Apollo Commodities Management, L.P., with respect to Series I (together with Apollo VII, “Apollo Management”) and Riverstone Energy Partners V, L.P. (“Riverstone”). Stone, Sailfish Energy Holdings Corporation (“New Talos”), a direct wholly owned subsidiary of Stone, and Sailfish Merger Sub Corporation, a direct wholly owned subsidiary of New Talos, entered into a Transaction Agreement (the “Transaction Agreement”) with Talos on November 21, 2017, which contemplates a series of transactions (the “Transactions”) occurring on the date of closing of the Transaction Agreement (the “Closing”) that will result in such business combination. Stone and Talos will become wholly owned subsidiaries of New Talos. At the time of the Closing, the parties intend that New Talos will become a publicly traded entity named Talos Energy, Inc. The Transactions include (i) the contribution of 100% of the equity interests in Talos Production to New Talos in exchange for shares of New Talos common stock, (ii) the contribution by entities controlled by or affiliated with Apollo Management (the “Apollo Funds”) and Riverstone (the “Riverstone Funds”) of $102 million in aggregate principal amount of 9.75% Senior Notes due 2022 issued by Talos Production and Talos Production Finance Inc. (together, the “the Talos Issuers”) to New Talos in exchange for shares of New Talos common stock, (iii) the exchange of the second lien bridge loans due 2022 issued by the Talos Issuers for newly issued 11% second lien notes issued by the Talos Issuers, and (iv) the exchange of the 7.50% Senior Second Lien Notes due 2022 (the “2022 Second Lien Notes”) issued by Stone for newly issued 11% second lien notes issued by the Talos Issuers. Under the terms of the Transaction Agreement, each outstanding share of Stone common stock will be exchanged for one share of New Talos common stock and the current Talos stakeholders (including the Apollo Funds and the Riverstone Funds) will be issued an aggregate of approximately 34.1 million common shares of New Talos. After the completion of the Transactions contemplated by the Transaction Agreement, holders of Stone common stock immediately prior to the combination will collectively hold 37% of the outstanding New Talos common stock and Talos Energy stakeholders will hold 63% of the outstanding New Talos common stock. Outstanding warrants to acquire Stone common stock will become warrants to acquire New Talos common stock with terms and conditions substantially identical to their existing terms and conditions. The combination was unanimously approved by the boards of directors of Stone and Talos Energy. Completion of the combination is subject to the approval of Stone shareholders, the consummation of a tender offer and consent solicitation for Stone’s 2022 Second Lien Notes, certain regulatory approvals and other customary conditions. Franklin Advisers, Inc. and MacKay Shields LLC, as investment managers for approximately 53% of the outstanding common shares of Stone as of September 30, 2017, entered into voting agreements to vote in favor of the combination, subject to certain conditions. The Transaction Agreement contains certain termination rights for Stone and Talos Energy. Stone may be required to pay a termination fee and to reimburse transaction expenses to Talos Energy if the Transaction Agreement is terminated under certain circumstances. The combination is expected to close in the second quarter of 2018. We cannot provide any assurance that the combination will be completed on the terms or timeline currently contemplated, or at all. Reorganization and Emergence from Voluntary Chapter 11 Proceedings On December 14, 2016 (the “Petition Date”), the Company and its subsidiaries Stone Energy Offshore, L.L.C. (“Stone Offshore”) and Stone Energy Holding, L.L.C. (together with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) seeking relief under the provisions of Chapter 11 of Title 11 (“Chapter 11”) of the United States Bankruptcy Code (the “Bankruptcy Code”). On February 15, 2017, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, dated December 28, 2016 (the “Plan”), as modified by the Confirmation Order, and on February 28, 2017, the Plan became effective (the “Effective Date”) and the Debtors emerged from bankruptcy, with the bankruptcy cases then being closed by Final Decree Closing Chapter 11 Cases and Terminating Claims Agent Services entered by the Bankruptcy Court on April 20, 2017. See Note 2 – Reorganization for additional details. Upon emergence from bankruptcy, the Company adopted fresh start accounting in accordance with the provisions of Accounting Standards Codification (“ASC”) 852, “ Reorganizations ”, which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. As a result of the adoption of fresh start accounting, the Company’s consolidated financial statements subsequent to February 28, 2017 will not be comparable to its financial statements prior to that date. See Note 3 – Fresh Start Accounting for further details on the impact of fresh start accounting on the Company’s consolidated financial statements. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017. Summary of Significant Accounting Policies 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 Offshore, Stone Energy Holding, L.L.C. and Stone Energy Canada, ULC. On August 29, 2016, our subsidiaries SEO A LLC and SEO B LLC were merged into Stone Offshore. On December 2, 2016, Stone Energy Canada, ULC was dissolved. All intercompany balances have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation. Reorganization and Fresh Start Accounting: For periods subsequent to the Chapter 11 filing, but prior to emergence, ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees and other expenses incurred in the Chapter 11 cases, and unamortized debt issuance costs, premiums and discounts associated with debt classified as liabilities subject to compromise, have been recorded as reorganization items on the consolidated statement of operations for the applicable periods. In addition, pre-petition obligations that were to be impacted by the Chapter 11 process were classified on the consolidated balance sheet at December 31, 2016 as liabilities subject to compromise. See Note 2 – Reorganization and Note 3 – Fresh Start Accounting for more information regarding reorganization items and liabilities subject to compromise. Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with the provisions of ASC 852, as (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the post-petition liabilities and allowed claims. The Company applied fresh start accounting as of February 28, 2017. Fresh start accounting required the Company to present its assets, liabilities and equity as if it were a new entity upon emergence from bankruptcy, with no beginning retained earnings or deficit as of the fresh start reporting date. The new entity is referred to as Successor or Successor Company, and includes the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to Predecessor or Predecessor Company relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017. The Chapter 11 proceedings did not include our former foreign subsidiary Stone Energy Canada, ULC. This subsidiary had no significant activity during 2016, except for the reclassification of approximately $6.1 million of losses related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the substantial liquidation of Stone Energy Canada, ULC. Stone Energy Canada, ULC was dissolved on December 2, 2016. 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. The Company bases its estimates on historical experience and on various assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects are uncertain and, accordingly, these estimates may change as new events occur, as additional information is obtained and as the Company’s operating environment changes. 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, estimated fair value of derivative contracts, contingencies and fair value estimates, including estimates of reorganization value, enterprise value and the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting. 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, 2017 and 2016 , 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. On February 28, 2017, the Company emerged from bankruptcy and adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting date, February 28, 2017. See Note 3 – Fresh Start Accounting for a detailed discussion of the fair value approaches used by the Company. 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. On December 31, 2017, we had $18.7 million of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the terms of the Amended Credit Agreement (as defined in Note 13 – Debt ). 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, timing of abandonment 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. Derivative Instruments and Hedging Activities: Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. Accordingly, the contracts were recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. Monthly settlements of effective hedges were reflected in revenue from oil and natural gas production. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements of these derivative contracts are recorded in earnings through derivative income (expense). 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. See Recently Issued Accounting Standards below. 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 costs relative to successful wells are capitalized and recovered through DD&A, although for 2015 , 2016 and 2017 , 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 (the “IRC”) 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. See Note 12 – Income Taxes for a discussion of the effects of the December 22, 2017 enactment of the Tax Cuts and Jobs Act. Share-Based Compensation: We record share-based compensation using the grant date fair value of issued stock options, stock awards, restricted stock and restricted stock units 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 stock awards, restricted stock and restricted stock units is typically determined based on the average of our high and low stock prices on the grant date. Combination Transaction Costs: In general, acquisition-related costs are expensed in the periods in which the costs are incurred and the services are rendered. However, some direct costs of an acquisition, such as the cost of registering and issuing equity securities to effect a business combination, are recorded as a reduction of additional paid-in-capital when incurred. Recently Issued Accounting Standards: In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “ Revenue from Contracts with Customers (Topic 606) ” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers including the disaggregation of revenue and remaining performance obligations. 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, and is effective for interim and annual periods beginning on or after December 15, 2017. We adopted this new standard on January 1, 2018 using the modified retrospective approach. The adoption of the standard did not have a material effect on our financial position, results of operations or cash flows, but will result in increased disclosures related to revenue recognition policies and disaggregation of revenues. In February 2016, the FASB issued ASU 2016-02, “ Leases (Topic 842) ” to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public companies for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements and related disclosures. In March 2016, the FASB issued ASU 2016-09, “ Compensation – Stock Compensation (Topic 718) ” to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. ASU 2016-09 became effective for us on January 1, 2017. Under ASU 2016-09, we elected to not apply a forfeiture estimate and will recognize a credit in compensation expense to the extent awards are forfeited. The implementation of this new standard did not have a material effect on our financial statements or related disclosures. In August 2017, the FASB issued ASU 2017-12, “ Derivatives and Hedging (Topic 815) ” to improve the financial reporting of hedging relationships to better reflect an entity’s hedging strategies. The standard expands an entity’s ability to apply hedge accounting for both non-financial and financial risk components and amends the presentation and disclosure requirements. Additionally, ASU 2017-12 eliminates the need to separately measure and report hedge ineffectiveness and generally requires the entire change in fair value of a hedging instrument to be recorded in the same income statement line as the earnings effect of the hedged item. The standard is effective for public companies for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted. The standard must be adopted by applying a modified retrospective approach to existing designated hedging relationships as of the adoption date, with a cumulative effect adjustment recorded to opening retained earnings as of the initial adoption date. We are currently evaluating the effect that this new standard may have on our financial statements and related disclosures.

REORGANIZATION

REORGANIZATION	12 Months Ended
	Dec. 31, 2017
Reorganizations [Abstract]
REORGANIZATION	REORGANIZATION On December 14, 2016, the Debtors filed the Bankruptcy Petitions seeking relief under the provisions of Chapter 11 of the Bankruptcy Code to pursue a prepackaged plan of reorganization. On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan, and on February 28, 2017, the Plan became effective and the Debtors emerged from bankruptcy. Prior to filing the Bankruptcy Petitions, on October 20, 2016, the Debtors and certain holders of the Company’s 1¾% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”) and the Company’s 7 1 ⁄ 2 % Senior Notes due 2022 (the “2022 Notes”) (collectively, the “Notes” and the holders thereof, the “Noteholders”) and the lenders (the “Banks”) under the Fourth Amended and Restated Credit Agreement, dated as of June 24, 2014, as amended, modified, or otherwise supplemented from time to time (the “Pre-Emergence Credit Agreement”), entered into an Amended and Restated Restructuring Support Agreement (the “A&R RSA”). The A&R RSA contained certain covenants on the part of the Company and the Noteholders and Banks who are signatories to the A&R RSA, including that such Noteholders and Banks would support the Company’s sale of Stone’s producing properties and acreage, including approximately 86,000 net acres, in the Appalachia regions of Pennsylvania and West Virginia (the “Appalachia Properties”) to TH Exploration III, LLC, an affiliate of Tug Hill, Inc. (“Tug Hill”), pursuant to the terms of a Purchase and Sale Agreement dated October 20, 2016, as amended on December 9, 2016 (the “Tug Hill PSA”) for a purchase price of at least $350 million and approval of the Bankruptcy Court. Pursuant to the terms of the Tug Hill PSA, Stone agreed to sell the Appalachia Properties to Tug Hill for $360 million in cash, subject to customary purchase price adjustments. Pursuant to Bankruptcy Court orders dated January 11, 2017 and January 31, 2017, two additional bidders were allowed to participate in competitive bidding on the Appalachia Properties. On January 18, 2017, the Bankruptcy Court approved certain bidding procedures (the “Bidding Procedures”) in connection with the sale of the Appalachia Properties. In accordance with the Bidding Procedures, Stone conducted an auction for the sale of the Appalachia Properties on February 8, 2017 and upon conclusion, selected the final bid submitted by EQT, with a final purchase price of $527 million in cash, subject to customary purchase price adjustments and approval by the Bankruptcy Court, with an upward adjustment to the purchase price of up to $16 million in an amount equal to certain downward adjustments, as the prevailing bid. On February 9, 2017, the Company entered into a purchase and sale agreement with EQT (the “EQT PSA”), reflecting the terms of the prevailing bid and on February 10, 2017, the Bankruptcy Court entered a sale order approving the sale of the Appalachia Properties to EQT. We completed the sale of the Appalachia Properties to EQT on February 27, 2017 for net cash consideration of approximately $522.5 million . At the close of the sale of the Appalachia Properties, the Tug Hill PSA was terminated, and the Company used a portion of the cash consideration received to pay Tug Hill a break-up fee and expense reimbursements totaling approximately $11.5 million , which is recognized as other expense in the statement of operations for the period of January 1, 2017 through February 28, 2017 (Predecessor). See Note 4 – Divestiture for additional information on the sale of the Appalachia Properties. Upon emergence from bankruptcy, pursuant to the terms of the Plan, the following significant transactions occurred: • Shares of the Predecessor Company’s issued and outstanding common stock immediately prior to the Effective Date were cancelled, and on the Effective Date, reorganized Stone issued an aggregate of 20.0 million shares of new common stock (the “New Common Stock”). • The Predecessor Company’s 2022 Notes and 2017 Convertible Notes were cancelled and the holders of such notes received their pro rata share of (a) $ 100 million of cash, (b) 19.0 million shares of New Common Stock, representing 95% of the New Common Stock and (c) $ 225 million of the 2022 Second Lien Notes. • The Predecessor Company’s common stockholders received their pro rata share of 1.0 million shares of the New Common Stock, representing 5% of the New Common Stock, and warrants to purchase approximately 3.5 million shares of New Common Stock. The warrants have an exercise price of $42.04 per share and a term of four years , unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company. • The Predecessor Company’s Pre-Emergence Credit Agreement was amended and restated as the Amended Credit Agreement (as defined in Note 13 – Debt ). The obligations owed to the lenders under the Pre-Emergence Credit Agreement were converted to obligations under the Amended Credit Agreement. • All claims of creditors with unsecured claims, other than claims by the holders of the 2022 Notes and 2017 Convertible Notes, including vendors, were unaltered and paid in full in the ordinary course of business to the extent such claims were undisputed. For further information regarding the equity and debt instruments of the Predecessor Company and the Successor Company, see Note 5 – Stockholders’ Equity and Note 13 – Debt .

FRESH START ACCOUNTING

FRESH START ACCOUNTING	12 Months Ended
	Dec. 31, 2017
Reorganizations [Abstract]
FRESH START ACCOUNTING	FRESH START ACCOUNTING Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with the provisions of ASC 852, “ Reorganizations ” as (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the post-petition liabilities and allowed claims. See Note 2 – Reorganization for the terms of the Plan. The Company applied fresh start accounting as of February 28, 2017. Fresh start accounting required the Company to present its assets, liabilities and equity as if it were a new entity upon emergence from bankruptcy, with no beginning retained earnings or deficit as of the fresh start reporting date. As described in Note 1 – Organization and Summary of Significant Accounting Policies , the new entity is referred to as Successor or Successor Company, and includes the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to Predecessor or Predecessor Company relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017. Reorganization Value Under fresh start accounting, reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately after restructuring. Upon application of fresh start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values. The Company’s reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s long-term debt and stockholders’ equity. In support of the Plan, the Company estimated the enterprise value of the core assets (as defined in the Plan) of the Successor Company to be in the range of $300 million to $450 million , which was subsequently approved by the Bankruptcy Court. This valuation analysis was prepared using reserve information, development schedules, other financial information and financial projections and applying standard valuation techniques, including net asset value analysis, precedent transactions analyses and public comparable company analyses. Based on the estimates and assumptions used in determining the enterprise value, the Company ultimately estimated the enterprise value of the Successor Company’s core assets to be approximately $420 million . Valuation of Assets The Company’s principal assets are its oil and gas properties, which the Company accounts for under the full cost accounting method. With the assistance of valuation experts, the Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the bankruptcy emergence date. The fair value analysis performed by valuation experts was based on the Company’s estimates of reserves as developed internally by the Company’s reserve engineers. For purposes of estimating the fair value of the Company’s proved, probable and possible reserves, an income approach was used, which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, risked by reserve category and discounted using a weighted average cost of capital of 12.5% . The discount factor was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar market participants. Future revenues were based upon forward strip oil and natural gas prices as of the emergence date, adjusted for differentials realized by the Company, and adjusted for a 2% annual escalation after 2021. Development and operating costs were based on the Company’s recent cost trends adjusted for inflation. The discounted cash flow models also included estimates not typically included in proved reserves such as depreciation and income tax expenses. The proved reserve locations were limited to wells expected to be drilled in the Company’s five year development plan. As a result of this analysis, the Company concluded the fair value of its proved reserves was $380.8 million and the fair value of its probable and possible reserves was $16.8 million as of the Effective Date. The Company also reviewed its undeveloped leasehold acreage and inventory. An analysis of comparable market transactions indicated a fair value of undeveloped acreage and inventory totaling $80.2 million . These amounts are reflected in the Fresh Start Adjustments item number 12 below. The fair value of the Company’s asset retirement obligations was estimated at $290.1 million and was based on estimated plugging and abandonment costs as of the Effective Date, adjusted for inflation and discounted at the Successor Company’s credit-adjusted risk free rate of 12% . See further discussion in Fresh Start Adjustments below for details on the specific assumptions used in the valuation of the Company’s various other assets. The following table reconciles the enterprise value per the Plan to the estimated fair value (for fresh start accounting purposes) of the Successor Company’s common stock as of February 28, 2017 (in thousands, except per share value): February 28, 2017 Enterprise value $ 419,720 Plus: Cash and other assets 371,278 Less: Fair value of debt (236,261 ) Less: Fair value of warrants (15,648 ) Fair value of Successor common stock $ 539,089 Shares issued upon emergence 20,000 Per share value $ 26.95 The following table reconciles the enterprise value per the Plan to the estimated reorganization value as of the Effective Date (in thousands): February 28, 2017 Enterprise value $ 419,720 Plus: Cash and other assets 371,278 Plus: Asset retirement obligations (current and long-term) 290,067 Plus: Working capital and other liabilities 58,055 Reorganization value of Successor assets $ 1,139,120 Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond our control. Accordingly, the estimates set forth herein are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized. Condensed Consolidated Balance Sheet The adjustments set forth in the following condensed consolidated balance sheet reflect the effects of the transactions contemplated by the Plan and carried out by the Company (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions or inputs. The following table reflects the reorganization and application of ASC 852 on our consolidated balance sheet as of February 28, 2017 (in thousands): Predecessor Company Reorganization Adjustments Fresh Start Adjustments Successor Company Assets Current assets: Cash and cash equivalents $ 198,571 $ (35,605 ) (1) $ — $ 162,966 Restricted cash — 75,547 (1) — 75,547 Accounts receivable 42,808 9,301 (2) — 52,109 Fair value of derivative contracts 1,267 — — 1,267 Current income tax receivable 22,516 — — 22,516 Other current assets 11,033 875 (3) (124 ) (12) 11,784 Total current assets 276,195 50,118 (124 ) 326,189 Oil and gas properties, full cost method of accounting: Proved 9,633,907 (188,933 ) (1) (8,774,122 ) (12) 670,852 Less: accumulated DD&A (9,215,679 ) — 9,215,679 (12) — Net proved oil and gas properties 418,228 (188,933 ) 441,557 670,852 Unevaluated 371,140 (127,838 ) (1) (146,292 ) (12) 97,010 Other property and equipment, net 25,586 (101 ) (4) (4,423 ) (13) 21,062 Fair value of derivative contracts 1,819 — — 1,819 Other assets, net 26,516 (4,328 ) (5) — 22,188 Total assets $ 1,119,484 $ (271,082 ) $ 290,718 $ 1,139,120 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable to vendors $ 20,512 $ — $ — $ 20,512 Undistributed oil and gas proceeds 5,917 (4,139 ) (1) — 1,778 Accrued interest 266 — — 266 Asset retirement obligations 92,597 — — 92,597 Fair value of derivative contracts 476 — — 476 Current portion of long-term debt 411 — — 411 Other current liabilities 17,032 (195 ) (6) — 16,837 Total current liabilities 137,211 (4,334 ) — 132,877 Long-term debt 352,350 (116,500 ) (7) — 235,850 Asset retirement obligations 151,228 (8,672 ) (1) 54,914 (14) 197,470 Fair value of derivative contracts 653 — — 653 Other long-term liabilities 17,533 — — 17,533 Total liabilities not subject to compromise 658,975 (129,506 ) 54,914 584,383 Liabilities subject to compromise 1,110,182 (1,110,182 ) (8) — — Total liabilities 1,769,157 (1,239,688 ) 54,914 584,383 Commitments and contingencies Stockholders’ equity: Common stock (Predecessor) 56 (56 ) (9) — — Treasury stock (Predecessor) (860 ) 860 (9) — — Additional paid-in capital (Predecessor) 1,660,810 (1,660,810 ) (9) — — Common stock (Successor) — 200 (10) — 200 Additional paid-in capital (Successor) — 554,537 (10) — 554,537 Accumulated deficit (2,309,679 ) 2,073,875 (11) 235,804 (15) — Total stockholders’ equity (649,673 ) 968,606 235,804 554,737 Total liabilities and stockholders’ equity $ 1,119,484 $ (271,082 ) $ 290,718 $ 1,139,120 Reorganization Adjustments 1. Reflects the net cash proceeds received from the sale of the Appalachia Properties in connection with the Plan and net cash payments made as of the Effective Date from implementation of the Plan (in thousands): Sources: Net cash proceeds from sale of Appalachia Properties (a) $ 512,472 Total sources 512,472 Uses: Cash transferred to restricted account (b) 75,547 Break-up fee to Tug Hill 10,800 Repayment of outstanding borrowings under Pre-Emergence Credit Agreement 341,500 Repayment of 2017 Convertible Notes and 2022 Notes 100,000 Other fees and expenses (c) 20,230 Total uses 548,077 Net uses $ (35,605 ) (a) The closing of the sale of the Appalachia Properties occurred on February 27, 2017, but as emergence was contingent on such closing, the effects of the transaction are reflected as reorganization adjustments. See Note 4 – Divestiture for additional details on the sale. Total consideration received for the sale of the Appalachia Properties of $522.5 million included cash consideration of $512.5 million received at closing and a $10.0 million indemnity escrow which was released subsequent to emergence from bankruptcy (see Reorganization Adjustments item number 2 below). (b) Reflects the movement of $75.0 million of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the provisions of the Amended Credit Agreement (as defined in Note 13 – Debt ), and $0.5 million held in a restricted cash account for certain cure amounts in connection with the Chapter 11 proceedings. (c) Other fees and expenses include approximately $15.2 million of emergence and success fees, $2.7 million of professional fees and $2.4 million of payments made to seismic providers in settlement of their bankruptcy claims. 2. Reflects a receivable for a $10.0 million indemnity escrow with release delayed until emergence from bankruptcy, net of a $0.7 million reimbursement to Tug Hill in connection with the sale of the Appalachia Properties (see Note 4 – Divestiture ). 3. Reflects the payment of a claim to a seismic provider as a prepayment/deposit. 4. Reflects the sale of vehicles in connection with the sale of the Appalachia Properties. 5. Reflects the write-off of $2.6 million of unamortized debt issuance costs related to the Pre-Emergence Credit Agreement and the reversal of a $1.8 million prepayment made to Tug Hill in October 2016. 6. Reflects the accrual of $2.0 million in expected bonus payments under the KEIP (as defined in Note 15 – Employee Benefit Plans ) and a $0.4 million termination fee in connection with the early termination of an office lease, less the settlement of a property tax accrual of $2.6 million in connection with the sale of the Appalachia Properties. 7. Reflects the repayment of $341.5 million of outstanding borrowings under the Pre-Emergence Credit Agreement and the issuance of $225 million of 2022 Second Lien Notes as part of the settlement of the Predecessor Company 2017 Convertible Notes and 2022 Notes. 8. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands): 1 ¾% Senior Convertible Notes due 2017 $ 300,000 7 ½% Senior Notes due 2022 775,000 Accrued interest 35,182 Liabilities subject to compromise of the Predecessor Company 1,110,182 Cash payment to senior noteholders (100,000 ) Issuance of 2022 Second Lien Notes to former holders of the senior notes (225,000 ) Fair value of equity issued to unsecured creditors (539,089 ) Fair value of warrants issued to unsecured creditors (15,648 ) Gain on settlement of liabilities subject to compromise $ 230,445 9. Reflects the cancellation of the Predecessor Company’s common stock, treasury stock and additional paid-in capital. 10. Reflects the issuance of Successor Company equity. In accordance with the Plan, the Successor Company issued 19.0 million shares of New Common Stock to the former holders of the 2017 Convertible Notes and the 2022 Notes and 1.0 million shares of New Common Stock to the Predecessor Company’s common stockholders. These amounts are subject to dilution by warrants issued to the Predecessor Company common stockholders, totaling approximately 3.5 million shares, with an exercise price of $42.04 per share and a term of four years. The fair value of the warrants was estimated at $4.43 per share using a Black-Scholes-Merton valuation model. 11. Reflects the cumulative impact of the reorganization adjustments discussed above (in thousands): Gain on settlement of liabilities subject to compromise $ 230,445 Professional and other fees paid at emergence (10,648 ) Write-off of unamortized debt issuance costs (2,577 ) Other reorganization adjustments (1,915 ) Net impact to reorganization items 215,305 Gain on sale of Appalachia Properties 213,453 Cancellation of Predecessor Company equity 1,662,282 Other adjustments to accumulated deficit (17,165 ) Net impact to accumulated deficit $ 2,073,875 Fresh Start Adjustments 12. Fair value adjustments to oil and gas properties, associated inventory and unproved acreage. See above for a detailed discussion of the fair value methodology. 13. Fair value adjustment for an office building owned by the Company. The income and sales comparison approaches were used in determining the fair value, using anticipated future earnings and an appropriate expected rate of return, as well as relying upon recent sales or offerings of similar assets. 14. Fair value adjustments to the Company’s asset retirement obligations using estimated plugging and abandonment costs as of the Effective Date, adjusted for inflation and discounted at the Successor Company’s credit-adjusted risk free rate. 15. Reflects the cumulative effect of the fresh start accounting adjustments discussed above. Reorganization Items Reorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan and are classified as “Reorganization items, net” in the Company’s consolidated statement of operations. The following table summarizes reorganization items, net (in thousands): Predecessor Period from Gain on settlement of liabilities subject to compromise $ 230,445 Fresh start valuation adjustments 235,804 Reorganization professional fees and other expenses (20,403 ) Write-off of unamortized debt issuance costs (2,577 ) Other reorganization items (5,525 ) Gain on reorganization items, net $ 437,744 The cash payments for reorganization items for the period from January 1, 2017 through February 28, 2017 include approximately $10.6 million of emergence and success fees and approximately $8.9 million of other reorganization professional fees and expenses paid on the Effective Date.

DIVESTITURE

DIVESTITURE	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
DIVESTITURE	DIVESTITURE On February 27, 2017, we completed the sale of the Appalachia Properties to EQT for net cash consideration of approximately $522.5 million , representing gross proceeds of $527.0 million adjusted downward by approximately $4.5 million for purchase price adjustments for operations related to the Appalachia Properties after June 1, 2016, the effective date of the transaction. A portion of the consideration received from the sale of the Appalachia Properties was used to fund the Company’s cash payment obligations under the Plan. See Note 2 – Reorganization . At December 31, 2016, the estimated proved oil and natural gas reserves associated with these assets totaled 18 MMBoe (million barrels of oil equivalent), which represented approximately 34% of the Predecessor Company’s total estimated proved oil and natural gas reserves, on a volume equivalent basis. We no longer have assets or operations in Appalachia. Since accounting for the sale of these oil and gas properties as a reduction of the capitalized costs of oil and gas properties would have significantly altered the relationship between capitalized costs and proved reserves, we recognized a gain on the sale of $213.5 million during the period from January 1, 2017 through February 28, 2017 (Predecessor). The gain on the sale of the Appalachia Properties is computed as follows (in thousands): Net consideration received for sale of Appalachia Properties $ 522,472 Add: Release of funds held in suspense 4,139 Transfer of asset retirement obligations 8,672 Other adjustments, net 2,597 Less: Transaction costs (7,087 ) Carrying value of properties sold (317,340 ) Gain on sale $ 213,453 The carrying value of the properties sold was determined by allocating total capitalized costs within the U.S. full cost pool between properties sold and properties retained based on their relative fair values.

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
STOCKHOLDERS' EQUITY	STOCKHOLDERS’ EQUITY Common Stock As discussed in Note 2 – Reorganization , upon emergence from bankruptcy, all existing shares of Predecessor common stock were cancelled, and the Successor Company issued an aggregate of 20.0 million shares of New Common Stock, par value $0.01 per share, to the Predecessor Company’s existing common stockholders and holders of the 2017 Convertible Notes and the 2022 Notes pursuant to the Plan. Warrants As discussed in Note 2 – Reorganization , the Predecessor Company’s existing common stockholders received warrants to purchase approximately 3.5 million shares of New Common Stock. The warrants have an exercise price of $42.04 per share and a term of four years, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company. The Company allocated $15.6 million of the enterprise value to the warrants which is reflected in “Successor additional paid-in capital” on the audited consolidated balance sheet at December 31, 2017 (Successor).

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
EARNINGS PER SHARE	EARNINGS PER SHARE On February 28, 2017, upon emergence from Chapter 11 bankruptcy, the Company’s Predecessor equity was cancelled and new equity was issued. Additionally, the Predecessor Company’s 2017 Convertible Notes were cancelled. See Note 2 – Reorganization and Note 5 – Stockholders’ Equity for further details. The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods (in thousands, except per share amounts): Successor Predecessor Period from Period from Year Ended December 31, 2016 2015 Income (numerator): Basic: Net income (loss) $ (247,639 ) $ 630,317 $ (590,586 ) $ (1,090,915 ) Net income attributable to participating securities — (4,995 ) — — Net income (loss) attributable to common stock - basic $ (247,639 ) $ 625,322 $ (590,586 ) $ (1,090,915 ) Diluted: Net income (loss) $ (247,639 ) $ 630,317 $ (590,586 ) $ (1,090,915 ) Net income attributable to participating securities — (4,995 ) — — Net income (loss) attributable to common stock - diluted $ (247,639 ) $ 625,322 $ (590,586 ) $ (1,090,915 ) Weighted average shares (denominator): Weighted average shares - basic 19,997 5,634 5,591 5,525 Dilutive effect of stock options — — — — Dilutive effect of warrants — — — — Dilutive effect of convertible notes — — — — Weighted average shares - diluted 19,997 5,634 5,591 5,525 Basic income (loss) per share $ (12.38 ) $ 110.99 $ (105.63 ) $ (197.45 ) Diluted income (loss) per share $ (12.38 ) $ 110.99 $ (105.63 ) $ (197.45 ) All outstanding stock options were considered antidilutive during the period from January 1, 2017 through February 28, 2017 (Predecessor) ( 10,400 shares) because the exercise price of the options exceeded the average price of our common stock for the applicable period. During the years ended December 31, 2016 (Predecessor) ( 12,900 shares) and December 31, 2015 (Predecessor) ( 14,400 shares) all outstanding stock options were considered antidilutive because we had net losses for such years. On February 28, 2017, upon emergence from bankruptcy, all outstanding stock options were cancelled. See Note 16 – Share-Based Compensation . On February 28, 2017, upon emergence from bankruptcy, the Predecessor Company’s existing common stockholders received warrants to purchase common stock of the Successor Company. See Note 2 – Reorganization . For the period of March 1, 2017 through December 31, 2017 (Successor), all outstanding warrants (approximately 3.5 million ) were considered antidilutive because we had a net loss for such period. The Predecessor Company had no outstanding restricted stock units. The board of directors of the Successor Company (the “Board”) received grants of restricted stock units on March 1, 2017. See Note 16 – Share-Based Compensation. For the period from March 1, 2017 through December 31, 2017 (Successor), all outstanding restricted stock units ( 62,137 ) were considered antidilutive because we had a net loss for such period. For the period from January 1, 2017 through February 28, 2017 (Predecessor), the average price of our common stock was less than the effective conversion price for the 2017 Convertible Notes, resulting in no dilutive effect on the diluted earnings per share computation for such period. For the years ended December 31, 2016 and 2015 (Predecessor), the 2017 Convertible Notes had no dilutive effect on the diluted earnings per share computation as we had net losses for such years. On February 28, 2017, upon emergence from bankruptcy, the 2017 Convertible Notes were cancelled. See Note 2 – Reorganization . During the period from March 1, 2017 through December 31, 2017 (Successor), 1,195 shares of common stock of the Successor Company were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees. During the period from January 1, 2017 through February 28, 2017 (Predecessor) and the years ended December 31, 2016 and 2015 (Predecessor), 47,390 , 79,621 and 41,375 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock and granting of stock awards for employees and nonemployee directors.

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE	12 Months Ended
	Dec. 31, 2017
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 (in thousands): Successor Predecessor As of December 31, As of December 31, 2017 2016 Other co-venturers $ 2,656 $ 3,532 Trade 34,980 42,944 Unbilled accounts receivable 820 591 Other 802 1,397 Total accounts receivable $ 39,258 $ 48,464

CONCENTRATIONS

CONCENTRATIONS	12 Months Ended
	Dec. 31, 2017
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: Successor Predecessor Period from Period from Year Ended December 31, 2016 2015 Phillips 66 Company 74 % 56 % 68 % 53 % Shell Trading (US) Company 15 % 7 % 10 % 13 % Williams Ohio Valley Midstream LLC — % 12 % 2 % 9 % Conoco — % 11 % 5 % 2 % The maximum amount of credit risk exposure at December 31, 2017 (Successor) relating to these customers was $30.5 million . 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 All of our estimated proved reserve volumes at December 31, 2017 (Successor) and approximately 88% of our production during 2017 were associated with our GOM deep water, conventional shelf and deep gas properties. We closed the sale of the Appalachia Properties on February 27, 2017 and no longer have assets or operations in Appalachia (see Note 4 – Divestiture) . Cash and Cash Equivalents A substantial portion of our cash balances are not federally insured.

DERIVATIVE INSTRUMENTS AND HEDG

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	12 Months Ended
	Dec. 31, 2017
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. We do not enter into derivative transactions for trading purposes. All derivatives are recognized as assets or liabilities on the balance sheet and are measured at fair value. At the end of each quarterly period, these derivatives are marked-to-market. If the derivative does not qualify or is not designated as a cash flow hedge, subsequent changes in the fair value of the derivative are recognized in earnings through derivative income (expense) in the statement of operations. If the derivative qualifies and is designated as a cash flow hedge, subsequent changes in the fair value of the derivative 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 cash flow hedges are reflected in revenue from oil and natural gas production. Monthly settlements of ineffective hedges and derivatives not designated or that do not qualify for hedge accounting are recognized in earnings through derivative income (expense). The resulting cash flows from all monthly settlements are reported as cash flows from operating activities. Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. A small portion of our cash flow hedges were typically determined to be ineffective because oil and natural gas price changes in the markets in which we sell our products were not 100% correlative to changes in the underlying price basis indicative in the derivative contract. We had no outstanding derivatives at December 31, 2016. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements of these derivative contracts will be recorded in earnings through derivative income (expense). We have entered into put contracts, fixed-price swaps and collar contracts with various counterparties for a portion of our expected 2018 and 2019 oil and natural gas production from the Gulf Coast Basin. 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 typically enter 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 March 9, 2018 , our derivative instruments were with four counterparties, two of which accounted for approximately 64% of our contracted volumes. Currently, all of our outstanding derivative instruments are with lenders under our current bank credit facility. Put contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The historical cost of the put contract represents our maximum cash exposure. We are not obligated to make any further payments under the put contract regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if the New York Mercantile Exchange (“NYMEX”) prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above the floor. 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. Settlements for our oil put contracts, oil collar contracts and fixed-price oil swaps are based on an average of the NYMEX closing price for West Texas Intermediate crude oil during the entire calendar month. Settlements for our natural gas collar contracts and fixed-price natural gas swaps are based on the NYMEX price for the last day of a respective contract month. The following tables illustrate our derivative positions for calendar years 2018 and 2019 as of March 9, 2018 : Put Contracts (NYMEX) Oil Daily Volume Price (Bbls/d) ($ per Bbl) 2018 January - December 1,000 $ 54.00 2018 January - December 1,000 45.00 Fixed-Price Swaps (NYMEX) Oil Daily Volume Swap Price (Bbls/d) ($ per Bbl) 2018 January - December 1,000 $ 52.50 2018 January - December 1,000 51.98 2018 January - December 1,000 53.67 2019 January - December 1,000 51.00 2019 January - December 1,000 51.57 2019 January - December 2,000 56.13 Collar Contracts (NYMEX) Natural Gas Oil Daily Volume Floor Price Ceiling Price Daily Volume (Bbls/d) Floor Price Ceiling Price 2018 January - December 6,000 $ 2.75 $ 3.24 1,000 $ 45.00 $ 55.35 Derivatives not designated or not qualifying as hedging instruments The following table discloses the location and fair value amounts of derivatives not designated or not qualifying as hedging instruments, as reported in our balance sheet, at December 31, 2017 (Successor) (in thousands). We had no outstanding hedging instruments at December 31, 2016 (Predecessor). Fair Value of Derivatives Not Designated or Not Qualifying as Hedging Instruments at December 31, 2017 (Successor) Asset Derivatives Liability Derivatives Description Balance Sheet Location Fair Balance Sheet Location Fair Commodity contracts Current assets: Fair value of $ 879 Current liabilities: Fair value of derivative contracts $ 8,969 Long-term assets: Fair value — Long-term liabilities: Fair 3,085 $ 879 $ 12,054 Gains or losses related to changes in fair value and cash settlements for derivatives not designated or 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 designated or not qualifying as hedging instruments on the statement of operations for the indicated periods (in thousands): Gain (Loss) Recognized in Derivative Income (Expense) Successor Predecessor Period from Period from Year Ended Description December 31, 2016 December 31, 2015 Commodity contracts: Cash settlements $ 2,161 $ — $ — $ 17,385 Change in fair value (15,549 ) (1,778 ) — (12,146 ) Total gains (losses) on derivatives not designated or not qualifying as hedging instruments $ (13,388 ) $ (1,778 ) $ — $ 5,239 Derivatives qualifying as hedging instruments None of our derivative contracts outstanding as of December 31, 2017 (Successor) were designated as accounting hedges. We had no outstanding derivatives at December 31, 2016 (Predecessor). During 2016 and 2015, we had outstanding derivatives that were designated and qualified as hedging instruments. 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, 2016 and 2015 (Predecessor) (in thousands): Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations for the Years Ended December 31, 2016 and 2015 (Predecessor) 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 2016 2016 2016 Commodity contracts $ (1,648 ) Operating revenue - oil/natural gas production $ 35,457 Derivative income (expense), net $ (810 ) Total $ (1,648 ) $ 35,457 $ (810 ) 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 (a) For the year ended December 31, 2016 , effective hedging contracts increased oil revenue by $23,747 and increased natural gas revenue by $11,710 . For the year ended December 31, 2015 , effective hedging contracts increased oil revenue by $135,617 and increased natural gas revenue by $14,338 . 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. The following table presents the potential impact of the offset rights associated with our recognized assets and liabilities at December 31, 2017 (Successor) (in thousands): As Presented Without Netting Effects of Netting With Effects of Netting Current assets: Fair value of derivative contracts $ 879 $ (879 ) $ — Long-term assets: Fair value of derivative contracts — — — Current liabilities: Fair value of derivative contracts (8,969 ) 879 (8,090 ) Long-term liabilities: Fair value of derivative contracts (3,085 ) — (3,085 ) We had no outstanding derivative contracts at December 31, 2016 (Predecessor).

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2017
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, 2017 (Successor) and 2016 (Predecessor), we held certain financial assets 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. The income approach is used in this determination utilizing the third party’s 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 and put contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars and puts are the volatility impacts in the pricing model as it relates to the call portion of the collar and the floor of the put. For a more detailed description of our derivative instruments, see Note 9 – Derivative Instruments and Hedging Activities . We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy. The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2017 (Successor) (in thousands): Fair Value Measurements Successor as of December 31, 2017 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) $ 5,081 $ 5,081 $ — $ — Derivative contracts 879 — — 879 Total $ 5,960 $ 5,081 $ — $ 879 Fair Value Measurements Successor as of December 31, 2017 Liabilities Total Quoted Prices in Significant Other Significant Unobservable Inputs (Level 3) Derivative contracts $ 12,054 $ — $ 10,110 $ 1,944 Total $ 12,054 $ — $ 10,110 $ 1,944 We had no liabilities measured at fair value on a recurring basis at December 31, 2016. The following table presents our assets that are measured at fair value on a recurring basis at December 31, 2016 (Predecessor) (in thousands): Fair Value Measurements Predecessor as of December 31, 2016 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) $ 8,746 $ 8,746 $ — $ — Total $ 8,746 $ 8,746 $ — $ — The table below presents a reconciliation for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the period from March 1, 2017 through December 31, 2017 (Successor) and the period from January 1, 2017 through February 28, 2017 (Predecessor) (in thousands): Hedging Contracts, net Successor Predecessor Period from Period from Beginning balance $ 3,087 $ — Total gains/(losses) (realized or unrealized): Included in earnings (5,201 ) (649 ) Included in other comprehensive income — — Purchases, sales, issuances and settlements 1,049 3,736 Transfers in and out of Level 3 — — Ending balance $ (1,065 ) $ 3,087 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, 2017 $ (4,699 ) The fair value of cash and cash equivalents approximated book value at December 31, 2017 and 2016 . Upon emergence from bankruptcy on February 28, 2017, the 2017 Convertible Notes and 2022 Notes were cancelled, and the Company issued the 2022 Second Lien Notes. As of December 31, 2016, the fair value of the liability component of the 2017 Convertible Notes was approximately $293.5 million . As of December 31, 2016, the fair value of the 2022 Notes was approximately $465.0 million . As of December 31, 2017, the fair value of the 2022 Second Lien Notes was approximately $227.3 million . The fair values of the 2022 Notes and the 2022 Second Lien Notes were 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 at inception and at December 31, 2016. 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. On February 28, 2017, the Company emerged from bankruptcy and adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting date, February 28, 2017. See Note 3 – Fresh Start Accounting for a detailed discussion of the fair value approaches used by the Company. The inputs utilized in the valuation of our most significant asset, our oil and gas properties, included mostly unobservable inputs, which fall within Level 3 of the fair value hierarchy.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS Upon emergence from bankruptcy, as discussed in Note 3 – Fresh Start Accounting , the Company adopted fresh start accounting which included the adjustment of asset retirement obligations to estimated fair values at February 28, 2017. The following table presents the change in our asset retirement obligations during the indicated periods (in thousands, inclusive of current portion): Successor Predecessor Period from Period from Year Ended December 31, 2016 2015 Beginning balance $ 290,067 $ 242,019 $ 225,866 $ 316,409 Liabilities incurred 2,280 — 2,338 15,933 Liabilities settled (81,197 ) (3,641 ) (19,630 ) (72,713 ) Divestment of properties — (8,672 ) — (248 ) Accretion expense 21,151 5,447 40,229 25,988 Revision of estimates (19,200 ) — (6,784 ) (59,503 ) Fair value fresh start adjustment — 54,914 — — Asset retirement obligations, end of period $ 213,101 $ 290,067 $ 242,019 $ 225,866

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES An analysis of our deferred taxes follows (in thousands): Successor Predecessor As of December 31, As of December 31, 2017 2016 Tax effect of temporary differences: Net operating loss carryforwards $ 66,304 $ 201,557 Oil and gas properties 12,035 85,772 Asset retirement obligations 44,751 85,312 Stock compensation 278 3,294 Derivatives 3,110 — Accrued incentive compensation 2,269 954 Debt issuance costs 644 7,480 Other 1,600 441 Total deferred tax assets (liabilities) 130,991 384,810 Valuation allowance (130,991 ) (384,810 ) Net deferred tax assets (liabilities) $ — $ — Upon our emergence from bankruptcy, pursuant to the terms of the Plan, a substantial portion of the Company’s pre-petition debt was extinguished (see Note 2 – Reorganization ). For tax purposes, absent an exception, a debtor recognizes cancellation of indebtedness income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The IRC provides that a debtor in a bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. After consideration of the market value of the Company’s equity upon emergence from Chapter 11 bankruptcy proceedings, the estimated amount of U.S. CODI is approximately $257 million , which will reduce the value of the Company’s U.S. net operating losses. The actual reduction in tax attributes does not occur until the first day of the Company’s tax year subsequent to the date of emergence, or January 1, 2018. The estimated results of the attribute reduction have been reflected in the Company’s ending balance of deferred tax assets for the year ended December 31, 2017 (Successor). The Successor Company also has various state net operating loss carryforwards that are subject to reduction as a result of the CODI being excluded from taxable income, however, subsequent to the sale of the Appalachia Properties, our state income tax exposure is not expected to be material. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). Generally effective for tax years 2018 and beyond, the Tax Act makes broad and complex changes to the IRC, including, but not limited to, (i) reducing the U.S. federal corporate tax rate from 35% to 21%; (ii) eliminating the corporate alternative minimum tax (“AMT”) and changing how existing AMT credits are realized; (iii) creating a new limitation on deductible interest expense; and (iv) changing rules related to uses and limitation of net operating loss carryforwards created in tax years beginning after December 31, 2017. As of December 31, 2017, we have not completed our accounting for the tax effects of enactment of the Tax Act. However, we have made a reasonable estimate of the effects on our existing deferred tax balances and recognized a provisional amount of $87.3 million to remeasure our deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. This amount is included as a component of income tax expense (benefit) from continuing operations and is fully offset by the related adjustment to our valuation allowance. We are still analyzing certain aspects of the Tax Act and refining our calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. We estimate that we had ($18.3) million and $3.6 million , respectively, of current federal income tax expense (benefit) for the periods of March 1, 2017 through December 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor). For the years ended December 31, 2016 and 2015 (Predecessor) we had ($5.7) million and ($44.1) million , respectively, of current federal income tax (benefits). There was no deferred income tax expense (benefit) recorded for the periods of March 1, 2017 through December 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor). For the years ended December 31, 2016 and 2015 (Predecessor), we recorded a deferred income tax expense (benefit) of $13.1 million and ($272.3) million , respectively. The deferred income tax benefit in 2015 was a result of our losses before income taxes attributable primarily to ceiling test write-downs of our oil and gas properties (see Note 22 – Supplemental Information on Oil and Natural Gas Operations – Unaudited ). We had current income tax receivables of $36.3 million and $26.1 million at December 31, 2017 (Successor) and 2016 (Predecessor), respectively, both of which related to expected tax refunds from the carryback of net operating losses to previous tax years. We received $20.6 million of the tax refund subsequent to December 31, 2017. For tax reporting purposes, our net operating loss carryforwards totaled approximately $315.7 million at December 31, 2017 (net of the aforementioned CODI reduction). If not utilized, such carryforwards would begin to expire in 2035 and would fully expire in 2036. Additionally, IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future U.S. taxable income in the event of a change in ownership. The Company’s emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of IRC Section 382. Accordingly, we estimate that approximately $127 million of our net operating loss carryforwards will be subject to the annual IRC Section 382 limitation, with the remaining $189 million of net operating loss carryforwards being unlimited. In addition, we had approximately $1.2 million 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, 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 valuation allowance against a portion of our deferred tax assets. As of December 31, 2017 (Successor), our valuation allowance totaled $131.0 million . 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. The following table provides a reconciliation of the statutory federal income tax rate to the Company’s effective income tax rate as a percentage of income before income taxes for the indicated periods: Successor Predecessor Period from Period from Year Ended December 31, 2016 2015 Income tax expense computed at the statutory federal income tax rate 35.0% 35.0% 35.0% 35.0% Tax Act rate change (32.8) — — — State taxes (0.7) 0.3 0.2 0.6 Change in valuation allowance 5.3 (37.8) (35.0) (12.8) IRC Sec. 162(m) limitation 0.4 — (0.3) (0.1) Tax deficits on stock compensation (0.6) 0.6 (0.7) (0.1) Reorganization fees 0.3 2.5 (0.3) — Other — — (0.2) (0.1) Effective income tax rate 6.9% 0.6% (1.3)% 22.5% There were no income taxes allocated to accumulated other comprehensive income for the periods of March 1, 2017 through December 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor). Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to ($13.1) million , ($35.7) million for the years ended December 31, 2016 and 2015 (Predecessor), respectively. As of December 31, 2017 (Successor), we had unrecognized tax benefits of $491 thousand . 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 (in thousands): Successor Predecessor Period from Period from Total unrecognized tax benefits, beginning balance $ 491 $ 491 Increases (decreases) in unrecognized tax benefits as a result of: Tax positions taken during a prior period — — Tax positions taken during the current period — — Settlements with taxing authorities — — Lapse of applicable statute of limitations — — Total unrecognized tax benefits, ending balance $ 491 $ 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 $33 thousand and $7 thousand , respectively, of interest expense and no penalties related to uncertain tax positions for the periods of March 1, 2017 through December 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor). We recognized $46 thousand of interest expense and no penalties related to uncertain tax positions for the year ended December 31, 2016 (Predecessor). We recognized $131 thousand of interest expense and no penalties related to uncertain tax positions for the year ended December 31, 2015 (Predecessor). The liabilities for unrecognized tax benefits and accrued interest payable are components of other current liabilities on our balance sheet. The tax years 2014 through 2017 remain subject to examination by major tax jurisdictions.

DEBT

DEBT	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
DEBT	DEBT Our debt balances (net of related unamortized discounts and debt issuance costs) as of December 31, 2017 and 2016 were as follows (in thousands): Successor Predecessor December 31, December 31, 2017 2016 7 1⁄2 % Senior Second Lien Notes due 2022 $ 225,000 $ — 1 3 ⁄ 4 % Senior Convertible Notes due 2017 — 300,000 7 1⁄2 % Senior Notes due 2022 — 775,000 Predecessor revolving credit facility — 341,500 4.20% Building Loan 10,927 11,284 Total debt $ 235,927 $ 1,427,784 Less: current portion of long-term debt (425 ) (408 ) Less: liabilities subject to compromise — (1,075,000 ) Long-term debt $ 235,502 $ 352,376 Reorganization On December 14, 2016, the Debtors filed Bankruptcy Petitions seeking relief under Chapter 11 of the Bankruptcy Code to pursue a prepackaged plan of reorganization. The 2017 Convertible Notes and 2022 Notes were impacted by the Chapter 11 process and were classified in the accompanying consolidated balance sheet at December 31, 2016 as liabilities subject to compromise under the provisions of ASC 852, “ Reorganizations ”. On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan, and on February 28, 2017, the Plan became effective and the Debtors emerged from bankruptcy. Upon emergence from bankruptcy, pursuant to the terms of the Plan, the Predecessor Company’s 2017 Convertible Notes and 2022 Notes were cancelled, the Predecessor Company’s Pre-Emergence Credit Agreement was amended and restated, and the Company issued the 2022 Second Lien Notes. Current Portion of Long-Term Debt As of December 31, 2017 (Successor), the current portion of long-term debt of $0.4 million represented principal payments due within one year on the 4.20% Building Loan (the “Building Loan”). Reclassification of Deb t The face values of the 2017 Convertible Notes of $300 million and the 2022 Notes of $775 million were reclassified as liabilities subject to compromise in the accompanying consolidated balance sheet at December 31, 2016 (Predecessor). See Note 1 – Organization and Summary of Significant Accounting Policies . Successor Revolving Credit Facility On the Effective Date, pursuant to the terms of the Plan, the Company entered into the Fifth Amended and Restated Credit Agreement with the lenders party thereto and Bank of America, N.A. (as amended from time to time, the “Amended Credit Agreement”), as administrative agent and issuing lender, which amended and replaced the Company’s Pre-Emergence Credit Agreement. The Amended Credit Agreement provides for a reserve-based revolving credit facility and matures on February 28, 2021. The Company’s available borrowings under the Amended Credit Agreement were initially set at $150 million until the first borrowing base redetermination in November 2017. On November 8, 2017, the borrowing base under the Amended Credit Agreement was redetermined to $100 million . On December 31, 2017 , the Company had no outstanding borrowings and $12.6 million of outstanding letters of credit, leaving $87.4 million of availability under the Amended Credit Agreement. Interest on loans under the Amended Credit Agreement is calculated using the London Interbank Offering Rate (“LIBOR”) or the base rate, at the election of the Company, plus, in each case, an applicable margin. The applicable margin is determined based on borrowing base utilization and ranges from 2.00% to 3.00% per annum for base rate loans and 3.00% to 4.00% per annum for LIBOR loans. The borrowing base under the Amended Credit Agreement is redetermined semi-annually, in May and November, by the lenders, 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 each in any calendar year, to have the borrowing base redetermined. Subject to certain exceptions, the Amended Credit Agreement is required to be guaranteed by all of the material domestic direct and indirect subsidiaries of the Company. As of December 31, 2017 , the Amended Credit Agreement is guaranteed by Stone Offshore. The Amended Credit Agreement is secured by substantially all of the Company’s and its subsidiaries’ assets. The Amended Credit Agreement provides for customary optional and mandatory prepayments, affirmative and negative covenants and events of default, including limitations on the incurrence of debt, liens, restrictive agreements, mergers, asset sales, dividends, investments, affiliate transactions and restrictions on commodity hedging. During the continuance of certain events of default, the lenders may take a number of actions, including declaring the entire amount then outstanding under the Amended Credit Agreement due and payable (in the event of certain insolvency-related events, the entire amount then outstanding under the Amended Credit Agreement will become automatically due and payable). The Amended Credit Agreement also requires maintenance of certain financial covenants, including (i) a consolidated funded debt to EBITDA ratio of not more than 2.75 x for the test period ending March 31, 2017, 2.50 x for the test period ending June 30, 2017, 3.00 x for the test period ending September 30, 2017, 2.75 x for the test period ending December 31, 2017, 2.50 x for the test periods ending March 31, 2018, June 30, 2018, September 30, 2018 and December 31, 2018, respectively, 2.75 x for the test period ending March 31, 2019, 3.00 x for the test period ending June 30, 2019, 3.50 x for the test periods ending September 30, 2019 and December 31, 2019, respectively, 3.00 x for the test period ending March 31, 2020, 2.75 x for the test periods ending June 30, 2020 and September 30, 2020, respectively, and 2.50 x for the test periods ending December 31, 2020 and March 31, 2021, respectively, (ii) a consolidated interest coverage ratio of not less than 2.75 to 1.00, and (iii) a requirement to maintain minimum liquidity of at least 20% of the borrowing base. We were in compliance with all covenants under the Amended Credit Agreement as of December 31, 2017 . Predecessor Revolving Credit Facility On June 24, 2014 , the Predecessor Company entered into the Pre-Emergence Credit Agreement with the lenders party thereto and Bank of America, N.A., as administrative agent and issuing lender, with commitments totaling $900 million (subject to borrowing base limitations). The borrowing base under the Pre-Emergence Credit Agreement prior to its amendment and restatement as the Amended Credit Agreement was $150 million . Interest on loans under the Pre-Emergence Credit Agreement was calculated using the LIBOR rate or the base rate, at our election. The margin for loans at the LIBOR rate was determined based on borrowing base utilization and ranged from 1.500% to 2.500% . Prior to emergence from bankruptcy, the Predecessor Company had $341.5 million of outstanding borrowings and $12.5 million of outstanding letters of credit under the Pre-Emergence Credit Agreement. At emergence, the outstanding borrowings were paid in full and the $12.5 million of outstanding letters of credit were converted to obligations under the Amended Credit Agreement. Building Loan On November 20, 2015, we entered into an approximately $11.8 million term loan agreement, the Building Loan, maturing on November 20, 2030. There were no changes to the terms of the Building Loan pursuant to the Plan. The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of approximately $73,000 commencing on December 20, 2015. As of December 31, 2017, the outstanding balance under the Building Loan totaled $10.9 million . The Building Loan is collateralized 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. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities. We were in compliance with all covenants under the Building Loan as of December 31, 2017 . Successor 2022 Second Lien Notes On the Effective Date, pursuant to the terms of the Plan, the Successor Company entered into an indenture by and among the Company, Stone Offshore, as guarantor (the “Guarantor”), and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (the “2022 Second Lien Notes Indenture”), and issued $225 million of the Company’s 2022 Second Lien Notes pursuant thereto. Interest on the 2022 Second Lien Notes accrues at a rate of 7.50% per annum payable semi-annually in arrears on May 31 and November 30 of each year in cash, beginning November 30, 2017. At December 31, 2017, $1.4 million had been accrued in connection with the May 31, 2018 interest payment. The 2022 Second Lien Notes are secured on a second lien priority basis by the same collateral that secures the Amended Credit Agreement, including the Company’s oil and natural gas properties, and are guaranteed by the Guarantor. The 2022 Second Lien Notes mature on May 31, 2022. Pursuant to the terms of the Intercreditor Agreement (as defined below), the security interest in those assets that secure the 2022 Second Lien Notes and the related guarantee are contractually subordinated to liens thereon that secure the Company’s Amended Credit Agreement and certain other permitted obligations as set forth in the 2022 Second Lien Notes Indenture. Consequently, the 2022 Second Lien Notes and the related guarantee are effectively subordinated to the Amended Credit Agreement and such other permitted secured indebtedness to the extent of the value of such assets. At any time prior to May 31, 2020, the Company may, at its option, on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2022 Second Lien Notes issued under the 2022 Second Lien Notes Indenture at a redemption price of 107.5% of the principal amount of the 2022 Second Lien Notes, plus accrued and unpaid interest to the redemption date, with an amount of cash equal to the net cash proceeds of certain equity offerings; provided that at least 65% of the aggregate principal amount of the 2022 Second Lien Notes as of the Effective Date remains outstanding after each such redemption. On or after May 31, 2020, the Company may redeem all or part of the 2022 Second Lien Notes at redemption prices (expressed as percentages of the principal amount) equal to (i) 105.625% for the twelve-month period beginning on May 31, 2020; (ii) 105.625% for the twelve-month period beginning on May 31, 2021; and (iii) 100.000% for the twelve-month period beginning on May 31, 2022 and at any time thereafter, in each case, plus accrued and unpaid interest at the redemption date. In addition, at any time prior to May 31, 2020, the Company may redeem all or a part of the 2022 Second Lien Notes at a redemption price equal to 100% of the principal amount of the 2022 Second Lien Notes to be redeemed plus a make-whole premium, plus accrued and unpaid interest to the redemption date. The 2022 Second Lien Notes Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt and issue preferred stock; (ii) make payments or distributions on account of the Company’s or its restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of the Company’s restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates, and (vii) merge or consolidate with another company. These covenants are subject to a number of important exceptions and qualifications. At any time when the 2022 Second Lien Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc., and no Default (as defined in the 2022 Second Lien Notes Indenture) has occurred and is continuing, many of these covenants will terminate. The 2022 Second Lien Notes Indenture also provides for certain events of default. In the case of an event of default arising from certain events of bankruptcy, insolvency or reorganization with respect to the Company or any of the Company’s restricted subsidiaries that is a significant subsidiary, or any group of the Company’s restricted subsidiaries that, taken as a whole, would constitute a significant subsidiary of the Company, all outstanding 2022 Second Lien Notes will become due and immediately payable without further action or notice. If any other event of default occurs and is continuing, the trustee of the 2022 Second Lien Notes or the holders of at least 25% in aggregate principal amount of the then outstanding 2022 Second Lien Notes may declare all the 2022 Second Lien Notes to be due and payable immediately. Intercreditor Agreement On the Effective Date, Bank of America, N.A., as priority lien agent, The Bank of New York Mellon Trust Company, N.A., as second lien collateral agent, and The Bank of New York Mellon Trust Company, N.A., as the 2022 Second Lien Notes trustee, entered into an intercreditor agreement, which was acknowledged and agreed to by the Company and the Guarantor (the “Intercreditor Agreement”) to govern the relationship of holders of the 2022 Second Lien Notes, the lenders under the Amended Credit Agreement and holders of other priority lien obligations, with respect to collateral and certain other matters. Predecessor Senior Notes 2017 Convertible Notes. On March 6, 2012, the Predecessor Company issued in a private offering $300 million 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 2017 Convertible Notes were 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 23.4449 shares of our common stock per $1,000 principal amount of 2017 Convertible Notes, which corresponded to an initial conversion price of approximately $42.65 per share of our common stock at the time of the issuance of the 2017 Convertible Notes. On June 10, 2016, we completed a 1-for-10 reverse stock split with respect to our common stock and proportional adjustments were made to the conversion price and shares as they relate to the 2017 Convertible Notes, resulting in a conversion rate of 2.34449 shares of our common stock with a corresponding conversion price of $426.50 per share. The 2017 Convertible Notes were due on March 1, 2017. Upon emergence from bankruptcy on February 28, 2017, pursuant to the Plan, the $300 million of debt related to the 2017 Convertible Notes was cancelled. See Note 2 – Reorganization for additional details. During the year ended December 31, 2016 (Predecessor), we recognized $15.4 million of interest expense for the amortization of the discount and $1.5 million of interest expense for the amortization of debt issuance costs related to the 2017 Convertible Notes. During the year ended December 31, 2015 (Predecessor), we recognized $15.0 million of interest expense for the amortization of the discount and $1.4 million of interest expense for the amortization of debt issuance costs related to the 2017 Convertible Notes. 2022 Notes. On November 8, 2012 and November 27, 2013, respectively, the Predecessor Company completed the public offering of $300 million and $475 million aggregate principal amount of the 2022 Notes. The 2022 Notes were scheduled to mature on November 15, 2022. Upon emergence from bankruptcy, pursuant to the Plan, the $775 million of debt related to the 2022 Notes was cancelled. See Note 2 – Reorganization for additional details. Deferred Financing Cost and Interest Cost In accordance with the provisions of ASC 852, we recognized a charge of approximately $8.3 million to write-off the remaining unamortized debt issuance costs, discounts and premiums related to the 2017 Convertible Notes and 2022 Notes, which is included in reorganization items in the accompanying consolidated statement of operations for the year ended December 31, 2016 (Predecessor). Additionally, we recognized a charge of approximately $2.6 million to write-off the remaining unamortized debt issuance costs related to the Pre-Emergence Credit Agreement as of the Petition Date, which is included in reorganization items in the consolidated statement of operations during the period from January 1, 2017 through February 28, 2017 (Predecessor). See Note 1 – Organization and Summary of Significant Accounting Policies and Note 3 – Fresh Start Accounting for additional details. At December 31, 2017 (Successor) and December 31, 2016 (Predecessor), approximately $59 thousand and $63 thousand , respectively, of unamortized debt issuance costs were deducted from the carrying amount of the Building Loan. At December 31, 2016 (Predecessor), approximately $2.8 million of debt issuance costs related to the Pre-Emergence Credit Agreement were classified as other assets. Prior to the filing of the Bankruptcy Petitions, the costs associated with the 2017 Convertible Notes were being amortized over the life of the notes using a method that applied an effective interest rate of 7.51% . The costs associated with the November 2012 issuance and November 2013 issuance of the 2022 Notes were being amortized over the life of the notes using a method that applied effective interest rates of 7.75% and 7.04% , respectively. The costs associated with the Pre-Emergence Credit Agreement were being amortized on a straight-line basis over the term of the facility. The costs associated with the issuance of the Building Loan are being amortized using the effective interest method over the term of the Building Loan. Total interest cost incurred, before capitalization, on all obligations for the period from March 1, 2017 through December 31, 2017 (Successor) was $15.7 million . Total interest cost incurred, before capitalization, on all obligations for the years ended December 31, 2016 and 2015 (Predecessor) was $91.1 million and $85.3 million , respectively. In accordance with the accounting guidance in ASC 852, we accrued interest on the 2017 Convertible Notes and 2022 Notes only up to the Petition Date, and such amounts were included as liabilities subject to compromise in our consolidated balance sheet at December 31, 2016 (Predecessor). Accordingly, there was no interest expense recognized on the 2017 Convertible Notes or the 2022 Notes after the Bankruptcy Petitions were filed.

ACCUMULATED OTHER COMPREHENSIVE

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts, and accordingly, changes in the fair value of the derivative were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. We had no outstanding derivative contracts at December 31, 2016. During the periods from March 1, 2017 through December 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor), we entered into various commodity derivative contracts (see Note 9 – Derivative Instruments and Hedging Activities ). With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements of these derivative contracts will be recorded in earnings through derivative income (expense). During the year ended December 31, 2016, we reclassified a $6.1 million loss related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the liquidation of our former foreign subsidiary, Stone Energy Canada, ULC. The following tables include the changes in accumulated other comprehensive income (loss) by component for the years ended December 31, 2016 and 2015 (Predecessor) (in thousands): Cash Flow Hedges Foreign Currency Items Total For the Year Ended December 31, 2016 (Predecessor) Beginning balance, net of tax $ 24,025 $ (6,073 ) $ 17,952 Other comprehensive income (loss) before reclassifications: Change in fair value of derivatives (1,648 ) — (1,648 ) Foreign currency translations — (8 ) (8 ) Income tax effect 581 — 581 Net of tax (1,067 ) (8 ) (1,075 ) Amounts reclassified from accumulated other comprehensive income: Operating revenue: oil/natural gas production 35,457 — 35,457 Other operational expenses — (6,081 ) (6,081 ) Income tax effect (12,499 ) — (12,499 ) Net of tax 22,958 (6,081 ) 16,877 Other comprehensive income (loss), net of tax (24,025 ) 6,073 (17,952 ) Ending balance, net of tax $ — $ — $ — Cash Flow Hedges Foreign Currency Items Total For the Year Ended December 31, 2015 (Predecessor) 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

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2017
Compensation Related Costs [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS We entered into deferred compensation and disability agreements with certain of our former officers. The benefits under the deferred compensation agreements vested after certain periods of employment, and at December 31, 2017 (Successor), the liability for such vested benefits was approximately $0.9 million and is recorded in current and other long-term liabilities. The deferred compensation plan is described further below. The following is a brief description of each incentive compensation plan applicable to our employees: Annual Incentive Cash Compensation Plans In 2016, we replaced our historical long-term cash and equity-based incentive compensation programs with the 2016 Performance Incentive Compensation Plan (the “2016 Annual Incentive Plan”), pursuant to which incentive cash bonuses were calculated based on the achievement of certain strategic objectives for each quarter of 2016. On July 25, 2017, the Board approved the Stone Energy Corporation 2017 Annual Incentive Compensation Plan (the “2017 Annual Incentive Plan”) for all salaried employees (other than the interim chief executive officer) of the Company. The 2017 Annual Incentive Plan is a performance-based short-term cash incentive program that provides award opportunities based on the Company’s annual performance in certain performance measures as defined by the Board. The 2017 Annual Incentive Plan replaced the Company’s Amended and Restated Revised Annual Incentive Compensation Plan, which was adopted in November 2007, and the 2016 Annual Incentive Plan. For the period from March 1, 2017 through December 31, 2017 (Successor), Stone incurred expenses of $7.0 million , net of amounts capitalized, related to incentive compensation cash bonuses. Stone incurred expenses of $13.5 million and $2.2 million , net of amounts capitalized, for each of the years ended December 31, 2016 and 2015 (Predecessor), respectively, related to incentive compensation cash bonuses. These charges are reflected in incentive compensation expense on the statement of operations. Key Executive Incentive Plan Pursuant to the terms of the Executive Claims Settlement Agreement, the Company’s executives agreed to waive their claims related to the Company’s 2016 Annual Incentive Plan, and in exchange therefor, the Company adopted the Stone Energy Corporation Key Executive Incentive Plan (“KEIP”), in which the Company’s executives were allowed to participate. Payments to the Company’s executives under the KEIP were limited to $2.0 million , or the equivalent of the target bonus under the 2016 Annual Incentive Plan for the fourth quarter of 2016. The KEIP payments of $2.0 million are reflected in incentive compensation expense on the statement of operations for the period from January 1, 2017 through February 28, 2017 (Predecessor). Retention Award Agreement On July 25, 2017, the Board approved retention awards and the form of Stone Energy Corporation Retention Award Agreement (the “Retention Award Agreement”) and authorized the Company to enter into Retention Award Agreements with certain executive officers and employees of the Company. The Retention Award Agreement provides for a retention award to certain individuals to be paid in a lump sum cash payment within 30 days of the earliest to occur of (i) the first anniversary (June 1, 2018) of the effective date of the Retention Award Agreement, subject to the individual remaining employed by the Company or a subsidiary of the Company on such date, (ii) a change in control of the Company or (iii) a termination of the individual’s employment with the Company (a) due to death, (b) by the Company without “cause” or (c) by the individual for “good reason.” We recognized a charge of $1.0 million for the period from March 1, 2017 through December 31, 2017 (Successor), representing a prorated portion of estimated retention awards through December 31, 2017. This charge is reflected in incentive compensation expense on the statement of operations. Transaction Bonus Agreement On November 21, 2017, the Board approved transaction bonuses and the form of Stone Energy Corporation Transaction Bonus Agreement (the “Transaction Bonus Agreement”) and authorized the Company to enter into Transaction Bonus Agreements with certain of our executive officers and other employees of the Company. The Transaction Bonus Agreements provide for a lump sum cash payment within 30 days of a “change in control” (as defined in the Transaction Bonus Agreement) if the individual remains employed with the Company through the date of the “change in control” or is terminated prior to the change in control (i) due to death, (ii) by the Company without “cause” (as defined below) (including due to disability), or (iii) by the individual for “good reason” (as defined in the Transaction Bonus Agreement). The Transaction Bonus Agreements were entered into in connection with the Talos combination. 2017 Long-Term Incentive Plan On the Effective Date, pursuant to the Plan, the Stone Energy Corporation 2017 Long-Term Incentive Plan (the “2017 LTIP”) became effective, replacing the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (As Amended and Restated December 17, 2015). The types of awards that may be granted under the 2017 LTIP include stock options, restricted stock, restricted stock units, dividend equivalents and other forms of awards granted or denominated in shares of New Common Stock, as well as certain cash-based awards. The maximum number of shares of New Common Stock that may be issued or transferred pursuant to awards under the 2017 LTIP is 2,614,379 . As of March 9, 2018 , other than the grant of 62,137 restricted stock units to the Board (see Note 16 – Share-Based Compensation ), there have been no other issuances or awards of stock under the 2017 LTIP. 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 period from March 1, 2017 through December 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor), Stone contributed $0.6 million and $0.3 million , respectively, to the plan. For the years ended December 31, 2016 and 2015 (Predecessor), Stone contributed $1.2 million and $1.6 million , respectively, to the plan. The Stone Energy Corporation Deferred Compensation Plan (the “Deferred Compensation Plan”) provides eligible executives and employees with the option to defer up to 100% of their eligible compensation for a calendar year. Historically, we could, at our discretion, match a portion or all of the participant’s deferral based upon a percentage determined by our Board. In 2016, the compensation committee of the Predecessor board adopted an amendment to the Deferred Compensation Plan that removed our ability to make matching contributions under such plan. Our Board may still 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 under the Deferred Compensation Plan. 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, 2017 (Successor) and December 31, 2016 (Predecessor), plan assets of $5.1 million and $8.7 million , 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 July 25, 2017, the Board approved the Stone Energy Corporation Executive Severance Plan (the “Executive Severance Plan”), which provides for the payment of severance and change in control benefits to the executive officers (other than the interim chief executive officer) of the Company. The Executive Severance Plan replaced the Stone Energy Corporation Executive Severance Plan dated December 13, 2016. Pursuant to the Executive Severance Plan, if a covered executive officer is terminated (i) by the Company without “cause” or (ii) by the executive officer for “good reason” (each, an “Involuntary Termination”), the executive officer will receive (i) a lump sum cash payment in an amount equal to 1.0 x or 1.5 x the executive officer’s annual base salary, (ii) a lump sum cash payment equal to 100% of the executive officer’s annual bonus opportunity, at target, prorated by the number of days that have elapsed from January 1 of that calendar year, (iii) six months of health benefit continuation for the executive officer and the executive officer’s dependents, at a cost to the participant that is equal to the cost for an active employee for similar coverage, (iv) accelerated vesting of any outstanding and unvested equity awards, (v) certain outplacement services and (vi) any unpaid portion of the executive officer’s annual pay as of the date of the Involuntary Termination. The Executive Severance Plan was amended on November 21, 2017 in connection with the proposed Talos combination to provide, among other things, that if a participant in the plan experiences a qualifying termination of employment during the twelve month period following Closing, such participant’s target bonus will be no less than such participant’s target bonus for the 2017 calendar year. On July 25, 2017, the Board approved the Stone Energy Corporation Employee Severance Plan (the “2017 Employee Severance Plan”). The 2017 Employee Severance Plan covers all full-time employees other than officers. Severance is triggered by an involuntary termination of employment on and during the twelve-month period following a change of control. Employees who are terminated within the scope of the 2017 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 thousand 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 at a cost to the participant that is equal to the cost for an active employee for similar coverage, (iii) a prorated portion of the employee’s targeted bonus for the year, and (iv) reasonable outplacement services consistent with current HR practices. The 2017 Employee Severance Plan was amended on November 21, 2017 in connection with the proposed Talos combination to provide, among other things, that if a participant in the plan experiences a qualifying termination of employment during the twelve month period following Closing, such participant’s target bonus will be no less than such participant’s target bonus for the 2017 calendar year. The 2017 Employee Severance Plan replaced the Stone Energy Corporation Employee Change of Control Severance Plan, dated December 7, 2007.

SHARE-BASED COMPENSATION

SHARE-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
SHARE-BASED COMPENSATION	SHARE-BASED COMPENSATION On the Effective Date, pursuant to the Plan, the 2017 LTIP became effective. As discussed in Note 15 – Employee Benefit Plans , the types of awards that may be granted under the 2017 LTIP include stock options, restricted stock, restricted stock units, dividend equivalents and other forms of awards granted or denominated in shares of New Common Stock, as well as certain cash-based awards. We record share-based compensation expense 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 statement of operations on a straight-line basis over the vesting period of the award. Under the full cost method of accounting, we capitalize a portion of employee and general and administrative costs (including share-based compensation). 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. 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. There were no adjustments to additional paid-in capital related to the net tax effect of stock option exercises and restricted stock vesting in 2017 , 2016 or 2015 . During the period from March 1, 2017 through December 31, 2017 (Successor), the period from January 1, 2017 through February 28, 2017 (Predecessor) and the years ended December 31, 2016 and 2015 (Predecessor), respectively, $2.5 million , $2.7 million , $4.1 million and $1.3 million of tax deficits were charged to income tax expense. Predecessor Share-Based Compensation For the period from January 1, 2017 through February 28, 2017 (Predecessor), we incurred $3.5 million of share-based compensation expense, all of which related to stock awards and restricted stock issuances, and of which a total of approximately $0.9 million was capitalized into oil and gas properties. For the year ended December 31, 2016 (Predecessor), we incurred $11.6 million of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $3.1 million was capitalized into oil and gas properties. For the year ended December 31, 2015 (Predecessor), we incurred $17.9 million of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $5.6 million was capitalized into oil and gas properties. Stock Options . All outstanding stock options at December 31, 2016 related to executive share-based awards that were cancelled upon emergence from bankruptcy. There were no stock option grants during the period from January 1, 2017 through February 28, 2017. The following tables include Predecessor Company stock option activity during the years ended December 31, 2016 and 2015: Year Ended December 31, 2016 (Predecessor) Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Term Aggregate Intrinsic Value Options outstanding, beginning of period 14,447 $ 269.25 Granted — — Exercised — — Forfeited — — Expired (1,500 ) 477.45 Options outstanding, end of period 12,947 245.13 1.4 years $ — Options exercisable, end of period 12,947 245.13 1.4 years — Options unvested, end of period — — — — Year Ended December 31, 2015 (Predecessor) Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Term Aggregate Intrinsic Value Options outstanding, beginning of period 20,497 $ 339.36 Granted — — Exercised — — Forfeited — — Expired (6,050 ) 506.76 Options outstanding, end of period 14,447 269.25 2.1 years $ — Options exercisable, end of period 14,447 269.25 2.1 years — Options unvested, end of period — — — — Restricted Stock and Other Stock Awards. Immediately prior to emergence, the vesting of all Predecessor outstanding, unvested share-based awards for non-executive employees was accelerated and, as a result, all unrecognized compensation cost related to such awards was recognized. Upon emergence from bankruptcy, all Predecessor outstanding, unvested restricted shares held by the Company’s executives were cancelled and exchanged for a proportionate share of the 5% of New Common Stock, plus a proportionate share of the warrants for ownership of up to 15% of the Successor Company’s common equity. Vesting continued in accordance with the applicable vesting provisions of the original awards (see Successor Share-Based Compensation below). During the period from January 1, 2017 through February 28, 2017, 10,404 shares (valued at $69 thousand ) of Predecessor Company stock were issued, representing grants of stock to the board of directors of the Predecessor Company. During the years ended December 31, 2016 and 2015, we issued 31,313 shares (valued at $0.3 million ) and 141,872 shares (valued at $23.7 million ), respectively, of Predecessor Company restricted stock or stock awards. The following table includes Predecessor Company restricted stock and stock award activity during the period from January 1, 2017 through February 28, 2017 and the years ended December 31, 2016 and 2015: Predecessor Period from Year Ended December 31, 2016 2015 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 81,090 $ 205.34 180,239 $ 208.17 129,848 $ 299.45 Issuances 10,404 6.67 31,313 8.93 141,872 167.21 Lapse of restrictions or granting of stock awards (73,276 ) 186.37 (117,406 ) 158.79 (63,745 ) 296.00 Forfeitures (194 ) 169.40 (13,056 ) 200.06 (27,736 ) 223.80 Restricted stock outstanding, end of period 18,024 $ 169.42 81,090 $ 205.34 180,239 $ 208.17 Successor Share-Based Compensation Restricted Stock and Other Stock Awards. As discussed above, upon emergence from bankruptcy, all Predecessor outstanding, unvested restricted shares held by the Company’s executives were cancelled and exchanged for proportionate shares of New Common Stock. Vesting continued in accordance with the applicable vesting provisions of the original awards, with remaining compensation expense based on the fresh start fair value of $26.95 per share (see Note 3 – Fresh Start Accounting ). For the period from March 1, 2017 through December 31, 2017 (Successor), we incurred approximately $0.1 million of share-based compensation expense related to these restricted shares. The restricted stock outstanding on December 31, 2017 became fully vested on January 15, 2018. The following table includes Successor Company restricted stock and stock award activity during the period from March 1, 2017 through December 31, 2017: Period from March 1, 2017 through December 31, 2017 Number of Restricted Shares Wgtd. Avg. Fair Value Per Share Restricted stock outstanding at February 28, 2017 (Predecessor) 18,024 $ 169.42 Restricted stock outstanding at March 1, 2017 (Successor) 3,176 $ 26.95 Issuances — — Lapse of restrictions (2,083 ) 21.78 Forfeitures — — Restricted stock outstanding at December 31, 2017 (Successor) 1,093 $ 26.95 Restricted Stock Units. On March 1, 2017, the Board received grants of restricted stock units under the 2017 LTIP. The restricted stock units are scheduled to vest in full on the day prior to the annual meeting of the Company’s stockholders in May 2018, subject to: (i) the director’s continued service on the board through the vesting date, and (ii) earlier vesting upon the occurrence of a change of control event or the termination of the director’s service due to death or removal from the board without cause. A total of 62,137 restricted stock units were granted with an aggregate grant date fair value of $1.7 million , based on a per share grant date fair value of $26.95 . During the period from March 1, 2017 through December 31, 2017 (Successor), we incurred approximately $1.2 million of share-based compensation expense related to these restricted stock units. As of December 31, 2017, there was $0.5 million of unrecognized compensation cost related to such restricted stock units, with a current weighted average remaining vesting period of approximately four months.

REDUCTION IN WORKFORCE

REDUCTION IN WORKFORCE	12 Months Ended
	Dec. 31, 2017
Restructuring and Related Activities [Abstract]
REDUCTION IN WORKFORCE	REDUCTION IN WORKFORCE During the second quarter of 2017, we implemented workforce reduction plans to better align our employee base with current business needs, resulting in a reduction of approximately 20% of our total workforce. The workforce reductions were complete as of July 31, 2017. In connection with the reductions, we recognized a charge of $5.7 million , consisting primarily of severance payments to affected employees and payment of related employer payroll taxes. This charge is reflected in SG&A expenses on the statement of operations for the period from March 1, 2017 through December 31, 2017 (Successor). In addition to the workforce reduction costs, during the second quarter of 2017, we recognized a charge of $3.0 million for severance costs related to the sale of the Appalachia Properties and the retirement of the prior chief executive officer of the Company. These severance costs are reflected in SG&A expenses on the statement of operations for the period from March 1, 2017 through December 31, 2017 (Successor).

FEDERAL ROYALTY RECOVERY

FEDERAL ROYALTY RECOVERY	12 Months Ended
	Dec. 31, 2017
Federal Royalty Recovery [Abstract]
FEDERAL ROYALTY RECOVERY	FEDERAL ROYALTY RECOVERY In July 2017, we received a federal royalty recovery totaling $14.1 million as part of a multi-year federal royalty refund claim. Approximately $9.6 million of the refund was recognized as other operational income and $4.5 million as a reduction of lease operating expenses during the period from March 1, 2017 through December 31, 2017 (Successor). Included in SG&A expenses for the period from March 1, 2017 through December 31, 2017 (Successor) is a $3.9 million success-based consulting fee incurred in connection with the federal royalty recovery.

OTHER OPERATIONAL EXPENSES

OTHER OPERATIONAL EXPENSES	12 Months Ended
	Dec. 31, 2017
Other Income and Expenses [Abstract]
OTHER OPERATIONAL EXPENSES	OTHER OPERATIONAL EXPENSES Other operational expenses for the period of March 1, 2017 through December 31, 2017 (Successor) of $3.4 million included approximately $2.1 million of stacking charges for the Pompano platform rig. For the year ended December 31, 2016 (Predecessor), other operational expenses of $55.5 million included approximately $17.7 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, an Appalachian drilling rig and the platform rig at Pompano, a $20.0 million charge related to the termination of our deep water drilling rig contract with Ensco and $9.9 million in charges related to the terminations of offshore vessel and Appalachian drilling rig contracts. Also included in other operational expenses for the year ended December 31, 2016 (Predecessor) is a $6.1 million loss on the liquidation of our former foreign subsidiary, Stone Energy Canada, ULC, representing cumulative foreign currency translation adjustments, which were reclassified from accumulated other comprehensive income. See Note 14 – Accumulated Other Comprehensive Income (Loss) .

COMBINATION TRANSACTION COSTS

COMBINATION TRANSACTION COSTS	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
COMBINATION TRANSACTION COSTS	COMBINATION TRANSACTION COSTS In connection with the pending combination with Talos, we have incurred approximately $6.2 million in transaction costs, consisting primarily of legal and financial advisor costs. These costs are included in SG&A expense on our statement of operations for the period from March 1, 2017 through December 31, 2017 (Successor). Additionally, we have incurred approximately $0.2 million of direct costs for purposes of registering equity securities to effect the Talos combination. These direct costs are recorded as a reduction of additional paid-in-capital during the period from March 1, 2017 through December 31, 2017 (Successor). See Note 1 – Organization and Summary of Significant Accounting Policies for more information on the pending combination.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES Legal Proceedings 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. Leases We lease office facilities in Lafayette and New Orleans, Louisiana under the terms of non-cancelable leases expiring on various dates in 2018 . We also lease certain equipment on our oil and gas properties typically on a month-to-month basis. The minimum net commitment for 2018 under our leases, subleases and contracts at December 31, 2017 totaled $0.3 million . Payments related to our lease obligations were $0.5 million for the period from March 1, 2017 through December 31, 2017 (Successor) and $0.1 million for the period of January 1, 2017 through February 28, 2017 (Predecessor). Payments related to our lease obligations for the years ended December 31, 2016 and 2015 (Predecessor) were approximately $0.7 million and $3.1 million , respectively. Other Commitments and Contingencies On March 21, 2016, we received notice letters from the Bureau of Ocean Energy Management (“BOEM”) stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at such time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM towards finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $115 million in surety bonds in favor of BOEM, third-party bonds, and letters of credit, all relating to our offshore abandonment obligations. In July 2016, BOEM issued a Notice to Lessees (the “NTL”), with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurances by offshore lessees. The NTL details procedures to determine a lessee’s ability to carry out its lease obligations (primarily the decommissioning of OCS facilities) and whether to require lessees to furnish additional financial assurances to meet BOEM’s estimate of the lessees decommissioning obligations. The NTL supersedes the agency’s prior practice of allowing operators of a certain net worth to waive the need for supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure only a small portion of its OCS liabilities based upon the lessee’s financial capacity and financial strength. The NTL also allows lessees to meet their additional financial security requirements pursuant to an individually approved tailored plan, whereby an operator and BOEM agree to set a timeframe for the posting of additional financial assurances. We received a self-insurance letter from BOEM dated September 30, 2016 stating that we were not eligible to self-insure any of our additional security obligations. We received a proposal letter from BOEM dated October 20, 2016 indicating that additional security may be required. The September 30, 2016 self-insurance determination letter was rescinded by BOEM on March 24, 2017. In the first quarter of 2017, BOEM announced that it would extend the implementation timeline for the July 2016 NTL by an additional six months. Furthermore, on April 28, 2017, President Trump issued an executive order directing the Secretary of the Interior to review the NTL to determine whether modifications are necessary to ensure operator compliance with lease terms while minimizing unnecessary regulatory burdens. On June 22, 2017, BOEM announced that, pending its review of the NTL, the implementation timeline would be indefinitely extended, subject to certain exceptions. At this time, it is uncertain when, or if, the July 2016 NTL will be implemented or whether a revised NTL might be proposed. A revised tailored plan may require incremental financial assurance or bonding for non-sole liability properties, dependent on adjustments following ongoing discussions with BOEM and the Bureau of Safety and Environmental Enforcement, and any modifications to the proposed NTL. There is no assurance that our current tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan. In connection with our exploration and development efforts, we are contractually committed to the acquisition of seismic data in the amount of $8.6 million to be incurred over the next two years. The Oil Pollution Act (“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 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 million in specified state waters to at least $35 million in Outer Continental Shelf waters, with higher amounts of up to $150 million in certain limited circumstances where 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 BOEM’s final rule. In addition, BOEM has finalized rules that raise OPA’s damages liability cap from $75 million to $133.7 million .

SUPPLEMENTAL INFORMATION ON OIL

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED	SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS – UNAUDITED At December 31, 2017 and 2016 , our oil and gas properties were located in the United States (onshore and offshore). On February 27, 2017, we completed the sale of the Appalachia Properties in connection with our restructuring (see Note 4 – Divestiture ). During 2015 , we discontinued our business development effort in Canada. With the adoption of fresh start accounting, the Company recorded its oil and gas properties at fair value as of February 28, 2017. The Company’s proved, probable and possible reserves and unevaluated properties (including inventory) were assigned values of $380.8 million , $16.8 million and $80.2 million , respectively. See Note 3 – Fresh Start Accounting for a discussion of the valuation approach used. Costs Incurred United States . The following table discloses the total amount of capitalized costs and accumulated DD&A relative to our proved and unevaluated oil and natural gas properties located in the United States (in thousands): Successor Predecessor December 31, 2017 December 31, 2016 Proved properties $ 713,157 $ 9,572,082 Unevaluated properties 102,187 373,720 Total proved and unevaluated properties 815,344 9,945,802 Less accumulated depreciation, depletion and amortization (353,462 ) (9,134,288 ) Balance, end of year $ 461,882 $ 811,514 The following table sets forth certain information regarding the costs incurred in our acquisition, exploratory and development activities in the United States during the periods indicated (in thousands): Successor Predecessor Period from March 1, 2017 through December 31, 2017 Period from January 1, 2017 through February 28, 2017 Year Ended December 31, 2016 2015 Costs incurred during the period (capitalized): Acquisition costs, net of sales of unevaluated properties $ (8,371 ) $ (324 ) $ 3,923 $ (14,158 ) Exploratory costs 12,079 2,055 17,891 104,169 Development costs (1) 33,356 12,547 102,665 266,982 Salaries, general and administrative costs 7,495 2,976 21,753 27,984 Interest 3,927 2,524 26,634 41,339 Less: overhead reimbursements (1,004 ) — (521 ) (913 ) Total costs incurred during the period, net of divestitures $ 47,482 $ 19,778 $ 172,345 $ 425,403 (1) Includes net changes in capitalized asset retirement costs of ($17,446) , $0 , ($4,461) and ($43,901) , respectively. The following table discloses operational expenses incurred during the periods indicated relative to our oil and natural gas producing activities located in the United States (in thousands): Successor Predecessor Period from Period from Year Ended December 31, 2016 2015 Lease operating expenses $ 49,800 $ 8,820 $ 79,650 $ 100,139 Transportation, processing and gathering expenses 4,084 6,933 27,760 58,847 Production taxes 629 682 3,148 6,877 Accretion expense 21,151 5,447 40,229 25,988 Expensed costs – United States $ 75,664 $ 21,882 $ 150,787 $ 191,851 The following table sets forth certain information relative to the amortization of our investment in oil and gas properties and the impairment of our oil and gas properties in the United States for the periods indicated (in thousands, except per unit amounts): Successor Predecessor Period from March 1, 2017 through December 31, 2017 Period from January 1, 2017 through February 28, 2017 Year Ended December 31, 2016 2015 Provision for DD&A $ 97,027 $ 36,751 $ 215,737 $ 277,088 Write-down of oil and gas properties $ 256,435 $ — $ 357,079 $ 1,314,817 DD&A per Boe $ 16.61 $ 17.05 $ 16.10 $ 19.15 At March 31, 2017 (Successor), our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $256.4 million based on twelve-month average prices, net of applicable differentials, of $45.40 per Bbl of oil, $2.24 per Mcf of natural gas and $19.18 per Bbl of NGLs. The write-down at March 31, 2017 is reflected in the statement of operations of the Successor Company for the period from March 1, 2017 through December 31, 2017 and was primarily due to differences between the trailing twelve-month average pricing assumption used in calculating the ceiling test and the forward prices used in fresh start accounting to estimate the fair value of our oil and gas properties on the fresh start reporting date of February 28, 2017. Weighted average commodity prices used in the determination of the fair value of our oil and gas properties for purposes of fresh start accounting were $56.01 per Bbl of oil, $2.52 per Mcf of natural gas and $14.18 per Bbl of NGLs, net of applicable differentials. Since none of our derivatives as of March 31, 2017 were designated as cash flow hedges (see Note 9 – Derivative Instruments and Hedging Activities ), the write-down at March 31, 2017 was not affected by hedging. The 2016 and 2015 write-downs were decreased by $50.7 million and $143.9 million , 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 periods indicated (in thousands): Successor Predecessor Period from March 1, 2017 through December 31, 2017 Period from January 1, 2017 through February 28, 2017 Year Ended December 31, 2016 2015 Net costs incurred (evaluated) during period: Acquisition costs $ (9,155 ) $ 959 $ (71,378 ) $ (115,767 ) Exploration costs 10,405 (6,063 ) (21,579 ) (16,315 ) Capitalized interest 3,927 2,524 26,634 41,339 $ 5,177 $ (2,580 ) $ (66,323 ) $ (90,743 ) Under fresh start accounting, our oil and gas properties were recorded at fair value as of February 28, 2017. The following table discloses financial data associated with unevaluated costs (United States) for the Successor Company at December 31, 2017 (in thousands): Successor Net Costs Incurred During the Period from March 1, 2017 through December 31, 2017 Successor March 1, 2017 December 31, 2017 Acquisition costs $ 58,359 $ (9,155 ) $ 49,204 Exploration costs 38,651 10,405 49,056 Capitalized interest — 3,927 3,927 Total unevaluated costs $ 97,010 $ 5,177 $ 102,187 Approximately 34 specifically identified drilling projects are included in unevaluated costs at December 31, 2017 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. Canada . 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, we discontinued our business development effort in Canada during 2015 and recognized a full impairment of our Canadian oil and gas properties. The following table discloses certain financial data relative to our oil and gas activities located in Canada (in thousands): Predecessor Year Ended December 31, 2016 2015 Oil and gas properties – Canada: Balance, beginning of year $ 42,484 $ 36,579 Costs incurred during the year (capitalized): Acquisition costs (498 ) (2,862 ) Exploratory costs 2,168 8,767 Total costs incurred during the year 1,670 5,905 Balance, end of year (fully evaluated at December 31, 2016 and 2015) $ 44,154 $ 42,484 Accumulated DD&A: Balance, beginning of year $ (42,484 ) $ — Foreign currency translation adjustment (1,318 ) 5,146 Write-down of oil and gas properties (352 ) (47,630 ) Balance, end of year $ (44,154 ) $ (42,484 ) Net capitalized costs – Canada $ — $ — Proved Oil and Natural Gas Quantities Our estimated net proved oil and natural gas reserves at December 31, 2017 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 are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a historical twelve-month average pricing assumption. Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Oil, Natural Gas and NGLs (MBoe) Estimated proved developed and undeveloped reserves: As of December 31, 2014 (Predecessor) 42,397 27,817 493,843 152,520 Revisions of previous estimates (6,818 ) (20,777 ) (362,102 ) (87,945 ) Extensions, discoveries and other additions 862 11 1,499 1,123 Purchase of producing properties 685 1,808 26,136 6,849 Sale of reserves (859 ) — (1,061 ) (1,036 ) Production (5,991 ) (2,401 ) (36,457 ) (14,468 ) As of December 31, 2015 (Predecessor) 30,276 6,458 121,858 57,043 Revisions of previous estimates (751 ) 6,352 24,858 9,744 Extensions, discoveries and other additions 63 2 45 73 Production (6,308 ) (2,183 ) (29,441 ) (13,398 ) As of December 31, 2016 (Predecessor) 23,280 10,629 117,320 53,462 Revisions of previous estimates 730 (2 ) 1,242 935 Sale of reserves (826 ) (7,417 ) (52,992 ) (17,075 ) Production (908 ) (408 ) (5,037 ) (2,156 ) As of February 28, 2017 (Predecessor) 22,276 2,802 60,533 35,166 Revisions of previous estimates 3,769 (94 ) (2,801 ) 3,208 Production (4,169 ) (403 ) (7,616 ) (5,841 ) As of December 31, 2017 (Successor) 21,876 2,305 50,116 32,533 Estimated proved developed reserves: As of December 31, 2015 (Predecessor) 21,734 4,784 90,262 41,562 As of December 31, 2016 (Predecessor) 18,269 9,255 90,741 42,647 As of February 28, 2017 (Predecessor) 18,344 1,515 35,865 25,836 As of December 31, 2017 (Successor) 20,275 1,689 37,946 28,288 Estimated proved undeveloped reserves: As of December 31, 2015 (Predecessor) 8,542 1,674 31,596 15,481 As of December 31, 2016 (Predecessor) 5,011 1,374 26,579 10,815 As of February 28, 2017 (Predecessor) 3,932 1,287 24,668 9,330 As of December 31, 2017 (Successor) 1,601 616 12,170 4,245 The following narrative provides the reasons for the significant changes in the quantities of our estimated proved reserves by year. 2017 Periods. Revisions of previous estimates were primarily the result of positive well performance ( 4 MMBoe). The sale of reserves represents the sale of the Appalachia Properties ( 17 MMBoe) in connection with our restructuring (see Note 4 – Divestiture ). Year Ended December 31, 2016. Revisions of previous estimates were primarily the result of positive reserve report gas pricing changes extending the economic limits of the reservoirs ( 15 MMBoe) primarily in Appalachia, slightly offset by negative well performance ( 6 MMBoe). Year Ended December 31, 2015. Revisions of previous estimates were primarily the result of the significant decline in commodity prices resulting in uneconomic reserves ( 95 MMBoe) primarily in Appalachia, slightly offset by positive well performance ( 7 MMBoe). 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. 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, 2017 . 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 twelve-month average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. 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. Our GOM Basin properties represented 100% of our estimated proved oil and natural gas reserves and standardized measure of discounted future net cash flows at December 31, 2017. The standardized measure of discounted future net cash flows and changes therein are as follows (in thousands, except average prices): Standardized Measure Successor Predecessor December 31, December 31, 2017 2016 2015 Future cash inflows $ 1,264,809 $ 1,236,097 $ 1,921,329 Future production costs (497,538 ) (480,815 ) (651,396 ) Future development costs (431,752 ) (638,988 ) (679,355 ) Future income taxes — — — Future net cash flows 335,519 116,294 590,578 10% annual discount 57,591 109,628 13,259 Standardized measure of discounted future net cash flows $ 393,110 $ 225,922 $ 603,837 Average prices related to proved reserves: Oil (per Bbl) $ 50.05 $ 40.15 $ 51.16 NGLs (per Bbl) 22.90 9.46 16.40 Natural gas (per Mcf) 2.34 1.71 2.19 Changes in Standardized Measure Successor Predecessor Period from March 1, 2017 through December 31, 2017 Period From January 1, 2017 through February 28, 2017 Year Ended December 31, 2016 2015 Standardized measure at beginning of period $ 303,086 $ 225,922 $ 603,837 $ 1,418,792 Sales and transfers of oil, natural gas and NGLs produced, net of production costs (164,612 ) (46,137 ) (223,948 ) (340,477 ) Changes in price, net of future production costs 66,192 17,455 (448,861 ) (237,747 ) Extensions and discoveries, net of future production and development costs — — 5,243 1,573 Changes in estimated future development costs, net of development costs incurred during the period 88,111 20,756 54,406 731,115 Revisions of quantity estimates 96,454 36,557 139,759 (1,458,652 ) Accretion of discount 30,309 22,592 60,384 174,456 Net change in income taxes — — — 325,768 Purchases of reserves in-place — — — 3,493 Sales of reserves in-place — 14,584 — — Changes in production rates due to timing and other (26,430 ) 11,357 35,102 (14,484 ) Net change in standardized measure 90,024 77,164 (377,915 ) (814,955 ) Standardized measure at end of period $ 393,110 $ 303,086 $ 225,922 $ 603,837

SUMMARIZED QUARTERLY FINANCIAL

SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED	SUMMARIZED QUARTERLY FINANCIAL INFORMATION – UNAUDITED The Company’s results of operations by quarter are as follows (in thousands, except per share amounts): Predecessor Successor Period from Period from 2017 Quarter Ended June 30 Sept. 30 Dec. 31 Operating revenue $ 68,922 $ 25,809 $ 76,722 $ 79,525 $ 76,327 Income (loss) from operations $ 209,119 $ (258,594 ) $ (4,519 ) $ 2,653 $ 5,302 Net income (loss) $ 630,317 $ (259,613 ) $ (6,461 ) $ 1,297 $ 17,138 Basic income (loss) per share $ 110.99 $ (12.98 ) $ (0.32 ) $ 0.06 $ 0.86 Diluted income (loss) per share $ 110.99 $ (12.98 ) $ (0.32 ) $ 0.06 $ 0.86 Write-down of oil and gas properties $ — $ 256,435 $ — $ — $ — Gain (loss) on Appalachia Properties divestiture $ 213,453 $ — $ 27 $ (132 ) $ — Reorganization items (1) $ (437,744 ) $ — $ — $ — $ — Other expense $ 13,336 $ — $ 814 $ 47 $ 369 (1) See Note 3 – Fresh Start Accounting for additional details. Predecessor 2016 Quarter Ended March 31 June 30 Sept. 30 Dec. 31 Operating revenue $ 80,677 $ 89,319 $ 94,427 $ 113,107 Loss from operations $ (172,150 ) $ (174,656 ) $ (72,128 ) $ (90,234 ) Net loss $ (188,784 ) $ (195,761 ) $ (89,635 ) $ (116,406 ) Basic loss per share $ (33.89 ) $ (35.05 ) $ (16.01 ) $ (20.76 ) Diluted loss per share $ (33.89 ) $ (35.05 ) $ (16.01 ) $ (20.76 ) Write-down of oil and gas properties $ 129,204 $ 118,649 $ 36,484 $ 73,094 Restructuring fees $ 953 $ 9,436 $ 5,784 $ 13,424 Other operational expenses (1) $ 12,527 $ 27,680 $ 9,059 $ 6,187 Reorganization items $ — $ — $ — $ 10,947 (1) See Note 19 – Other Operational Expenses for additional details.

NEW YORK STOCK EXCHANGE COMPLIA

NEW YORK STOCK EXCHANGE COMPLIANCE	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
NEW YORK STOCK EXCHANGE COMPLIANCE	NEW YORK STOCK EXCHANGE COMPLIANCE On May 17, 2016, we were notified by the New York Stock Exchange (the “NYSE”) that our average global market capitalization had been less than $50 million over a consecutive 30 trading-day period at the same time that our stockholders’ equity was less than $50 million , which is non-compliant with Section 802.01B of the NYSE Listed Company Manual. On June 30, 2016, we submitted our 18-month business plan for curing the average market capitalization and stockholders’ equity deficiencies to the NYSE, and on August 4, 2016, the NYSE accepted the Plan. All of our quarterly updates to the business plan were accepted by the NYSE. Since March 1, 2017, the first day of trading subsequent to the effective date of the Company’s plan of reorganization, the Successor Company has maintained a market capitalization above $50 million . On August 24, 2017, we were notified by the NYSE that we are back in compliance with their continued listing standards as a result of the Company’s consistent positive performance with respect to the original business plan submission and the achievement of compliance with the average global market capitalization and stockholders’ equity listing requirements over the past two quarters. In accordance with the NYSE’s Listed Company Manual, we will be subject to a 12-month follow up period within which the Company will be reviewed to ensure that the Company does not fall below any of the NYSE’s continued listing standards.

ORGANIZATION AND SUMMARY OF S32

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation and Reorganization	Basis of Presentation: The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Offshore, Stone Energy Holding, L.L.C. and Stone Energy Canada, ULC. On August 29, 2016, our subsidiaries SEO A LLC and SEO B LLC were merged into Stone Offshore. On December 2, 2016, Stone Energy Canada, ULC was dissolved. All intercompany balances have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation. Reorganization and Fresh Start Accounting: For periods subsequent to the Chapter 11 filing, but prior to emergence, ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees and other expenses incurred in the Chapter 11 cases, and unamortized debt issuance costs, premiums and discounts associated with debt classified as liabilities subject to compromise, have been recorded as reorganization items on the consolidated statement of operations for the applicable periods. In addition, pre-petition obligations that were to be impacted by the Chapter 11 process were classified on the consolidated balance sheet at December 31, 2016 as liabilities subject to compromise. See Note 2 – Reorganization and Note 3 – Fresh Start Accounting for more information regarding reorganization items and liabilities subject to compromise. Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with the provisions of ASC 852, as (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the post-petition liabilities and allowed claims. The Company applied fresh start accounting as of February 28, 2017. Fresh start accounting required the Company to present its assets, liabilities and equity as if it were a new entity upon emergence from bankruptcy, with no beginning retained earnings or deficit as of the fresh start reporting date. The new entity is referred to as Successor or Successor Company, and includes the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to Predecessor or Predecessor Company relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017. The Chapter 11 proceedings did not include our former foreign subsidiary Stone Energy Canada, ULC.
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. The Company bases its estimates on historical experience and on various assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects are uncertain and, accordingly, these estimates may change as new events occur, as additional information is obtained and as the Company’s operating environment changes. 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, estimated fair value of derivative contracts, contingencies and fair value estimates, including estimates of reorganization value, enterprise value and the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting.
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, 2017 and 2016 , 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. 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, 2017 (Successor) and 2016 (Predecessor), we held certain financial assets 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. The income approach is used in this determination utilizing the third party’s 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 and put contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars and puts are the volatility impacts in the pricing model as it relates to the call portion of the collar and the floor of the put. For a more detailed description of our derivative instruments, see Note 9 – 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.
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. Our estimated net proved oil and natural gas reserves at December 31, 2017 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.
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, timing of abandonment 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.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities: Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. Accordingly, the contracts were recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. Monthly settlements of effective hedges were reflected in revenue from oil and natural gas production. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements of these derivative contracts are recorded in earnings through derivative income (expense). 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. We do not enter into derivative transactions for trading purposes. All derivatives are recognized as assets or liabilities on the balance sheet and are measured at fair value. At the end of each quarterly period, these derivatives are marked-to-market. If the derivative does not qualify or is not designated as a cash flow hedge, subsequent changes in the fair value of the derivative are recognized in earnings through derivative income (expense) in the statement of operations. If the derivative qualifies and is designated as a cash flow hedge, subsequent changes in the fair value of the derivative 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 cash flow hedges are reflected in revenue from oil and natural gas production. Monthly settlements of ineffective hedges and derivatives not designated or that do not qualify for hedge accounting are recognized in earnings through derivative income (expense). The resulting cash flows from all monthly settlements are reported as cash flows from operating activities. Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. A small portion of our cash flow hedges were typically determined to be ineffective because oil and natural gas price changes in the markets in which we sell our products were not 100% correlative to changes in the underlying price basis indicative in the derivative contract. We had no outstanding derivatives at December 31, 2016. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements of these derivative contracts will be recorded in earnings through derivative income (expense). We have entered into put contracts, fixed-price swaps and collar contracts with various counterparties for a portion of our expected 2018 and 2019 oil and natural gas production from the Gulf Coast Basin. 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 typically enter 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 March 9, 2018 , our derivative instruments were with four counterparties, two of which accounted for approximately 64% of our contracted volumes. Currently, all of our outstanding derivative instruments are with lenders under our current bank credit facility. Put contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The historical cost of the put contract represents our maximum cash exposure. We are not obligated to make any further payments under the put contract regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if the New York Mercantile Exchange (“NYMEX”) prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above the floor. 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. Settlements for our oil put contracts, oil collar contracts and fixed-price oil swaps are based on an average of the NYMEX closing price for West Texas Intermediate crude oil during the entire calendar month. Settlements for our natural gas collar contracts and fixed-price natural gas swaps are based on the NYMEX price for the last day of a respective contract month.
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 costs relative to successful wells are capitalized and recovered through DD&A, although for 2015 , 2016 and 2017 , 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 (the “IRC”) 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.
Share-Based Compensation	Share-Based Compensation: We record share-based compensation using the grant date fair value of issued stock options, stock awards, restricted stock and restricted stock units 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 stock awards, restricted stock and restricted stock units is typically determined based on the average of our high and low stock prices on the grant date.
Combination Transaction Costs	Combination Transaction Costs: In general, acquisition-related costs are expensed in the periods in which the costs are incurred and the services are rendered. However, some direct costs of an acquisition, such as the cost of registering and issuing equity securities to effect a business combination, are recorded as a reduction of additional paid-in-capital when incurred.
Recently Issued Accounting Standards	Recently Issued Accounting Standards: In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “ Revenue from Contracts with Customers (Topic 606) ” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers including the disaggregation of revenue and remaining performance obligations. 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, and is effective for interim and annual periods beginning on or after December 15, 2017. We adopted this new standard on January 1, 2018 using the modified retrospective approach. The adoption of the standard did not have a material effect on our financial position, results of operations or cash flows, but will result in increased disclosures related to revenue recognition policies and disaggregation of revenues. In February 2016, the FASB issued ASU 2016-02, “ Leases (Topic 842) ” to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public companies for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements and related disclosures. In March 2016, the FASB issued ASU 2016-09, “ Compensation – Stock Compensation (Topic 718) ” to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. ASU 2016-09 became effective for us on January 1, 2017. Under ASU 2016-09, we elected to not apply a forfeiture estimate and will recognize a credit in compensation expense to the extent awards are forfeited. The implementation of this new standard did not have a material effect on our financial statements or related disclosures. In August 2017, the FASB issued ASU 2017-12, “ Derivatives and Hedging (Topic 815) ” to improve the financial reporting of hedging relationships to better reflect an entity’s hedging strategies. The standard expands an entity’s ability to apply hedge accounting for both non-financial and financial risk components and amends the presentation and disclosure requirements. Additionally, ASU 2017-12 eliminates the need to separately measure and report hedge ineffectiveness and generally requires the entire change in fair value of a hedging instrument to be recorded in the same income statement line as the earnings effect of the hedged item. The standard is effective for public companies for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted. The standard must be adopted by applying a modified retrospective approach to existing designated hedging relationships as of the adoption date, with a cumulative effect adjustment recorded to opening retained earnings as of the initial adoption date. We are currently evaluating the effect that this new standard may have on our financial statements and related disclosures.

FRESH START ACCOUNTING (Tables)

FRESH START ACCOUNTING (Tables)	12 Months Ended
	Dec. 31, 2017
Reorganizations [Abstract]
Reconciliation of Enterprise Value to Estimated Fair Value of Successor Common Stock	The following table reconciles the enterprise value per the Plan to the estimated fair value (for fresh start accounting purposes) of the Successor Company’s common stock as of February 28, 2017 (in thousands, except per share value): February 28, 2017 Enterprise value $ 419,720 Plus: Cash and other assets 371,278 Less: Fair value of debt (236,261 ) Less: Fair value of warrants (15,648 ) Fair value of Successor common stock $ 539,089 Shares issued upon emergence 20,000 Per share value $ 26.95
Reconciliation of Enterprise Value to Estimated Reorganization Value	The following table reconciles the enterprise value per the Plan to the estimated reorganization value as of the Effective Date (in thousands): February 28, 2017 Enterprise value $ 419,720 Plus: Cash and other assets 371,278 Plus: Asset retirement obligations (current and long-term) 290,067 Plus: Working capital and other liabilities 58,055 Reorganization value of Successor assets $ 1,139,120
Schedule of Fresh-Start Adjustments	The following table reflects the reorganization and application of ASC 852 on our consolidated balance sheet as of February 28, 2017 (in thousands): Predecessor Company Reorganization Adjustments Fresh Start Adjustments Successor Company Assets Current assets: Cash and cash equivalents $ 198,571 $ (35,605 ) (1) $ — $ 162,966 Restricted cash — 75,547 (1) — 75,547 Accounts receivable 42,808 9,301 (2) — 52,109 Fair value of derivative contracts 1,267 — — 1,267 Current income tax receivable 22,516 — — 22,516 Other current assets 11,033 875 (3) (124 ) (12) 11,784 Total current assets 276,195 50,118 (124 ) 326,189 Oil and gas properties, full cost method of accounting: Proved 9,633,907 (188,933 ) (1) (8,774,122 ) (12) 670,852 Less: accumulated DD&A (9,215,679 ) — 9,215,679 (12) — Net proved oil and gas properties 418,228 (188,933 ) 441,557 670,852 Unevaluated 371,140 (127,838 ) (1) (146,292 ) (12) 97,010 Other property and equipment, net 25,586 (101 ) (4) (4,423 ) (13) 21,062 Fair value of derivative contracts 1,819 — — 1,819 Other assets, net 26,516 (4,328 ) (5) — 22,188 Total assets $ 1,119,484 $ (271,082 ) $ 290,718 $ 1,139,120 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable to vendors $ 20,512 $ — $ — $ 20,512 Undistributed oil and gas proceeds 5,917 (4,139 ) (1) — 1,778 Accrued interest 266 — — 266 Asset retirement obligations 92,597 — — 92,597 Fair value of derivative contracts 476 — — 476 Current portion of long-term debt 411 — — 411 Other current liabilities 17,032 (195 ) (6) — 16,837 Total current liabilities 137,211 (4,334 ) — 132,877 Long-term debt 352,350 (116,500 ) (7) — 235,850 Asset retirement obligations 151,228 (8,672 ) (1) 54,914 (14) 197,470 Fair value of derivative contracts 653 — — 653 Other long-term liabilities 17,533 — — 17,533 Total liabilities not subject to compromise 658,975 (129,506 ) 54,914 584,383 Liabilities subject to compromise 1,110,182 (1,110,182 ) (8) — — Total liabilities 1,769,157 (1,239,688 ) 54,914 584,383 Commitments and contingencies Stockholders’ equity: Common stock (Predecessor) 56 (56 ) (9) — — Treasury stock (Predecessor) (860 ) 860 (9) — — Additional paid-in capital (Predecessor) 1,660,810 (1,660,810 ) (9) — — Common stock (Successor) — 200 (10) — 200 Additional paid-in capital (Successor) — 554,537 (10) — 554,537 Accumulated deficit (2,309,679 ) 2,073,875 (11) 235,804 (15) — Total stockholders’ equity (649,673 ) 968,606 235,804 554,737 Total liabilities and stockholders’ equity $ 1,119,484 $ (271,082 ) $ 290,718 $ 1,139,120 Reorganization Adjustments 1. Reflects the net cash proceeds received from the sale of the Appalachia Properties in connection with the Plan and net cash payments made as of the Effective Date from implementation of the Plan (in thousands): Sources: Net cash proceeds from sale of Appalachia Properties (a) $ 512,472 Total sources 512,472 Uses: Cash transferred to restricted account (b) 75,547 Break-up fee to Tug Hill 10,800 Repayment of outstanding borrowings under Pre-Emergence Credit Agreement 341,500 Repayment of 2017 Convertible Notes and 2022 Notes 100,000 Other fees and expenses (c) 20,230 Total uses 548,077 Net uses $ (35,605 ) (a) The closing of the sale of the Appalachia Properties occurred on February 27, 2017, but as emergence was contingent on such closing, the effects of the transaction are reflected as reorganization adjustments. See Note 4 – Divestiture for additional details on the sale. Total consideration received for the sale of the Appalachia Properties of $522.5 million included cash consideration of $512.5 million received at closing and a $10.0 million indemnity escrow which was released subsequent to emergence from bankruptcy (see Reorganization Adjustments item number 2 below). (b) Reflects the movement of $75.0 million of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the provisions of the Amended Credit Agreement (as defined in Note 13 – Debt ), and $0.5 million held in a restricted cash account for certain cure amounts in connection with the Chapter 11 proceedings. (c) Other fees and expenses include approximately $15.2 million of emergence and success fees, $2.7 million of professional fees and $2.4 million of payments made to seismic providers in settlement of their bankruptcy claims. 2. Reflects a receivable for a $10.0 million indemnity escrow with release delayed until emergence from bankruptcy, net of a $0.7 million reimbursement to Tug Hill in connection with the sale of the Appalachia Properties (see Note 4 – Divestiture ). 3. Reflects the payment of a claim to a seismic provider as a prepayment/deposit. 4. Reflects the sale of vehicles in connection with the sale of the Appalachia Properties. 5. Reflects the write-off of $2.6 million of unamortized debt issuance costs related to the Pre-Emergence Credit Agreement and the reversal of a $1.8 million prepayment made to Tug Hill in October 2016. 6. Reflects the accrual of $2.0 million in expected bonus payments under the KEIP (as defined in Note 15 – Employee Benefit Plans ) and a $0.4 million termination fee in connection with the early termination of an office lease, less the settlement of a property tax accrual of $2.6 million in connection with the sale of the Appalachia Properties. 7. Reflects the repayment of $341.5 million of outstanding borrowings under the Pre-Emergence Credit Agreement and the issuance of $225 million of 2022 Second Lien Notes as part of the settlement of the Predecessor Company 2017 Convertible Notes and 2022 Notes. 8. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands): 1 ¾% Senior Convertible Notes due 2017 $ 300,000 7 ½% Senior Notes due 2022 775,000 Accrued interest 35,182 Liabilities subject to compromise of the Predecessor Company 1,110,182 Cash payment to senior noteholders (100,000 ) Issuance of 2022 Second Lien Notes to former holders of the senior notes (225,000 ) Fair value of equity issued to unsecured creditors (539,089 ) Fair value of warrants issued to unsecured creditors (15,648 ) Gain on settlement of liabilities subject to compromise $ 230,445 9. Reflects the cancellation of the Predecessor Company’s common stock, treasury stock and additional paid-in capital. 10. Reflects the issuance of Successor Company equity. In accordance with the Plan, the Successor Company issued 19.0 million shares of New Common Stock to the former holders of the 2017 Convertible Notes and the 2022 Notes and 1.0 million shares of New Common Stock to the Predecessor Company’s common stockholders. These amounts are subject to dilution by warrants issued to the Predecessor Company common stockholders, totaling approximately 3.5 million shares, with an exercise price of $42.04 per share and a term of four years. The fair value of the warrants was estimated at $4.43 per share using a Black-Scholes-Merton valuation model. 11. Reflects the cumulative impact of the reorganization adjustments discussed above (in thousands): Gain on settlement of liabilities subject to compromise $ 230,445 Professional and other fees paid at emergence (10,648 ) Write-off of unamortized debt issuance costs (2,577 ) Other reorganization adjustments (1,915 ) Net impact to reorganization items 215,305 Gain on sale of Appalachia Properties 213,453 Cancellation of Predecessor Company equity 1,662,282 Other adjustments to accumulated deficit (17,165 ) Net impact to accumulated deficit $ 2,073,875
Summary of Reorganization Items	The following table summarizes reorganization items, net (in thousands): Predecessor Period from Gain on settlement of liabilities subject to compromise $ 230,445 Fresh start valuation adjustments 235,804 Reorganization professional fees and other expenses (20,403 ) Write-off of unamortized debt issuance costs (2,577 ) Other reorganization items (5,525 ) Gain on reorganization items, net $ 437,744

DIVESTITURE (Tables)

DIVESTITURE (Tables)	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Net Gain Recognized in Sale	The gain on the sale of the Appalachia Properties is computed as follows (in thousands): Net consideration received for sale of Appalachia Properties $ 522,472 Add: Release of funds held in suspense 4,139 Transfer of asset retirement obligations 8,672 Other adjustments, net 2,597 Less: Transaction costs (7,087 ) Carrying value of properties sold (317,340 ) Gain on sale $ 213,453

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Calculation of Basic and Diluted Weighted Average Shares and 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 (in thousands, except per share amounts): Successor Predecessor Period from Period from Year Ended December 31, 2016 2015 Income (numerator): Basic: Net income (loss) $ (247,639 ) $ 630,317 $ (590,586 ) $ (1,090,915 ) Net income attributable to participating securities — (4,995 ) — — Net income (loss) attributable to common stock - basic $ (247,639 ) $ 625,322 $ (590,586 ) $ (1,090,915 ) Diluted: Net income (loss) $ (247,639 ) $ 630,317 $ (590,586 ) $ (1,090,915 ) Net income attributable to participating securities — (4,995 ) — — Net income (loss) attributable to common stock - diluted $ (247,639 ) $ 625,322 $ (590,586 ) $ (1,090,915 ) Weighted average shares (denominator): Weighted average shares - basic 19,997 5,634 5,591 5,525 Dilutive effect of stock options — — — — Dilutive effect of warrants — — — — Dilutive effect of convertible notes — — — — Weighted average shares - diluted 19,997 5,634 5,591 5,525 Basic income (loss) per share $ (12.38 ) $ 110.99 $ (105.63 ) $ (197.45 ) Diluted income (loss) per share $ (12.38 ) $ 110.99 $ (105.63 ) $ (197.45 )

ACCOUNTS RECEIVABLE (Tables)

ACCOUNTS RECEIVABLE (Tables)	12 Months Ended
	Dec. 31, 2017
Receivables [Abstract]
Components of Accounts Receivable	Our accounts receivable are comprised of the following amounts (in thousands): Successor Predecessor As of December 31, As of December 31, 2017 2016 Other co-venturers $ 2,656 $ 3,532 Trade 34,980 42,944 Unbilled accounts receivable 820 591 Other 802 1,397 Total accounts receivable $ 39,258 $ 48,464

CONCENTRATIONS (Tables)

CONCENTRATIONS (Tables)	12 Months Ended
	Dec. 31, 2017
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: Successor Predecessor Period from Period from Year Ended December 31, 2016 2015 Phillips 66 Company 74 % 56 % 68 % 53 % Shell Trading (US) Company 15 % 7 % 10 % 13 % Williams Ohio Valley Midstream LLC — % 12 % 2 % 9 % Conoco — % 11 % 5 % 2 %

DERIVATIVE INSTRUMENTS AND HE38

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Positions	The following tables illustrate our derivative positions for calendar years 2018 and 2019 as of March 9, 2018 : Put Contracts (NYMEX) Oil Daily Volume Price (Bbls/d) ($ per Bbl) 2018 January - December 1,000 $ 54.00 2018 January - December 1,000 45.00 Fixed-Price Swaps (NYMEX) Oil Daily Volume Swap Price (Bbls/d) ($ per Bbl) 2018 January - December 1,000 $ 52.50 2018 January - December 1,000 51.98 2018 January - December 1,000 53.67 2019 January - December 1,000 51.00 2019 January - December 1,000 51.57 2019 January - December 2,000 56.13 Collar Contracts (NYMEX) Natural Gas Oil Daily Volume Floor Price Ceiling Price Daily Volume (Bbls/d) Floor Price Ceiling Price 2018 January - December 6,000 $ 2.75 $ 3.24 1,000 $ 45.00 $ 55.35
Gains or Losses Related to Changes in Fair Value and Cash Settlements on Derivatives Not Qualifying as Hedging Instruments	We had no outstanding hedging instruments at December 31, 2016 (Predecessor). Fair Value of Derivatives Not Designated or Not Qualifying as Hedging Instruments at December 31, 2017 (Successor) Asset Derivatives Liability Derivatives Description Balance Sheet Location Fair Balance Sheet Location Fair Commodity contracts Current assets: Fair value of $ 879 Current liabilities: Fair value of derivative contracts $ 8,969 Long-term assets: Fair value — Long-term liabilities: Fair 3,085 $ 879 $ 12,054 The following table discloses the before tax effect of our derivatives not designated or not qualifying as hedging instruments on the statement of operations for the indicated periods (in thousands): Gain (Loss) Recognized in Derivative Income (Expense) Successor Predecessor Period from Period from Year Ended Description December 31, 2016 December 31, 2015 Commodity contracts: Cash settlements $ 2,161 $ — $ — $ 17,385 Change in fair value (15,549 ) (1,778 ) — (12,146 ) Total gains (losses) on derivatives not designated or not qualifying as hedging instruments $ (13,388 ) $ (1,778 ) $ — $ 5,239
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, 2016 and 2015 (Predecessor) (in thousands): Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations for the Years Ended December 31, 2016 and 2015 (Predecessor) 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 2016 2016 2016 Commodity contracts $ (1,648 ) Operating revenue - oil/natural gas production $ 35,457 Derivative income (expense), net $ (810 ) Total $ (1,648 ) $ 35,457 $ (810 ) 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 (a) For the year ended December 31, 2016 , effective hedging contracts increased oil revenue by $23,747 and increased natural gas revenue by $11,710 . For the year ended December 31, 2015 , effective hedging contracts increased oil revenue by $135,617 and increased natural gas revenue by $14,338 .
Offsetting Assets	The following table presents the potential impact of the offset rights associated with our recognized assets and liabilities at December 31, 2017 (Successor) (in thousands): As Presented Without Netting Effects of Netting With Effects of Netting Current assets: Fair value of derivative contracts $ 879 $ (879 ) $ — Long-term assets: Fair value of derivative contracts — — — Current liabilities: Fair value of derivative contracts (8,969 ) 879 (8,090 ) Long-term liabilities: Fair value of derivative contracts (3,085 ) — (3,085 )
Offsetting Liabilities	The following table presents the potential impact of the offset rights associated with our recognized assets and liabilities at December 31, 2017 (Successor) (in thousands): As Presented Without Netting Effects of Netting With Effects of Netting Current assets: Fair value of derivative contracts $ 879 $ (879 ) $ — Long-term assets: Fair value of derivative contracts — — — Current liabilities: Fair value of derivative contracts (8,969 ) 879 (8,090 ) Long-term liabilities: Fair value of derivative contracts (3,085 ) — (3,085 )

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of Assets and Liabilities Measured at Fair Value Recurring Basis	The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2017 (Successor) (in thousands): Fair Value Measurements Successor as of December 31, 2017 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) $ 5,081 $ 5,081 $ — $ — Derivative contracts 879 — — 879 Total $ 5,960 $ 5,081 $ — $ 879 Fair Value Measurements Successor as of December 31, 2017 Liabilities Total Quoted Prices in Significant Other Significant Unobservable Inputs (Level 3) Derivative contracts $ 12,054 $ — $ 10,110 $ 1,944 Total $ 12,054 $ — $ 10,110 $ 1,944 We had no liabilities measured at fair value on a recurring basis at December 31, 2016. The following table presents our assets that are measured at fair value on a recurring basis at December 31, 2016 (Predecessor) (in thousands): Fair Value Measurements Predecessor as of December 31, 2016 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) $ 8,746 $ 8,746 $ — $ — Total $ 8,746 $ 8,746 $ — $ —
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	The table below presents a reconciliation for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the period from March 1, 2017 through December 31, 2017 (Successor) and the period from January 1, 2017 through February 28, 2017 (Predecessor) (in thousands): Hedging Contracts, net Successor Predecessor Period from Period from Beginning balance $ 3,087 $ — Total gains/(losses) (realized or unrealized): Included in earnings (5,201 ) (649 ) Included in other comprehensive income — — Purchases, sales, issuances and settlements 1,049 3,736 Transfers in and out of Level 3 — — Ending balance $ (1,065 ) $ 3,087 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, 2017 $ (4,699 )

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	The following table presents the change in our asset retirement obligations during the indicated periods (in thousands, inclusive of current portion): Successor Predecessor Period from Period from Year Ended December 31, 2016 2015 Beginning balance $ 290,067 $ 242,019 $ 225,866 $ 316,409 Liabilities incurred 2,280 — 2,338 15,933 Liabilities settled (81,197 ) (3,641 ) (19,630 ) (72,713 ) Divestment of properties — (8,672 ) — (248 ) Accretion expense 21,151 5,447 40,229 25,988 Revision of estimates (19,200 ) — (6,784 ) (59,503 ) Fair value fresh start adjustment — 54,914 — — Asset retirement obligations, end of period $ 213,101 $ 290,067 $ 242,019 $ 225,866

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Analysis of Deferred Taxes	An analysis of our deferred taxes follows (in thousands): Successor Predecessor As of December 31, As of December 31, 2017 2016 Tax effect of temporary differences: Net operating loss carryforwards $ 66,304 $ 201,557 Oil and gas properties 12,035 85,772 Asset retirement obligations 44,751 85,312 Stock compensation 278 3,294 Derivatives 3,110 — Accrued incentive compensation 2,269 954 Debt issuance costs 644 7,480 Other 1,600 441 Total deferred tax assets (liabilities) 130,991 384,810 Valuation allowance (130,991 ) (384,810 ) Net deferred tax assets (liabilities) $ — $ —
Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax Rate as a Percentage of Income Before Income Taxes	The following table provides a reconciliation of the statutory federal income tax rate to the Company’s effective income tax rate as a percentage of income before income taxes for the indicated periods: Successor Predecessor Period from Period from Year Ended December 31, 2016 2015 Income tax expense computed at the statutory federal income tax rate 35.0% 35.0% 35.0% 35.0% Tax Act rate change (32.8) — — — State taxes (0.7) 0.3 0.2 0.6 Change in valuation allowance 5.3 (37.8) (35.0) (12.8) IRC Sec. 162(m) limitation 0.4 — (0.3) (0.1) Tax deficits on stock compensation (0.6) 0.6 (0.7) (0.1) Reorganization fees 0.3 2.5 (0.3) — Other — — (0.2) (0.1) Effective income tax rate 6.9% 0.6% (1.3)% 22.5%
Summary of Income Tax Contingencies	A reconciliation of the total amounts of unrecognized tax benefits follows (in thousands): Successor Predecessor Period from Period from Total unrecognized tax benefits, beginning balance $ 491 $ 491 Increases (decreases) in unrecognized tax benefits as a result of: Tax positions taken during a prior period — — Tax positions taken during the current period — — Settlements with taxing authorities — — Lapse of applicable statute of limitations — — Total unrecognized tax benefits, ending balance $ 491 $ 491

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Our debt balances (net of related unamortized discounts and debt issuance costs) as of December 31, 2017 and 2016 were as follows (in thousands): Successor Predecessor December 31, December 31, 2017 2016 7 1⁄2 % Senior Second Lien Notes due 2022 $ 225,000 $ — 1 3 ⁄ 4 % Senior Convertible Notes due 2017 — 300,000 7 1⁄2 % Senior Notes due 2022 — 775,000 Predecessor revolving credit facility — 341,500 4.20% Building Loan 10,927 11,284 Total debt $ 235,927 $ 1,427,784 Less: current portion of long-term debt (425 ) (408 ) Less: liabilities subject to compromise — (1,075,000 ) Long-term debt $ 235,502 $ 352,376

ACCUMULATED OTHER COMPREHENSI43

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Schedule of Changes in Accumulated Other Comprehensive Income Loss	During the year ended December 31, 2016, we reclassified a $6.1 million loss related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the liquidation of our former foreign subsidiary, Stone Energy Canada, ULC. The following tables include the changes in accumulated other comprehensive income (loss) by component for the years ended December 31, 2016 and 2015 (Predecessor) (in thousands): Cash Flow Hedges Foreign Currency Items Total For the Year Ended December 31, 2016 (Predecessor) Beginning balance, net of tax $ 24,025 $ (6,073 ) $ 17,952 Other comprehensive income (loss) before reclassifications: Change in fair value of derivatives (1,648 ) — (1,648 ) Foreign currency translations — (8 ) (8 ) Income tax effect 581 — 581 Net of tax (1,067 ) (8 ) (1,075 ) Amounts reclassified from accumulated other comprehensive income: Operating revenue: oil/natural gas production 35,457 — 35,457 Other operational expenses — (6,081 ) (6,081 ) Income tax effect (12,499 ) — (12,499 ) Net of tax 22,958 (6,081 ) 16,877 Other comprehensive income (loss), net of tax (24,025 ) 6,073 (17,952 ) Ending balance, net of tax $ — $ — $ — Cash Flow Hedges Foreign Currency Items Total For the Year Ended December 31, 2015 (Predecessor) 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

SHARE-BASED COMPENSATION (Table

SHARE-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Stock Option Activity Under Plan	The following tables include Predecessor Company stock option activity during the years ended December 31, 2016 and 2015: Year Ended December 31, 2016 (Predecessor) Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Term Aggregate Intrinsic Value Options outstanding, beginning of period 14,447 $ 269.25 Granted — — Exercised — — Forfeited — — Expired (1,500 ) 477.45 Options outstanding, end of period 12,947 245.13 1.4 years $ — Options exercisable, end of period 12,947 245.13 1.4 years — Options unvested, end of period — — — — Year Ended December 31, 2015 (Predecessor) Number of Options Wgtd. Avg. Exercise Price Wgtd. Avg. Term Aggregate Intrinsic Value Options outstanding, beginning of period 20,497 $ 339.36 Granted — — Exercised — — Forfeited — — Expired (6,050 ) 506.76 Options outstanding, end of period 14,447 269.25 2.1 years $ — Options exercisable, end of period 14,447 269.25 2.1 years — Options unvested, end of period — — — —
Summary of Restricted Stock Activity Under Plan	The following table includes Successor Company restricted stock and stock award activity during the period from March 1, 2017 through December 31, 2017: Period from March 1, 2017 through December 31, 2017 Number of Restricted Shares Wgtd. Avg. Fair Value Per Share Restricted stock outstanding at February 28, 2017 (Predecessor) 18,024 $ 169.42 Restricted stock outstanding at March 1, 2017 (Successor) 3,176 $ 26.95 Issuances — — Lapse of restrictions (2,083 ) 21.78 Forfeitures — — Restricted stock outstanding at December 31, 2017 (Successor) 1,093 $ 26.95 The following table includes Predecessor Company restricted stock and stock award activity during the period from January 1, 2017 through February 28, 2017 and the years ended December 31, 2016 and 2015: Predecessor Period from Year Ended December 31, 2016 2015 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 81,090 $ 205.34 180,239 $ 208.17 129,848 $ 299.45 Issuances 10,404 6.67 31,313 8.93 141,872 167.21 Lapse of restrictions or granting of stock awards (73,276 ) 186.37 (117,406 ) 158.79 (63,745 ) 296.00 Forfeitures (194 ) 169.40 (13,056 ) 200.06 (27,736 ) 223.80 Restricted stock outstanding, end of period 18,024 $ 169.42 81,090 $ 205.34 180,239 $ 208.17

SUPPLEMENTAL INFORMATION ON O45

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Financial Data Relative to Oil and Gas Producing Activities	The following table sets forth certain information regarding the costs incurred in our acquisition, exploratory and development activities in the United States during the periods indicated (in thousands): Successor Predecessor Period from March 1, 2017 through December 31, 2017 Period from January 1, 2017 through February 28, 2017 Year Ended December 31, 2016 2015 Costs incurred during the period (capitalized): Acquisition costs, net of sales of unevaluated properties $ (8,371 ) $ (324 ) $ 3,923 $ (14,158 ) Exploratory costs 12,079 2,055 17,891 104,169 Development costs (1) 33,356 12,547 102,665 266,982 Salaries, general and administrative costs 7,495 2,976 21,753 27,984 Interest 3,927 2,524 26,634 41,339 Less: overhead reimbursements (1,004 ) — (521 ) (913 ) Total costs incurred during the period, net of divestitures $ 47,482 $ 19,778 $ 172,345 $ 425,403 (1) Includes net changes in capitalized asset retirement costs of ($17,446) , $0 , ($4,461) and ($43,901) , respectively. The following table discloses operational expenses incurred during the periods indicated relative to our oil and natural gas producing activities located in the United States (in thousands): Successor Predecessor Period from Period from Year Ended December 31, 2016 2015 Lease operating expenses $ 49,800 $ 8,820 $ 79,650 $ 100,139 Transportation, processing and gathering expenses 4,084 6,933 27,760 58,847 Production taxes 629 682 3,148 6,877 Accretion expense 21,151 5,447 40,229 25,988 Expensed costs – United States $ 75,664 $ 21,882 $ 150,787 $ 191,851 The following table sets forth certain information relative to the amortization of our investment in oil and gas properties and the impairment of our oil and gas properties in the United States for the periods indicated (in thousands, except per unit amounts): Successor Predecessor Period from March 1, 2017 through December 31, 2017 Period from January 1, 2017 through February 28, 2017 Year Ended December 31, 2016 2015 Provision for DD&A $ 97,027 $ 36,751 $ 215,737 $ 277,088 Write-down of oil and gas properties $ 256,435 $ — $ 357,079 $ 1,314,817 DD&A per Boe $ 16.61 $ 17.05 $ 16.10 $ 19.15 The following table discloses the total amount of capitalized costs and accumulated DD&A relative to our proved and unevaluated oil and natural gas properties located in the United States (in thousands): Successor Predecessor December 31, 2017 December 31, 2016 Proved properties $ 713,157 $ 9,572,082 Unevaluated properties 102,187 373,720 Total proved and unevaluated properties 815,344 9,945,802 Less accumulated depreciation, depletion and amortization (353,462 ) (9,134,288 ) Balance, end of year $ 461,882 $ 811,514
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 periods indicated (in thousands): Successor Predecessor Period from March 1, 2017 through December 31, 2017 Period from January 1, 2017 through February 28, 2017 Year Ended December 31, 2016 2015 Net costs incurred (evaluated) during period: Acquisition costs $ (9,155 ) $ 959 $ (71,378 ) $ (115,767 ) Exploration costs 10,405 (6,063 ) (21,579 ) (16,315 ) Capitalized interest 3,927 2,524 26,634 41,339 $ 5,177 $ (2,580 ) $ (66,323 ) $ (90,743 ) Under fresh start accounting, our oil and gas properties were recorded at fair value as of February 28, 2017. The following table discloses financial data associated with unevaluated costs (United States) for the Successor Company at December 31, 2017 (in thousands): Successor Net Costs Incurred During the Period from March 1, 2017 through December 31, 2017 Successor March 1, 2017 December 31, 2017 Acquisition costs $ 58,359 $ (9,155 ) $ 49,204 Exploration costs 38,651 10,405 49,056 Capitalized interest — 3,927 3,927 Total unevaluated costs $ 97,010 $ 5,177 $ 102,187
Financial Data Associated with Unevaluated Costs	The following table discloses certain financial data relative to our oil and gas activities located in Canada (in thousands): Predecessor Year Ended December 31, 2016 2015 Oil and gas properties – Canada: Balance, beginning of year $ 42,484 $ 36,579 Costs incurred during the year (capitalized): Acquisition costs (498 ) (2,862 ) Exploratory costs 2,168 8,767 Total costs incurred during the year 1,670 5,905 Balance, end of year (fully evaluated at December 31, 2016 and 2015) $ 44,154 $ 42,484 Accumulated DD&A: Balance, beginning of year $ (42,484 ) $ — Foreign currency translation adjustment (1,318 ) 5,146 Write-down of oil and gas properties (352 ) (47,630 ) Balance, end of year $ (44,154 ) $ (42,484 ) Net capitalized costs – Canada $ — $ —
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 are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a historical twelve-month average pricing assumption. Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Oil, Natural Gas and NGLs (MBoe) Estimated proved developed and undeveloped reserves: As of December 31, 2014 (Predecessor) 42,397 27,817 493,843 152,520 Revisions of previous estimates (6,818 ) (20,777 ) (362,102 ) (87,945 ) Extensions, discoveries and other additions 862 11 1,499 1,123 Purchase of producing properties 685 1,808 26,136 6,849 Sale of reserves (859 ) — (1,061 ) (1,036 ) Production (5,991 ) (2,401 ) (36,457 ) (14,468 ) As of December 31, 2015 (Predecessor) 30,276 6,458 121,858 57,043 Revisions of previous estimates (751 ) 6,352 24,858 9,744 Extensions, discoveries and other additions 63 2 45 73 Production (6,308 ) (2,183 ) (29,441 ) (13,398 ) As of December 31, 2016 (Predecessor) 23,280 10,629 117,320 53,462 Revisions of previous estimates 730 (2 ) 1,242 935 Sale of reserves (826 ) (7,417 ) (52,992 ) (17,075 ) Production (908 ) (408 ) (5,037 ) (2,156 ) As of February 28, 2017 (Predecessor) 22,276 2,802 60,533 35,166 Revisions of previous estimates 3,769 (94 ) (2,801 ) 3,208 Production (4,169 ) (403 ) (7,616 ) (5,841 ) As of December 31, 2017 (Successor) 21,876 2,305 50,116 32,533 Estimated proved developed reserves: As of December 31, 2015 (Predecessor) 21,734 4,784 90,262 41,562 As of December 31, 2016 (Predecessor) 18,269 9,255 90,741 42,647 As of February 28, 2017 (Predecessor) 18,344 1,515 35,865 25,836 As of December 31, 2017 (Successor) 20,275 1,689 37,946 28,288 Estimated proved undeveloped reserves: As of December 31, 2015 (Predecessor) 8,542 1,674 31,596 15,481 As of December 31, 2016 (Predecessor) 5,011 1,374 26,579 10,815 As of February 28, 2017 (Predecessor) 3,932 1,287 24,668 9,330 As of December 31, 2017 (Successor) 1,601 616 12,170 4,245
Summary of Standardized Measure of Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows and changes therein are as follows (in thousands, except average prices): Standardized Measure Successor Predecessor December 31, December 31, 2017 2016 2015 Future cash inflows $ 1,264,809 $ 1,236,097 $ 1,921,329 Future production costs (497,538 ) (480,815 ) (651,396 ) Future development costs (431,752 ) (638,988 ) (679,355 ) Future income taxes — — — Future net cash flows 335,519 116,294 590,578 10% annual discount 57,591 109,628 13,259 Standardized measure of discounted future net cash flows $ 393,110 $ 225,922 $ 603,837 Average prices related to proved reserves: Oil (per Bbl) $ 50.05 $ 40.15 $ 51.16 NGLs (per Bbl) 22.90 9.46 16.40 Natural gas (per Mcf) 2.34 1.71 2.19 Changes in Standardized Measure Successor Predecessor Period from March 1, 2017 through December 31, 2017 Period From January 1, 2017 through February 28, 2017 Year Ended December 31, 2016 2015 Standardized measure at beginning of period $ 303,086 $ 225,922 $ 603,837 $ 1,418,792 Sales and transfers of oil, natural gas and NGLs produced, net of production costs (164,612 ) (46,137 ) (223,948 ) (340,477 ) Changes in price, net of future production costs 66,192 17,455 (448,861 ) (237,747 ) Extensions and discoveries, net of future production and development costs — — 5,243 1,573 Changes in estimated future development costs, net of development costs incurred during the period 88,111 20,756 54,406 731,115 Revisions of quantity estimates 96,454 36,557 139,759 (1,458,652 ) Accretion of discount 30,309 22,592 60,384 174,456 Net change in income taxes — — — 325,768 Purchases of reserves in-place — — — 3,493 Sales of reserves in-place — 14,584 — — Changes in production rates due to timing and other (26,430 ) 11,357 35,102 (14,484 ) Net change in standardized measure 90,024 77,164 (377,915 ) (814,955 ) Standardized measure at end of period $ 393,110 $ 303,086 $ 225,922 $ 603,837

SUMMARIZED QUARTERLY FINANCIA46

SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Results of Operations by Quarter	The Company’s results of operations by quarter are as follows (in thousands, except per share amounts): Predecessor Successor Period from Period from 2017 Quarter Ended June 30 Sept. 30 Dec. 31 Operating revenue $ 68,922 $ 25,809 $ 76,722 $ 79,525 $ 76,327 Income (loss) from operations $ 209,119 $ (258,594 ) $ (4,519 ) $ 2,653 $ 5,302 Net income (loss) $ 630,317 $ (259,613 ) $ (6,461 ) $ 1,297 $ 17,138 Basic income (loss) per share $ 110.99 $ (12.98 ) $ (0.32 ) $ 0.06 $ 0.86 Diluted income (loss) per share $ 110.99 $ (12.98 ) $ (0.32 ) $ 0.06 $ 0.86 Write-down of oil and gas properties $ — $ 256,435 $ — $ — $ — Gain (loss) on Appalachia Properties divestiture $ 213,453 $ — $ 27 $ (132 ) $ — Reorganization items (1) $ (437,744 ) $ — $ — $ — $ — Other expense $ 13,336 $ — $ 814 $ 47 $ 369 (1) See Note 3 – Fresh Start Accounting for additional details. Predecessor 2016 Quarter Ended March 31 June 30 Sept. 30 Dec. 31 Operating revenue $ 80,677 $ 89,319 $ 94,427 $ 113,107 Loss from operations $ (172,150 ) $ (174,656 ) $ (72,128 ) $ (90,234 ) Net loss $ (188,784 ) $ (195,761 ) $ (89,635 ) $ (116,406 ) Basic loss per share $ (33.89 ) $ (35.05 ) $ (16.01 ) $ (20.76 ) Diluted loss per share $ (33.89 ) $ (35.05 ) $ (16.01 ) $ (20.76 ) Write-down of oil and gas properties $ 129,204 $ 118,649 $ 36,484 $ 73,094 Restructuring fees $ 953 $ 9,436 $ 5,784 $ 13,424 Other operational expenses (1) $ 12,527 $ 27,680 $ 9,059 $ 6,187 Reorganization items $ — $ — $ — $ 10,947 (1) See Note 19 – Other Operational Expenses for additional details.

ORGANIZATION AND SUMMARY OF S47

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($) shares in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016	Nov. 21, 2017	Sep. 30, 2017	Mar. 01, 2017	Feb. 27, 2017
Schedule Of Significant Accounting Policies [Line Items]
Restricted cash		$ 18,742,000
Building
Schedule Of Significant Accounting Policies [Line Items]
Estimated useful life of building		39 years
7.5% Second Lien Notes | Second Lien Notes
Schedule Of Significant Accounting Policies [Line Items]
Interest rate						7.50%
Predecessor
Schedule Of Significant Accounting Policies [Line Items]
Restricted cash			$ 0
Predecessor | Foreign Currency Items | Other operational expenses
Schedule Of Significant Accounting Policies [Line Items]
Reclassification from accumulated other comprehensive income			$ 6,081,000
Talos Energy, Inc. | Forecast
Schedule Of Significant Accounting Policies [Line Items]
Percentage of outstanding stock	37.00%
Talos Energy, Inc. | 9.75% Senior Notes Due 2022 | Senior Notes
Schedule Of Significant Accounting Policies [Line Items]
Aggregate principal amount of senior notes				$ 102,000,000
Interest rate				9.75%
Talos Energy, Inc. | 11% Second Lien Notes | Second Lien Notes
Schedule Of Significant Accounting Policies [Line Items]
Interest rate		11.00%
Talos Energy, Inc. | Talos Production | Forecast
Schedule Of Significant Accounting Policies [Line Items]
Percentage of outstanding stock	100.00%
Talos Energy, Inc. | Stone Energy Corp. | Forecast
Schedule Of Significant Accounting Policies [Line Items]
Number of New Talos shares issued (in shares)	34.1
Talos Energy | Talos Energy, Inc. | Forecast
Schedule Of Significant Accounting Policies [Line Items]
Percentage of outstanding stock	63.00%
Franklin Advisors, Inc. and MacKay Shields LLC | Stone Energy Corp.
Schedule Of Significant Accounting Policies [Line Items]
Investment managers voting percentage in Stone Energy					53.00%
Disposal Group, Disposed of by Sale | Appalachia Properties
Schedule Of Significant Accounting Policies [Line Items]
Net consideration received for sale of Appalachia Properties							$ 522,500,000
Disposal Group, Disposed of by Sale | Appalachia Properties | Predecessor
Schedule Of Significant Accounting Policies [Line Items]
Net consideration received for sale of Appalachia Properties							$ 522,500,000

REORGANIZATION - Additional Inf

REORGANIZATION - Additional Information (Details) $ / shares in Units, shares in Thousands, a in Thousands

Mar. 01, 2017USD ($)$ / sharesshares

Feb. 28, 2017USD ($)shares

Feb. 27, 2017USD ($)shares

Feb. 08, 2017USD ($)

Jan. 11, 2017bidder

Dec. 14, 2016USD ($)

Dec. 09, 2016USD ($)a

Feb. 28, 2017USD ($)

Dec. 31, 2017USD ($)$ / shares

Dec. 31, 2017$ / shares

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Oct. 20, 2016

Restructuring Cost and Reserve [Line Items]

Proceeds from sale of oil and gas properties, net of expenses

$ 512,472,000

$ 20,633,000

New shares issued in reorganization (in shares) | shares

20,000

20,000

Predecessor

Restructuring Cost and Reserve [Line Items]

Proceeds from sale of oil and gas properties, net of expenses

$ 505,383,000

$ 0

$ 22,839,000

Convertible Debt | Notes Due Two Thousand Seventeen

Restructuring Cost and Reserve [Line Items]

Interest rate

1.75%

1.75%

Convertible Debt | Notes Due Two Thousand Seventeen | Predecessor

Restructuring Cost and Reserve [Line Items]

Interest rate

1.75%

1.75%

Senior Notes | Notes Due Two Thousand Twenty Two

Restructuring Cost and Reserve [Line Items]

Interest rate

7.50%

7.50%

7.50%

Senior Notes | Notes Due Two Thousand Twenty Two | Predecessor

Restructuring Cost and Reserve [Line Items]

Interest rate

7.50%

Senior Notes | Second Lien Notes

Restructuring Cost and Reserve [Line Items]

Interest rate

7.50%

7.50%

7.50%

Aggregate principal amount of senior subordinated notes

$ 225,000,000

Predecessor Company's Common Stockholders

Restructuring Cost and Reserve [Line Items]

Warrants issued in reorganization (in shares) | shares

3,500

Exercise price of warrants or rights (in usd per share) | $ / shares

$ 42.04

$ 42.04

Exercise period for warrants

4 years

RSA | Predecessor

Restructuring Cost and Reserve [Line Items]

Acreage sold in agreement | a

86

Number of additional bidders allowed to participate in competitive bidding | bidder

2

RSA | TH Exploration III, LLC, an affiliate of Tug Hill, Inc. | Predecessor | Disposal Group, Disposed of by Sale

Restructuring Cost and Reserve [Line Items]

Proceeds from sale of oil and gas properties, net of expenses

$ 360,000,000

Loss on contract termination

$ 11,500,000

RSA | EQT Production Company | Predecessor | Disposal Group, Disposed of by Sale

Restructuring Cost and Reserve [Line Items]

Proceeds from sale of oil and gas properties, net of expenses

$ 527,000,000

Upward adjustment of purchase price

$ 16,000,000

RSA | Noteholders | Predecessor

Restructuring Cost and Reserve [Line Items]

Pro rata share of net cash proceeds

$ 100,000,000

Percentage of common stock issued in reorganization

95.00%

RSA | Noteholders | Senior Notes | Second Lien Notes | Predecessor

Restructuring Cost and Reserve [Line Items]

Aggregate principal amount of senior subordinated notes

$ 225,000,000

RSA | Predecessor Company's Common Stockholders

Restructuring Cost and Reserve [Line Items]

Percentage of common stock issued in reorganization

5.00%

Appalachia Regions of Pennsylvania and West Virginia | RSA | Predecessor

Restructuring Cost and Reserve [Line Items]

Minimum proceeds from sale of property

$ 350,000,000

Common Stock | RSA

Restructuring Cost and Reserve [Line Items]

New shares issued in reorganization (in shares) | shares

20,000

Common Stock | RSA | Noteholders | Predecessor

Restructuring Cost and Reserve [Line Items]

New shares issued in reorganization (in shares) | shares

19,000

Common Stock | RSA | Predecessor Company's Common Stockholders

Restructuring Cost and Reserve [Line Items]

New shares issued in reorganization (in shares) | shares

1,000

Warrants issued in reorganization (in shares) | shares

3,500

Exercise price of warrants or rights (in usd per share) | $ / shares

$ 42.04

Exercise period for warrants

4 years

Appalachia Properties | Disposal Group, Disposed of by Sale

Restructuring Cost and Reserve [Line Items]

Proceeds from sale of oil and gas properties, net of expenses

$ 512,500,000

Net consideration received for sale of Appalachia Properties

522,500,000

Appalachia Properties | Predecessor | Disposal Group, Disposed of by Sale

Restructuring Cost and Reserve [Line Items]

Net consideration received for sale of Appalachia Properties

$ 522,500,000

FRESH START ACCOUNTING - Additi

FRESH START ACCOUNTING - Additional Information (Details) - USD ($) $ / shares in Units, shares in Thousands	Mar. 01, 2017	Feb. 28, 2017	Feb. 27, 2017	Oct. 31, 2016	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fresh-Start Adjustment [Line Items]
Accumulated deficit		$ 554,737,000			$ 554,737,000	$ 308,168,000	$ 308,168,000
Enterprise value		$ 419,720,000			419,720,000
Annual escalation adjustment rate		2.00%
Expected period for development to begin		5 years
Fair value of asset retirement obligations		$ 290,067,000			290,067,000
Credit-adjusted risk free rate		12.00%
Proceeds from sale of oil and gas properties, net of expenses		$ 512,472,000				20,633,000
Cash transferred to restricted account		75,547,000
Restricted cash for certain cure amounts		500,000
Emergence and success fees		15,200,000
Professional fees		2,700,000
Payments to seismic providers		2,400,000
Repayment of outstanding borrowings under Pre-Emergence Credit Agreement		$ 341,500,000				$ 0
New shares issued in reorganization (in shares)	20,000	20,000
Predecessor Company's Common Stockholders
Fresh-Start Adjustment [Line Items]
Warrants issued in reorganization (in shares)	3,500
Exercise price of warrants or rights (in usd per share)						$ 42.04	$ 42.04
Exercise period for warrants							4 years
Amended Credit Agreement
Fresh-Start Adjustment [Line Items]
Cash transferred to restricted account		$ 75,000,000
Predecessor
Fresh-Start Adjustment [Line Items]
Accumulated deficit		(3,610,000)			(3,610,000)			$ (637,282,000)	$ (39,789,000)	$ 1,101,603,000
Proved reserves		380,800,000			380,800,000
Probable and possible reserves		16,800,000			16,800,000
Unevaluated properties reserves		80,200,000			80,200,000
Proceeds from sale of oil and gas properties, net of expenses					505,383,000			0	22,839,000
Emergence and success fees					10,600,000
Professional fees					8,900,000
Repayment of outstanding borrowings under Pre-Emergence Credit Agreement					341,500,000			135,500,000	5,000,000
Appalachia Properties | Disposal Group, Disposed of by Sale
Fresh-Start Adjustment [Line Items]
Net consideration received for sale of Appalachia Properties			$ 522,500,000
Proceeds from sale of oil and gas properties, net of expenses			512,500,000
Indemnity escrow release			10,000,000
Appalachia Properties | Disposal Group, Disposed of by Sale | Predecessor
Fresh-Start Adjustment [Line Items]
Net consideration received for sale of Appalachia Properties			$ 522,500,000
Revaluation of Assets
Fresh-Start Adjustment [Line Items]
Write off of unamortized debt issuance costs		2,600,000
Revaluation of Assets | Tug Hill, Inc
Fresh-Start Adjustment [Line Items]
Net reimbursement in connection with the sale of asset		700,000			700,000
Loss on contract termination				$ 1,800,000
Revaluation of Liabilities | Senior Notes | Notes Due Two Thousand Twenty Two
Fresh-Start Adjustment [Line Items]
Aggregate principal amount of senior subordinated notes		225,000,000			225,000,000
Revaluation of Liabilities | Predecessor
Fresh-Start Adjustment [Line Items]
Repayment of outstanding borrowings under Pre-Emergence Credit Agreement					341,500,000
Revaluation of Liabilities | Leasing Arrangement
Fresh-Start Adjustment [Line Items]
Loss on contract termination		400,000
Revaluation of Liabilities | Appalachia Properties | Disposal Group, Disposed of by Sale
Fresh-Start Adjustment [Line Items]
Settlement of a property tax accrual		2,600,000			$ 2,600,000
Revaluation of Liabilities | Deferred Bonus | 2016 Incentive Plan
Fresh-Start Adjustment [Line Items]
Deferred compensation arrangement compensation expense		$ 2,000,000
Exchange of Stock for Stock
Fresh-Start Adjustment [Line Items]
Estimated fair value of the warrants (in usd per share)		$ 4.43			$ 4.43
Exchange of Stock for Stock | Predecessor Company's Common Stockholders
Fresh-Start Adjustment [Line Items]
Warrants issued in reorganization (in shares)		3,500
Exercise price of warrants or rights (in usd per share)		$ 42.04			$ 42.04
Exercise period for warrants		4 years
Exchange of Stock for Stock | Senior Notes | Notes Due Two Thousand Twenty Two | Predecessor Company's Noteholders
Fresh-Start Adjustment [Line Items]
New shares issued in reorganization (in shares)		1,000
Exchange of Stock for Stock | Convertible Debt | Notes Due Two Thousand Seventeen | Predecessor Company's Noteholders
Fresh-Start Adjustment [Line Items]
New shares issued in reorganization (in shares)		19,000
Income Approach Valuation Technique
Fresh-Start Adjustment [Line Items]
Discounted weighted average cost of capital rate		12.50%
Minimum
Fresh-Start Adjustment [Line Items]
Enterprise value		$ 300,000,000			$ 300,000,000
Maximum
Fresh-Start Adjustment [Line Items]
Enterprise value		450,000,000			450,000,000
Accumulated Deficit
Fresh-Start Adjustment [Line Items]
Accumulated deficit		0			0	$ (247,639,000)	$ (247,639,000)
Accumulated Deficit | Predecessor
Fresh-Start Adjustment [Line Items]
Accumulated deficit		$ (1,665,892,000)			$ (1,665,892,000)			$ (2,296,209,000)	$ (1,705,623,000)	$ (614,708,000)

FRESH START ACCOUNTING - Reconc

FRESH START ACCOUNTING - Reconciliation of Enterprise Value to Estimated Fair Value of Successor Common Stock (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Mar. 01, 2017	Feb. 28, 2017	Dec. 31, 2017
Reorganizations [Abstract]
Enterprise value		$ 419,720
Plus: Cash and other assets		371,278
Less: Fair value of debt		(236,261)
Less: Fair value of warrants		(15,648)	$ (15,600)
Fair value of Successor common stock		$ 539,089
Shares issued (in shares)	20,000	20,000
Per share value (in usd per share)		$ 26.95

FRESH START ACCOUNTING - Reco51

FRESH START ACCOUNTING - Reconciliation of Enterprise Value to Estimated Reorganization Value (Details) $ in Thousands	Feb. 28, 2017USD ($)
Reorganizations [Abstract]
Enterprise value	$ 419,720
Plus: Cash and other assets	371,278
Plus: Asset retirement obligations (current and long-term)	290,067
Plus: Working capital and other liabilities	58,055
Reorganization value of Successor assets	$ 1,139,120

FRESH START ACCOUNTING - Schedu

FRESH START ACCOUNTING - Schedule of Fresh-Start Adjustments (Details) $ in Thousands	Feb. 28, 2017USD ($)
Current assets:
Cash and cash equivalents	$ 162,966
Restricted cash	75,547
Accounts receivable	52,109
Fair value of derivative contracts	1,267
Current income tax receivable	22,516
Other current assets	11,784
Total current assets	326,189
Proved	670,852
Less: accumulated DD&A	0
Net proved oil and gas properties	670,852
Unevaluated	97,010
Other property and equipment, net	21,062
Fair value of derivative contracts	1,819
Other assets, net	22,188
Total assets	1,139,120
Current liabilities:
Accounts payable to vendors	20,512
Undistributed oil and gas proceeds	1,778
Accrued interest	266
Asset retirement obligations	92,597
Fair value of derivative contracts	476
Current portion of long-term debt	411
Other current liabilities	16,837
Other current liabilities	132,877
Long-term debt	235,850
Asset retirement obligations	197,470
Fair value of derivative contracts	653
Other long-term liabilities	17,533
Total liabilities not subject to compromise	584,383
Liabilities subject to compromise	0
Total liabilities	584,383
Stockholders’ equity:
Common stock (Successor)	200
Additional paid-in capital (Successor)	554,537
Accumulated deficit	0
Total stockholders’ equity	554,737
Total liabilities and stockholders’ equity	1,139,120
Reorganization Adjustments
Current assets:
Cash and cash equivalents	(35,605)
Restricted cash	75,547
Accounts receivable	9,301
Fair value of derivative contracts	0
Current income tax receivable	0
Other current assets	875
Total current assets	50,118
Proved	(188,933)
Less: accumulated DD&A	0
Net proved oil and gas properties	(188,933)
Unevaluated	(127,838)
Other property and equipment, net	(101)
Fair value of derivative contracts	0
Other assets, net	(4,328)
Total assets	(271,082)
Current liabilities:
Accounts payable to vendors	0
Undistributed oil and gas proceeds	(4,139)
Accrued interest	0
Asset retirement obligations	0
Fair value of derivative contracts	0
Current portion of long-term debt	0
Other current liabilities	(195)
Total current liabilities	(4,334)
Long-term debt	(116,500)
Asset retirement obligations	(8,672)
Fair value of derivative contracts	0
Other long-term liabilities	0
Total liabilities not subject to compromise	(129,506)
Liabilities subject to compromise	(1,110,182)
Total liabilities	(1,239,688)
Stockholders’ equity:
Common stock	200
Additional paid-in capital	554,537
Accumulated deficit	2,073,875
Total stockholders’ equity	968,606
Total liabilities and stockholders’ equity	(271,082)
Fresh Start Adjustments
Current assets:
Cash and cash equivalents	0
Restricted cash	0
Accounts receivable	0
Fair value of derivative contracts	0
Current income tax receivable	0
Other current assets	(124)
Total current assets	(124)
Proved	(8,774,122)
Less: accumulated DD&A	9,215,679
Net proved oil and gas properties	441,557
Unevaluated	(146,292)
Other property and equipment, net	(4,423)
Fair value of derivative contracts	0
Other assets, net	0
Total assets	290,718
Current liabilities:
Accounts payable to vendors	0
Undistributed oil and gas proceeds	0
Accrued interest	0
Asset retirement obligations	0
Fair value of derivative contracts	0
Current portion of long-term debt	0
Other current liabilities	0
Total current liabilities	0
Long-term debt	0
Asset retirement obligations	54,914
Fair value of derivative contracts	0
Other long-term liabilities	0
Total liabilities not subject to compromise	54,914
Liabilities subject to compromise	0
Total liabilities	54,914
Stockholders’ equity:
Common stock	0
Additional paid-in capital	0
Accumulated deficit	235,804
Total stockholders’ equity	235,804
Total liabilities and stockholders’ equity	290,718
Predecessor
Current assets:
Cash and cash equivalents	198,571
Restricted cash	0
Accounts receivable	42,808
Fair value of derivative contracts	1,267
Current income tax receivable	22,516
Other current assets	11,033
Total current assets	276,195
Oil and gas properties, full cost method of accounting:
Proved	9,633,907
Less: accumulated DD&A	(9,215,679)
Net proved oil and gas properties	418,228
Unevaluated	371,140
Other property and equipment, net	25,586
Fair value of derivative contracts	1,819
Other assets, net	26,516
Other assets, net	1,119,484
Current liabilities:
Accounts payable to vendors	20,512
Undistributed oil and gas proceeds	5,917
Accrued interest	266
Asset retirement obligations	92,597
Fair value of derivative contracts	476
Current portion of long-term debt	411
Other current liabilities	17,032
Total current liabilities	137,211
Long-term debt	352,350
Asset retirement obligations	151,228
Fair value of derivative contracts	653
Other long-term liabilities	17,533
Total liabilities not subject to compromise	658,975
Liabilities subject to compromise	1,110,182
Total liabilities	1,769,157
Stockholders’ equity:
Common stock (Predecessor)	56
Treasury stock (Predecessor)	(860)
Additional paid-in capital (Predecessor)	1,660,810
Accumulated deficit	(2,309,679)
Total stockholders’ equity	(649,673)
Total liabilities and stockholders’ equity	1,119,484
Predecessor | Reorganization Adjustments
Stockholders’ equity:
Common stock	(56)
Treasury stock (Predecessor)	860
Additional paid-in capital	(1,660,810)
Predecessor | Fresh Start Adjustments
Stockholders’ equity:
Common stock	0
Treasury stock (Predecessor)	0
Additional paid-in capital	$ 0

FRESH START ACCOUNTING - Reorga

FRESH START ACCOUNTING - Reorganization Adjustments (Details) - USD ($) $ in Thousands	Feb. 28, 2017	Dec. 31, 2017
Reorganizations [Abstract]
Net consideration received for sale of Appalachia Properties	$ 512,472	$ 20,633
Cash transferred to restricted account	75,547
Break-up fee to Tug Hill	10,800
Repayment of outstanding borrowings under Pre-Emergence Credit Agreement	341,500	0
Repayment of 2017 Convertible Notes and 2022 Notes	100,000
Other fees and expenses	20,230
Total uses	548,077
Net change in cash and cash equivalents	$ (35,605)	$ 100,529

FRESH START ACCOUNTING - Liabil

FRESH START ACCOUNTING - Liabilities Subject to Compromise (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Feb. 28, 2017	Oct. 20, 2016
Fresh-Start Adjustment [Line Items]
Liabilities subject to compromise	$ 0
Revaluation of Liabilities
Fresh-Start Adjustment [Line Items]
Accrued interest		$ 35,182
Liabilities subject to compromise		1,110,182
Cash payment to senior noteholders		(100,000)
Issuance of 2022 Second Lien Notes to former holders of the senior notes		(225,000)
Gain on settlement of liabilities subject to compromise		230,445
Common Stock | Revaluation of Liabilities
Fresh-Start Adjustment [Line Items]
Equity fair value adjustments		(539,089)
Warrant
Fresh-Start Adjustment [Line Items]
Equity fair value adjustments		$ (15,648)
Convertible Debt | Notes Due Two Thousand Seventeen
Fresh-Start Adjustment [Line Items]
Interest rate		1.75%
Convertible Debt | Notes Due Two Thousand Seventeen | Revaluation of Liabilities
Fresh-Start Adjustment [Line Items]
Liabilities subject to compromise		$ 300,000
Senior Notes | Notes Due Two Thousand Twenty Two
Fresh-Start Adjustment [Line Items]
Interest rate		7.50%	7.50%
Senior Notes | Notes Due Two Thousand Twenty Two | Revaluation of Liabilities
Fresh-Start Adjustment [Line Items]
Liabilities subject to compromise		$ 775,000

FRESH START ACCOUNTING - Cumula

FRESH START ACCOUNTING - Cumulative Impact of the Reorganization Adjustments (Details) - Exchange of Stock for Stock $ in Thousands	Feb. 28, 2017USD ($)
Fresh-Start Adjustment [Line Items]
Gain on settlement of liabilities subject to compromise	$ 230,445
Professional and other fees paid at emergence	(10,648)
Write-off of unamortized deferred financing costs	(2,577)
Other reorganization adjustments	(1,915)
Net impact to reorganization items	215,305
Gain on sale of Appalachia Properties	213,453
Cancellation of Predecessor Company equity	1,662,282
Other adjustments to accumulated deficit	(17,165)
Net impact to accumulated deficit	$ 2,073,875

FRESH START ACCOUNTING - Reor56

FRESH START ACCOUNTING - Reorganization Items (Details) - USD ($) $ in Thousands

1 Months Ended

2 Months Ended

3 Months Ended

10 Months Ended

12 Months Ended

Mar. 31, 2017

Feb. 28, 2017

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Fresh-Start Adjustment [Line Items]

Write-off of deferred financing costs

$ (8,332)

Gain on reorganization items, net

$ 0

$ 0

$ 0

$ 0

$ 0

Predecessor

Fresh-Start Adjustment [Line Items]

Gain on settlement of liabilities subject to compromise

$ 230,445

Fresh start valuation adjustments

235,804

Reorganization professional fees and other expenses

(20,403)

Write-off of deferred financing costs

(2,577)

Other reorganization items

(5,525)

Gain on reorganization items, net

$ 437,744

$ (10,947)

$ 0

$ 0

$ 0

$ (10,947)

$ 0

DIVESTITURE - Additional Inform

DIVESTITURE - Additional Information (Details) $ in Millions	Feb. 27, 2017USD ($)	Dec. 31, 2016MMBoe	Feb. 28, 2017USD ($)
Appalachia Properties | Disposal Group, Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net consideration received for sale of Appalachia Properties	$ 522.5
Predecessor
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of proved oil and natural gas reserves		34.00%
Predecessor | Appalachia Properties | Disposal Group, Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net consideration received for sale of Appalachia Properties	522.5
Gross proceeds from properties sold	527
Purchase price adjustment	$ 4.5
Net gain on sale			$ 213.5
Predecessor | Oil and Gas Properties | Appalachia Properties | Disposal Group, Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Estimated proved oil and natural gas reserves | MMBoe		18

DIVESTITURE - Schedule of Net G

DIVESTITURE - Schedule of Net Gain Recognized in Sale (Details) - USD ($) $ in Thousands	Feb. 27, 2017	Mar. 31, 2017	Feb. 28, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Transfer of asset retirement obligations							$ 81,197
Carrying value of properties sold				$ (17,275)			(17,275)
Gain (loss) on Appalachia Properties divestiture		$ 0		$ 0	$ (132)	$ 27	$ (105)
Appalachia Properties | Disposal Group, Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net consideration received for sale of Appalachia Properties	$ 522,500
Predecessor
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Transfer of asset retirement obligations			$ 3,641					$ 19,630	$ 72,713
Carrying value of properties sold								(26,213)
Gain (loss) on Appalachia Properties divestiture			$ 213,453					$ 0	$ 0
Predecessor | Appalachia Properties | Disposal Group, Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net consideration received for sale of Appalachia Properties	522,500
Release of funds held in suspense	4,139
Transfer of asset retirement obligations	8,672
Other adjustments, net	2,597
Transaction costs	(7,087)
Gain (loss) on Appalachia Properties divestiture	213,453
Predecessor | Appalachia Properties | Disposal Group, Disposed of by Sale | Oil and Gas Properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Carrying value of properties sold	$ (317,340)

STOCKHOLDERS' EQUITY - Addition

STOCKHOLDERS' EQUITY - Additional Information (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Mar. 01, 2017	Feb. 28, 2017	Dec. 31, 2017
Class of Stock [Line Items]
New shares issued in reorganization (in shares)	20,000	20,000
Common stock, par value (in usd per share)	$ 0.01		$ 0.01
Warrants allocated of the enterprise value		$ 15,648	$ 15,600
Predecessor Company's Common Stockholders
Class of Stock [Line Items]
Warrants issued in reorganization (in shares)	3,500
Exercise price of warrants or rights (in usd per share)			$ 42.04
Exercise period for warrants			4 years

EARNINGS PER SHARE - Calculatio

EARNINGS PER SHARE - Calculation of Basic and Diluted Weighted Average Shares Outstanding and Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended							10 Months Ended	12 Months Ended
	Mar. 31, 2017	Feb. 28, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Basic:
Net income (loss)	$ (259,613)		$ 17,138	$ 1,297	$ (6,461)					$ (247,639)
Net income attributable to participating securities										0
Net income (loss) attributable to common stock - basic										(247,639)
Diluted:
Net income (loss)	$ (259,613)		$ 17,138	$ 1,297	$ (6,461)					(247,639)
Net income attributable to participating securities										0
Net income (loss) attributable to common stock - diluted										$ (247,639)
Weighted average shares (denominator):
Weighted average shares - basic (in shares)										19,997
Dilutive effect of convertible notes (in shares)										0
Weighted average shares - diluted (in shares)										19,997
Basic income (loss) per share (in usd per share)	$ (12.98)		$ 0.86	$ 0.06	$ (0.32)					$ (12.38)
Diluted income (loss) per share (in usd per share)	$ (12.98)		$ 0.86	$ 0.06	$ (0.32)					$ (12.38)
Employee Stock Option
Weighted average shares (denominator):
Dilutive effect of stock options (in shares)										0
Warrant
Weighted average shares (denominator):
Dilutive effect of warrants (in shares)										0
Predecessor
Basic:
Net income (loss)		$ 630,317				$ (116,406)	$ (89,635)	$ (195,761)	$ (188,784)		$ (590,586)	$ (1,090,915)
Net income attributable to participating securities		(4,995)									0	0
Net income (loss) attributable to common stock - basic		625,322									(590,586)	(1,090,915)
Diluted:
Net income (loss)		630,317				$ (116,406)	$ (89,635)	$ (195,761)	$ (188,784)		(590,586)	(1,090,915)
Net income attributable to participating securities		(4,995)									0	0
Net income (loss) attributable to common stock - diluted		$ 625,322									$ (590,586)	$ (1,090,915)
Weighted average shares (denominator):
Weighted average shares - basic (in shares)		5,634									5,591	5,525
Dilutive effect of convertible notes (in shares)		0									0	0
Weighted average shares - diluted (in shares)		5,634									5,591	5,525
Basic income (loss) per share (in usd per share)		$ 110.99				$ (20.76)	$ (16.01)	$ (35.05)	$ (33.89)		$ (105.63)	$ (197.45)
Diluted income (loss) per share (in usd per share)		$ 110.99				$ (20.76)	$ (16.01)	$ (35.05)	$ (33.89)		$ (105.63)	$ (197.45)
Predecessor | Employee Stock Option
Weighted average shares (denominator):
Dilutive effect of stock options (in shares)		0									0	0
Predecessor | Warrant
Weighted average shares (denominator):
Dilutive effect of warrants (in shares)		0									0	0

EARNINGS PER SHARE - Additional

EARNINGS PER SHARE - Additional Information (Details) - USD ($)	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Weighted Average Shares Used In Computing Earnings Per Share [Line Items]
Shares of common stock issued upon vesting of restricted stock (in shares)		1,195
Warrant
Weighted Average Shares Used In Computing Earnings Per Share [Line Items]
Antidilutive stock options outstanding (in shares)		3,500,000
Restricted Stock
Weighted Average Shares Used In Computing Earnings Per Share [Line Items]
Antidilutive stock options outstanding (in shares)		62,137
Predecessor
Weighted Average Shares Used In Computing Earnings Per Share [Line Items]
Shares of common stock issued upon vesting of restricted stock (in shares)	47,390		79,621	41,375
Predecessor | Employee Stock Option
Weighted Average Shares Used In Computing Earnings Per Share [Line Items]
Antidilutive stock options outstanding (in shares)	10,400		12,900	14,400
Predecessor | Restricted Stock
Weighted Average Shares Used In Computing Earnings Per Share [Line Items]
Antidilutive stock options outstanding (in shares)	0
1.75% Senior Convertible Notes due 2017 | Predecessor
Weighted Average Shares Used In Computing Earnings Per Share [Line Items]
Dilutive effect on the diluted earnings per share	$ 0		$ 0	$ 0

ACCOUNTS RECEIVABLE - Component

ACCOUNTS RECEIVABLE - Components of Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable [Line Items]
Other co-venturers	$ 2,656
Trade	34,980
Unbilled accounts receivable	820
Other	802
Total accounts receivable	$ 39,258
Predecessor
Accounts, Notes, Loans and Financing Receivable [Line Items]
Other co-venturers		$ 3,532
Trade		42,944
Unbilled accounts receivable		591
Other		1,397
Total accounts receivable		$ 48,464

CONCENTRATIONS - Customers from

CONCENTRATIONS - Customers from Whom We Derived 10% or More of Total Oil and Gas Revenue (Details) - Customer Concentration Risk - Sales Revenue, Product Line	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Phillips 66 Company
Concentration Risk [Line Items]
Customers from whom 10% or more revenue derived		74.00%
Shell Trading (US) Company
Concentration Risk [Line Items]
Customers from whom 10% or more revenue derived		15.00%
Williams Ohio Valley Midstream LLC
Concentration Risk [Line Items]
Customers from whom 10% or more revenue derived		0.00%
Conoco
Concentration Risk [Line Items]
Customers from whom 10% or more revenue derived		0.00%
Predecessor | Phillips 66 Company
Concentration Risk [Line Items]
Customers from whom 10% or more revenue derived	56.00%		68.00%	53.00%
Predecessor | Shell Trading (US) Company
Concentration Risk [Line Items]
Customers from whom 10% or more revenue derived	7.00%		10.00%	13.00%
Predecessor | Williams Ohio Valley Midstream LLC
Concentration Risk [Line Items]
Customers from whom 10% or more revenue derived	12.00%		2.00%	9.00%
Predecessor | Conoco
Concentration Risk [Line Items]
Customers from whom 10% or more revenue derived	11.00%		5.00%	2.00%

CONCENTRATIONS - Additional Inf

CONCENTRATIONS - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Unusual Risk or Uncertainty [Line Items]
Maximum amount of credit risk exposure	$ 30.5
GOM Deep Water, Conventional Shelf and Deep Gas Properties
Unusual Risk or Uncertainty [Line Items]
Production associated with properties	88.00%

DERIVATIVE INSTRUMENTS AND HE65

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Additional Information (Details)	Mar. 09, 2018counterparty	Dec. 31, 2017contract	Dec. 31, 2016instalment	Dec. 31, 2016hedging_instrument	Dec. 31, 2016contract
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%
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Number of derivative instruments outstanding		0
Subsequent Event
Derivative Instruments, Gain (Loss) [Line Items]
Percentage of counterparty contract volume	64.00%
Fixed-Price Swaps And Costless Collars | Subsequent Event
Derivative Instruments, Gain (Loss) [Line Items]
Number of counterparties | counterparty	4
Predecessor
Derivative Instruments, Gain (Loss) [Line Items]
Number of derivative instruments outstanding					0
Predecessor | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Number of derivative instruments outstanding			0	0

DERIVATIVE INSTRUMENTS AND HE66

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Summary of Derivative Instruments (Details) - Not Designated as Hedging Instrument - Subsequent Event bbl in Thousands, MMBTU in Thousands	Mar. 09, 2018MMBTU$ / MMBTU$ / bblbbl
Oil | Commodity Put Contract January Through December 2018, Contract One
Derivative [Line Items]
Daily volume (Bbls/d) | bbl	1
Floor price (in usd per MMBtu or Bbl)	54
Oil | Commodity Put Contract January Through December 2018, Contract Two
Derivative [Line Items]
Daily volume (Bbls/d) | bbl	1
Floor price (in usd per MMBtu or Bbl)	45
Oil | Commodity Fixed-Price Swap Contract, January Through December 2018
Derivative [Line Items]
Daily volume (Bbls/d) | bbl	1
Swap price (in usd/bbl)	52.5
Oil | Commodity Fixed-Price Swap Contract, January Through December 2018 Contract Two
Derivative [Line Items]
Daily volume (Bbls/d) | bbl	1
Swap price (in usd/bbl)	51.98
Oil | Commodity Fixed-Price Swap Contract, January Through December 2018 Contract Three
Derivative [Line Items]
Daily volume (Bbls/d) | bbl	1
Swap price (in usd/bbl)	53.67
Oil | Commodity Fixed-Price Swap Contract, January Through December 2019
Derivative [Line Items]
Daily volume (Bbls/d) | bbl	1
Swap price (in usd/bbl)	51
Oil | Commodity Fixed-Price Swap Contract, January Through December 2019 Contract Two
Derivative [Line Items]
Daily volume (Bbls/d) | bbl	1
Swap price (in usd/bbl)	51.57
Oil | Commodity Fixed-Price Swap Contract, January Through December 2019 Contract Three
Derivative [Line Items]
Daily volume (Bbls/d) | bbl	2
Swap price (in usd/bbl)	56.13
Oil | Commodity Collar Contract January Through December 2018
Derivative [Line Items]
Daily volume (Bbls/d) | bbl	1
Floor price (in usd per MMBtu or Bbl)	45
Ceiling price (in usd per MMBtu or Bbl)	55.35
Natural Gas | Commodity Collar Contract January Through December 2018
Derivative [Line Items]
Floor price (in usd per MMBtu or Bbl) | $ / MMBTU	2.75
Daily Volume (MMBtus/d) | MMBTU	6
Ceiling price (in usd per MMBtu or Bbl) | $ / MMBTU	3.24

DERIVATIVE INSTRUMENTS AND HE67

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Location and Fair Value Amounts of Derivative Instruments Reported in Balance Sheet (Details) $ in Thousands	Dec. 31, 2017USD ($)
Asset Derivatives
Fair value of derivative instruments, assets	$ 879
Liability Derivatives
Fair value of derivative instruments, liabilities	12,054
Not Designated as Hedging Instrument | Commodity contracts
Asset Derivatives
Fair value of derivative instruments, assets	900
Liability Derivatives
Fair value of derivative instruments, liabilities	12,100
Not Designated as Hedging Instrument | Commodity contracts | Current assets: Fair value of derivative contracts
Asset Derivatives
Fair value of derivative instruments, assets	900
Not Designated as Hedging Instrument | Commodity contracts | Long-term assets: Fair value of derivative contracts
Asset Derivatives
Fair value of derivative instruments, assets	0
Not Designated as Hedging Instrument | Commodity contracts | Current liabilities: Fair value of derivative contracts
Liability Derivatives
Fair value of derivative instruments, liabilities	9,000
Not Designated as Hedging Instrument | Commodity contracts | Long-term liabilities: Fair value of derivative contracts
Liability Derivatives
Fair value of derivative instruments, liabilities	$ 3,100

DERIVATIVE INSTRUMENTS AND HE68

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Gains or Losses Related to Changes in Fair Value and Cash Settlements on Derivatives Not Qualifying as Hedging Instruments (Details) - Not Designated as Hedging Instrument - Commodity contracts - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Cash settlements		$ 2,161
Change in fair value		(15,549)
Total gain on non-qualifying derivatives		$ (13,388)
Predecessor
Derivatives, Fair Value [Line Items]
Cash settlements	$ 0		$ 0	$ 17,385
Change in fair value	(1,778)		0	(12,146)
Total gain on non-qualifying derivatives	$ (1,778)		$ 0	$ 5,239

DERIVATIVE INSTRUMENTS AND HE69

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Before Tax Effect of Derivative Instruments in Statement of Operations (Details) - Predecessor - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Increase in oil revenue owing to effective hedging contracts	$ 23,747	$ 135,617
Increase (decrease) in gas revenue owing to effective hedging contracts	11,710	14,338
Designated as Hedging Instrument | Cash Flow Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives	(1,648)	52,630
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion)	35,457	149,955
Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	(810)	2,713
Designated as Hedging Instrument | Cash Flow Hedging | Operating revenue - oil/natural gas production
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion)	35,457	149,955
Designated as Hedging Instrument | Cash Flow Hedging | Derivative income (expense), net
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	(810)	2,713
Designated as Hedging Instrument | Cash Flow Hedging | Commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives	$ (1,648)	$ 52,630

DERIVATIVE INSTRUMENTS AND HE70

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Offsetting Assets and Liabilities (Details) $ in Millions	Dec. 31, 2017USD ($)
Current assets: Fair value of derivative contracts
Offsetting Derivative Assets [Abstract]
Derivative assets as presented without netting	$ 0.9
Derivative assets effects of netting	(0.9)
Derivative assets with effects of netting	0
Long-term assets: Fair value of derivative contracts
Offsetting Derivative Assets [Abstract]
Derivative assets as presented without netting	0
Derivative assets effects of netting	0
Derivative assets with effects of netting	0
Current liabilities: Fair value of derivative contracts
Offsetting Derivative Liabilities [Abstract]
Derivative liabilities as presented without netting	(9)
Derivative liabilities effects of netting	0.9
Derivative liabilities with effects of netting	8.1
Long-term liabilities: Fair value of derivative contracts
Offsetting Derivative Liabilities [Abstract]
Derivative liabilities as presented without netting	(3.1)
Derivative liabilities effects of netting	0
Derivative liabilities with effects of netting	$ 3.1

FAIR VALUE MEASUREMENTS - Asset

FAIR VALUE MEASUREMENTS - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Assets
Marketable securities (Other assets)	$ 5,081,000
Derivative contracts	879,000
Assets, fair value, total	5,960,000
Liabilities
Derivative contracts	12,054,000
Liabilities, fair value, total	12,054,000
Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Marketable securities (Other assets)	5,081,000
Derivative contracts	0
Assets, fair value, total	5,081,000
Liabilities
Derivative contracts	0
Liabilities, fair value, total	0
Significant Other Observable Inputs (Level 2)
Assets
Marketable securities (Other assets)	0
Derivative contracts	0
Assets, fair value, total	0
Liabilities
Derivative contracts	10,110,000
Liabilities, fair value, total	10,110,000
Significant Unobservable Inputs (Level 3)
Assets
Marketable securities (Other assets)	0
Derivative contracts	879,000
Assets, fair value, total	879,000
Liabilities
Derivative contracts	1,944,000
Liabilities, fair value, total	$ 1,944,000
Predecessor
Assets
Marketable securities (Other assets)		$ 8,746,000
Assets, fair value, total		8,746,000
Liabilities
Liabilities, fair value, total		0
Predecessor | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Marketable securities (Other assets)		8,746,000
Assets, fair value, total		8,746,000
Predecessor | Significant Other Observable Inputs (Level 2)
Assets
Marketable securities (Other assets)		0
Assets, fair value, total		0
Predecessor | Significant Unobservable Inputs (Level 3)
Assets
Marketable securities (Other assets)		0
Assets, fair value, total		$ 0

FAIR VALUE MEASUREMENTS - Addit

FAIR VALUE MEASUREMENTS - Additional Information (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Liabilities at fair value	$ 12,054,000
7.5% Senior Notes due 2022
Debt Instrument [Line Items]
Fair value of senior notes	$ 227,300,000
Predecessor
Debt Instrument [Line Items]
Liabilities at fair value		$ 0
Predecessor | Convertible Notes Due 2017
Debt Instrument [Line Items]
Fair value of convertible notes		293,500,000
Predecessor | 7.5% Senior Notes due 2022
Debt Instrument [Line Items]
Fair value of senior notes		$ 465,000,000

FAIR VALUE MEASUREMENTS - Ass73

FAIR VALUE MEASUREMENTS - Asset and Liability Unobservable Input Reconciliation (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended
	Feb. 28, 2017	Dec. 31, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance, assets		$ 3,087
Included in earnings		(5,201)
Included in other comprehensive income		0
Purchases, sales, issuances and settlements		1,049
Transfers in and out of Level 3		0
Ending balance, liabilities		(1,065)
Ending balance, assets	$ 3,087
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, 2017		(4,699)
Predecessor
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance, assets	0	$ 3,087
Included in earnings	(649)
Included in other comprehensive income	0
Purchases, sales, issuances and settlements	3,736
Transfers in and out of Level 3	0
Ending balance, assets	$ 3,087

ASSET RETIREMENT OBLIGATIONS -

ASSET RETIREMENT OBLIGATIONS - Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		$ 290,067
Liabilities incurred		2,280
Liabilities settled		(81,197)
Divestment of properties		0
Accretion expense		21,151
Revision of estimates		(19,200)
Fair value fresh start adjustment		0
Asset retirement obligations, end of period	$ 290,067	213,101
Predecessor
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	242,019	$ 290,067	$ 225,866	$ 316,409
Liabilities incurred	0		2,338	15,933
Liabilities settled	(3,641)		(19,630)	(72,713)
Divestment of properties	(8,672)		0	(248)
Accretion expense	5,447		40,229	25,988
Revision of estimates	0		(6,784)	(59,503)
Fair value fresh start adjustment	54,914		0	0
Asset retirement obligations, end of period	$ 290,067		$ 242,019	$ 225,866

INCOME TAXES - Analysis of Defe

INCOME TAXES - Analysis of Deferred Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Tax effect of temporary differences:
Net operating loss carryforwards	$ 66,304
Oil and gas properties	12,035
Asset retirement obligations	44,751
Stock compensation	278
Derivatives	3,110
Accrued incentive compensation	2,269
Debt issuance costs	644
Other	1,600
Total deferred tax assets (liabilities)	130,991
Valuation allowance	(130,991)
Net deferred tax assets (liabilities)	$ 0
Predecessor
Tax effect of temporary differences:
Net operating loss carryforwards		$ 201,557
Oil and gas properties		85,772
Asset retirement obligations		85,312
Stock compensation		3,294
Derivatives		0
Accrued incentive compensation		954
Debt issuance costs		7,480
Other		441
Total deferred tax assets (liabilities)		384,810
Valuation allowance		(384,810)
Net deferred tax assets (liabilities)		$ 0

INCOME TAXES - Additional Infor

INCOME TAXES - Additional Information (Details) - USD ($)	2 Months Ended		10 Months Ended	12 Months Ended
	Mar. 09, 2018	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Tax Cut and Jobs Act of 2017, change in tax rate, deferred tax assets and liabilities remeasurement					$ 87,300,000
Current federal income tax expense (benefit)			$ (18,339,000)
Deferred income tax provision (benefit)			0
Current income tax receivable			36,260,000		36,260,000
Operating loss carryforwards			315,700,000		315,700,000
Statutory depletion deductions available for tax reporting purposes			1,200,000		1,200,000
Valuation allowance of deferred tax assets			130,991,000		130,991,000
Income taxes allocated to other comprehensive income related to oil and gas hedges			0
Unrecognized tax benefits		$ 491,000	491,000		491,000
Unrecognized tax benefits, interest expense			33,000
Unrecognized tax benefits, penalties expense						$ 0
Predecessor
Income Tax Contingency [Line Items]
Current federal income tax expense (benefit)		3,570,000				(5,674,000)	$ (44,096,000)
Deferred income tax provision (benefit)		0				13,080,000	(272,311,000)
Current income tax receivable						26,086,000
Valuation allowance of deferred tax assets						384,810,000
Income taxes allocated to other comprehensive income related to oil and gas hedges		0				(13,100,000)	(35,700,000)
Unrecognized tax benefits		491,000				491,000
Unrecognized tax benefits, interest expense		7,000				$ 46,000	131,000
Unrecognized tax benefits, penalties expense		$ 0					$ 0
Forecast
Income Tax Contingency [Line Items]
U.S. Cancellation of debt income				$ 257,000,000
Unrecognized tax benefits				$ 0
Subsequent Event
Income Tax Contingency [Line Items]
Proceeds from income tax refunds	$ 20,600,000
IRC Section 382 Limitation
Income Tax Contingency [Line Items]
Operating loss carryforwards			127,000,000		127,000,000
Unlimited Portion
Income Tax Contingency [Line Items]
Operating loss carryforwards			$ 189,000,000		$ 189,000,000

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 (Details)	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reconciliation Of Federal Income Tax Rate [Line Items]
Income tax expense computed at the statutory federal income tax rate		35.00%
Tax Act rate change		(32.80%)
State taxes		(0.70%)
Change in valuation allowance		5.30%
IRC Sec. 162(m) limitation		0.40%
Tax deficits on stock compensation		(0.60%)
Reorganization fees		0.30%
Other		0.00%
Effective income tax rate		6.90%
Predecessor
Reconciliation Of Federal Income Tax Rate [Line Items]
Income tax expense computed at the statutory federal income tax rate	35.00%		35.00%	35.00%
Tax Act rate change	0.00%		0.00%	0.00%
State taxes	0.30%		0.20%	0.60%
Change in valuation allowance	(37.80%)		(35.00%)	(12.80%)
IRC Sec. 162(m) limitation	0.00%		(0.30%)	(0.10%)
Tax deficits on stock compensation	0.60%		(0.70%)	(0.10%)
Reorganization fees	2.50%		(0.30%)	0.00%
Other	0.00%		(0.20%)	(0.10%)
Effective income tax rate	0.60%		(1.30%)	22.50%

INCOME TAXES - Unrecognized Tax

INCOME TAXES - Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended
	Feb. 28, 2017	Dec. 31, 2017
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Total unrecognized tax benefits, beginning balance		$ 491
Tax positions taken during a prior period		0
Tax positions taken during the current period		0
Settlements with taxing authorities		0
Lapse of applicable statute of limitations		0
Total unrecognized tax benefits, ending balance	$ 491	491
Predecessor
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Total unrecognized tax benefits, beginning balance	491	$ 491
Tax positions taken during a prior period	0
Tax positions taken during the current period	0
Settlements with taxing authorities	0
Lapse of applicable statute of limitations	0
Total unrecognized tax benefits, ending balance	$ 491

DEBT - Long-Term Debt (Details)

DEBT - Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Mar. 01, 2017	Feb. 28, 2017	Dec. 31, 2016	Oct. 20, 2016	Nov. 20, 2015
Debt Instrument [Line Items]
Total debt	$ 235,927
Less: current portion of long-term debt	(425)
Long-term debt	235,502
Second Lien Notes | Senior Notes
Debt Instrument [Line Items]
Total debt	$ 225,000
Interest rate	7.50%	7.50%
Notes Due Two Thousand Seventeen | Convertible Debt
Debt Instrument [Line Items]
Interest rate			1.75%
Notes Due Two Thousand Twenty Two | Senior Notes
Debt Instrument [Line Items]
Interest rate			7.50%		7.50%
Building Loan | Secured Debt
Debt Instrument [Line Items]
Total debt	$ 10,927
Interest rate	4.20%
Predecessor
Debt Instrument [Line Items]
Total debt				$ 1,427,784
Less: current portion of long-term debt				(408)
Less: liabilities subject to compromise				(1,075,000)
Long-term debt				352,376
Predecessor | Notes Due Two Thousand Seventeen | Convertible Debt
Debt Instrument [Line Items]
Total debt				$ 300,000
Interest rate				1.75%	1.75%
Predecessor | Notes Due Two Thousand Twenty Two | Senior Notes
Debt Instrument [Line Items]
Total debt				$ 775,000
Interest rate				7.50%
Predecessor | Bank Debt | Line of Credit | Predecessor revolving credit facility
Debt Instrument [Line Items]
Total debt				$ 341,500
Predecessor | Building Loan
Debt Instrument [Line Items]
Interest rate						4.20%
Predecessor | Building Loan | Secured Debt
Debt Instrument [Line Items]
Total debt				$ 11,284
Interest rate				4.20%

DEBT - Additional Information (

DEBT - Additional Information (Details)

Mar. 01, 2017USD ($)

Feb. 28, 2017USD ($)

Dec. 14, 2016USD ($)

Jun. 10, 2016$ / shares

Nov. 20, 2015USD ($)instalment

Mar. 06, 2012USD ($)

Feb. 28, 2017USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2017USD ($)$ / shares

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Nov. 08, 2017USD ($)

Feb. 27, 2017USD ($)

Jun. 24, 2014USD ($)

Nov. 30, 2013

Nov. 27, 2013USD ($)

Nov. 30, 2012

Nov. 08, 2012USD ($)

Debt Instrument [Line Items]

Current portion of long-term debt

$ 425,000

$ 425,000

Outstanding borrowing

0

0

Outstanding balance

235,927,000

235,927,000

Stock split, conversion ratio

0.1

Write-off of deferred financing costs and associated unamortized discounts and premiums

$ 8,332,000

Total interest cost incurred

$ 15,700,000

91,100,000

$ 85,300,000

Interest expense

$ 11,744,000

Minimum

Debt Instrument [Line Items]

Percentage of borrowing base utilization

1.50%

Maximum

Debt Instrument [Line Items]

Percentage of borrowing base utilization

2.50%

Secured Debt | Building Loan

Debt Instrument [Line Items]

Interest rate

4.20%

4.20%

Outstanding balance

$ 10,927,000

$ 10,927,000

1.75% Senior Convertible Notes due 2017

Debt Instrument [Line Items]

Liabilities subject to compromise

$ 300,000,000

Aggregate principal amount of senior notes

$ 300,000,000

Initial conversion rate of common stock

0.0023449

0.0234449

Initial conversion price of convertible note 2017 (in usd per share) | $ / shares

$ 426.50

$ 42.65

Interest expense related to amortization of discount

15,407,000

15,019,000

Amortization of deferred financing costs

1,471,000

1,434,000

Effective interest rates

7.51%

7.51%

7.04%

7.75%

Interest expense

$ 0

1.75% Senior Convertible Notes due 2017 | Other Assets

Debt Instrument [Line Items]

Unamortized deferred financing costs

2,800,000

7.5% Senior Notes due 2022

Debt Instrument [Line Items]

Liabilities subject to compromise

$ 775,000,000

$ 775,000,000

Aggregate principal amount of senior notes

$ 475,000,000

$ 300,000,000

Interest expense

0

Bank Debt

Debt Instrument [Line Items]

Borrowing base

$ 150,000,000

Outstanding borrowing under bank credit facility

12,600,000

12,600,000

Initial bank and availability under facility

$ 87,400,000

$ 87,400,000

Base borrowing and credit facility

$ 900,000,000

Interest expense

$ 0

Senior Notes | Second Lien Notes

Debt Instrument [Line Items]

Interest rate

7.50%

7.50%

7.50%

Aggregate principal amount of senior notes

$ 225,000,000

Outstanding balance

$ 225,000,000

$ 225,000,000

Increase in accrued interest

1,400,000

Redemption price percent

107.50%

Redemption price, percentage of principal amount outstanding

65.00%

Debt default, percentage of principal amount outstanding

25.00%

Senior Convertible Notes Due Two Thousand Seventeen And Two Thousand And Twenty Two

Debt Instrument [Line Items]

Unamortized deferred financing costs

$ 59,000

$ 59,000

63,000

Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit

Debt Instrument [Line Items]

Consolidated interest coverage ratio (not less than)

2.75

Minimum liquidity required (at least)

0.2

Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Fifth Amended and Restated Credit Agreement

Debt Instrument [Line Items]

Borrowing base

$ 150,000,000

$ 150,000,000

$ 100,000,000

Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Period One

Debt Instrument [Line Items]

Consolidated funded debt to consolidated EBITDA ratio

2.75

Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Period Two

Debt Instrument [Line Items]

Consolidated funded debt to consolidated EBITDA ratio

2.50

Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Period Three

Debt Instrument [Line Items]

Consolidated funded debt to consolidated EBITDA ratio

3

Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Period Four

Debt Instrument [Line Items]

Consolidated funded debt to consolidated EBITDA ratio

2.75

Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Period Five

Debt Instrument [Line Items]

Consolidated funded debt to consolidated EBITDA ratio

2.50

Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Period Six

Debt Instrument [Line Items]

Consolidated funded debt to consolidated EBITDA ratio

2.75

Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Period Seven

Debt Instrument [Line Items]

Consolidated funded debt to consolidated EBITDA ratio

3

Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Period Eight

Debt Instrument [Line Items]

Consolidated funded debt to consolidated EBITDA ratio

3.50

Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Period Nine

Debt Instrument [Line Items]

Consolidated funded debt to consolidated EBITDA ratio

3

Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Period Ten

Debt Instrument [Line Items]

Consolidated funded debt to consolidated EBITDA ratio

2.75

Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Period Eleven

Debt Instrument [Line Items]

Consolidated funded debt to consolidated EBITDA ratio

2.50

Letter of Credit | Bank of America, N.A.

Debt Instrument [Line Items]

Outstanding borrowing under bank credit facility

$ 12,500,000

Base Rate | Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Minimum | Fifth Amended and Restated Credit Agreement

Debt Instrument [Line Items]

Percentage of borrowing base utilization

2.00%

Base Rate | Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Maximum | Fifth Amended and Restated Credit Agreement

Debt Instrument [Line Items]

Percentage of borrowing base utilization

3.00%

LIBOR | Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Minimum | Fifth Amended and Restated Credit Agreement

Debt Instrument [Line Items]

Percentage of borrowing base utilization

3.00%

LIBOR | Predecessor revolving credit facility | Bank of America, N.A. | Line of Credit | Maximum | Fifth Amended and Restated Credit Agreement

Debt Instrument [Line Items]

Percentage of borrowing base utilization

4.00%

Predecessor

Debt Instrument [Line Items]

Current portion of long-term debt

408,000

Outstanding borrowing

$ 341,500,000

Outstanding balance

1,427,784,000

Write-off of deferred financing costs and associated unamortized discounts and premiums

2,577,000

Interest expense

0

$ 64,458,000

$ 43,928,000

Predecessor | Building Loan

Debt Instrument [Line Items]

Interest rate

4.20%

Aggregate principal amount of senior notes

$ 11,802,000

Number of monthly installments | instalment

180

Monthly installment payment

$ 73,000

EBITDA to net interest expense ratio

2

Predecessor | Secured Debt | Building Loan

Debt Instrument [Line Items]

Interest rate

4.20%

Outstanding balance

$ 11,284,000

Predecessor | 1.75% Senior Convertible Notes due 2017

Debt Instrument [Line Items]

Aggregate principal amount of senior notes

$ 300,000,000

Predecessor | 7.5% Senior Notes due 2022

Debt Instrument [Line Items]

Liabilities subject to compromise

$ 775,000,000

Predecessor | Bank Debt

Debt Instrument [Line Items]

Outstanding borrowing under bank credit facility

$ 12,500,000

Exchange of Stock for Stock

Debt Instrument [Line Items]

Write-off of unamortized deferred financing costs

$ (2,577,000)

$ (2,577,000)

Debt Instrument, Redemption, Period One | Senior Notes | Second Lien Notes

Debt Instrument [Line Items]

Percentage of principal amount redeemed

35.00%

Redemption price percent

105.625%

Debt Instrument, Redemption, Period Two | Senior Notes | Second Lien Notes

Debt Instrument [Line Items]

Percentage of principal amount redeemed

100.00%

Redemption price percent

105.625%

Debt Instrument, Redemption, Period Three | Senior Notes | Second Lien Notes

Debt Instrument [Line Items]

Redemption price percent

100.00%

ACCUMULATED OTHER COMPREHENSI81

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) - Additional Information (Details) - Predecessor $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)contract
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of derivative instruments outstanding | contract	0
Foreign Currency Items | Other operational expenses
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from accumulated other comprehensive income | $	$ 6,081

ACCUMULATED OTHER COMPREHENSI82

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) - Schedule of Changes in Accumulated Other Comprehensive Income Loss (Details) - Predecessor - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Amounts reclassified from accumulated other comprehensive income:
Ending balance, net of tax	$ (637,282)
Cash Flow Hedges
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance, net of tax	24,025	$ 86,783
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	(1,648)	52,630
Foreign currency translations	0	0
Income tax effect	581	(19,096)
Net of tax	(1,067)	33,534
Amounts reclassified from accumulated other comprehensive income:
Income tax effect	(12,499)	(54,833)
Net of tax	22,958	96,292
Other comprehensive income (loss), net of tax	(24,025)	(62,758)
Ending balance, net of tax	0	24,025
Cash Flow Hedges | Operating revenue: oil/natural gas production
Amounts reclassified from accumulated other comprehensive income:
Reclassification from accumulated other comprehensive income	35,457	149,955
Cash Flow Hedges | Derivative income, net
Amounts reclassified from accumulated other comprehensive income:
Reclassification from accumulated other comprehensive income		1,170
Cash Flow Hedges | Other operational expenses
Amounts reclassified from accumulated other comprehensive income:
Reclassification from accumulated other comprehensive income	0
Foreign Currency Items
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance, net of tax	(6,073)	(3,468)
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	0	0
Foreign currency translations	(8)	(2,605)
Income tax effect	0	0
Net of tax	(8)	(2,605)
Amounts reclassified from accumulated other comprehensive income:
Income tax effect	0	0
Net of tax	(6,081)	0
Other comprehensive income (loss), net of tax	6,073	(2,605)
Ending balance, net of tax	0	(6,073)
Foreign Currency Items | Operating revenue: oil/natural gas production
Amounts reclassified from accumulated other comprehensive income:
Reclassification from accumulated other comprehensive income	0	0
Foreign Currency Items | Derivative income, net
Amounts reclassified from accumulated other comprehensive income:
Reclassification from accumulated other comprehensive income		0
Foreign Currency Items | Other operational expenses
Amounts reclassified from accumulated other comprehensive income:
Reclassification from accumulated other comprehensive income	(6,081)
Total
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance, net of tax	17,952	83,315
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	(1,648)	52,630
Foreign currency translations	(8)	(2,605)
Income tax effect	581	(19,096)
Net of tax	(1,075)	30,929
Amounts reclassified from accumulated other comprehensive income:
Income tax effect	(12,499)	(54,833)
Net of tax	16,877	96,292
Other comprehensive income (loss), net of tax	(17,952)	(65,363)
Ending balance, net of tax	0	17,952
Total | Operating revenue: oil/natural gas production
Amounts reclassified from accumulated other comprehensive income:
Reclassification from accumulated other comprehensive income	35,457	149,955
Total | Derivative income, net
Amounts reclassified from accumulated other comprehensive income:
Reclassification from accumulated other comprehensive income		$ 1,170
Total | Other operational expenses
Amounts reclassified from accumulated other comprehensive income:
Reclassification from accumulated other comprehensive income	$ (6,081)

EMPLOYEE BENEFIT PLANS - Additi

EMPLOYEE BENEFIT PLANS - Additional Information (Details)	Mar. 09, 2018shares	Nov. 21, 2017day	Jul. 25, 2017day	Dec. 07, 2007USD ($)	Feb. 28, 2017USD ($)shares	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)shares	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares
Employee Benefit And Retirement Plans [Line Items]
Liability of vested benefits recorded in other long term liabilities							$ 900,000	$ 900,000
Incentive compensation expense							$ 8,045,000
Retention award payout, number of days | day			30
Bonus award payout, number of days | day		30
Restricted stocks issued, shares (in shares) | shares							0
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							$ 600,000
Maximum percentage of deferred compensation plan								100.00%
Plan assets included in other assets							5,100,000	$ 5,100,000
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
2016 Incentive Plan
Employee Benefit And Retirement Plans [Line Items]
Incentive compensation expense							7,000,000
Stone Energy Corporation Retention Award Agreement
Employee Benefit And Retirement Plans [Line Items]
Incentive compensation expense							$ 1,000,000
Stone Energy Corporation 2017 Long-Term Incentive Plan
Employee Benefit And Retirement Plans [Line Items]
Additional shares available for issuance (in shares) | shares							2,614,379	2,614,379
Stone Energy Corporation Executive Severance Plan
Employee Benefit And Retirement Plans [Line Items]
Percentage of potential bonus payments to executives			100.00%
Stone Energy Corporation Executive Severance Plan | Minimum
Employee Benefit And Retirement Plans [Line Items]
Salary pay out rate			1
Stone Energy Corporation Executive Severance Plan | Maximum
Employee Benefit And Retirement Plans [Line Items]
Salary pay out rate			1.5
Predecessor
Employee Benefit And Retirement Plans [Line Items]
Incentive compensation expense					$ 2,008,000				$ 13,475,000	$ 2,242,000
Restricted stocks issued, shares (in shares) | shares									31,313	141,872
Amount of contribution by the company to Stone Energy 401 (k) Profit Sharing Plan					300,000				$ 1,200,000	$ 1,600,000
Plan assets included in other assets						$ 8,700,000			$ 8,700,000
Predecessor | Executive Officer | Deferred Bonus
Employee Benefit And Retirement Plans [Line Items]
Expenses related to incentive compensation bonus					$ 2,000,000
Predecessor | Executive Officer | Deferred Bonus | Maximum
Employee Benefit And Retirement Plans [Line Items]
Deferred compensation arrangement compensation expense						$ 2,008,000
Predecessor | Director
Employee Benefit And Retirement Plans [Line Items]
Restricted stocks issued, shares (in shares) | shares					10,404
Restricted Stock | Director
Employee Benefit And Retirement Plans [Line Items]
Restricted stocks issued, shares (in shares) | shares							62,137
Restricted Stock | Subsequent Event | Director
Employee Benefit And Retirement Plans [Line Items]
Restricted stocks issued, shares (in shares) | shares	62,137

SHARE-BASED COMPENSATION - Addi

SHARE-BASED COMPENSATION - Additional Information (Details) - USD ($)	Feb. 15, 2017	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Adjustments to additional paid-in capital related to net tax effect of stock options exercises and restricted stock vesting				$ 0
Net tax impact from stock option exercises and restricted stock vesting			$ 2,500,000
Restricted stocks issued, shares (in shares)			0
Per share value (in usd per share)		$ 26.95
RSA
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of common stock issued in reorganization to existing shareholders	5.00%
Percentage of warrants issued in reorganization (up to)	15.00%
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation			$ 100,000
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation			1,200,000
Aggregate grant date fair value			1,700,000
Unrecognized compensation cost			$ 500,000	$ 500,000
Vesting period of restricted stock units			4 months
Director | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stocks issued, shares (in shares)			62,137
Predecessor
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Adjustments to additional paid-in capital related to net tax effect of stock options exercises and restricted stock vesting					$ 0
Net tax impact from stock option exercises and restricted stock vesting		$ 2,700,000			4,100,000	$ 1,300,000
Share-based compensation		3,500,000			11,600,000	17,900,000
Share-based compensation capitalized into oil and gas properties		$ 900,000			$ 3,100,000	$ 5,600,000
Stock option granted (in shares)		0
Restricted stocks issued, shares (in shares)					31,313	141,872
Restricted stocks issued, value					$ 300,000	$ 23,700,000
Predecessor | Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stocks issued, shares (in shares)		10,404
Restricted stocks issued, value		$ 69,000

SHARE-BASED COMPENSATION - Summ

SHARE-BASED COMPENSATION - Summary of Stock Option Activity under Plan (Details) - Predecessor - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Number of Options
Options outstanding, beginning of period (in shares)	14,447	20,497
Granted (in shares)	0	0
Exercised (in shares)	0	0
Forfeited (in shares)	0	0
Expired (in shares)	(1,500)	(6,050)
Options outstanding, end of period (in shares)	12,947	14,447
Options exercisable, end of period (in shares)	12,947	14,447
Options unvested, end of period (in shares)	0	0
Wgtd. Avg. Exercise Price
Options outstanding, beginning of period (in usd per share)	$ 269.25	$ 339.36
Granted (in usd per share)	0	0
Exercised (in usd per share)	0	0
Forfeited (in usd per share)	0	0
Expired (in usd per share)	477.45	506.76
Options outstanding, end of period (in usd per share)	245.13	269.25
Options exercisable, end of period (in usd per share)	245.13	269.25
Options unvested, end of period (in usd per share)	$ 0	$ 0
Wgtd. Avg. Term
Options outstanding, Weighted Average Term, end of period	1 year 4 months 24 days	2 years 1 month 6 days
Options exercisable, Weighted Average Term, end of period	1 year 4 months 24 days	2 years 1 month 6 days
Aggregate Intrinsic Value (in thousands)
Options outstanding, end of period	$ 0	$ 0
Options exercisable, end of period	$ 0	$ 0

SHARE-BASED COMPENSATION - Su86

SHARE-BASED COMPENSATION - Summary of Restricted Stock Activity under Plan (Details) - $ / shares	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Number of Restricted Shares
Restricted stock outstanding, beginning of period (in shares)		3,176
Issuances (in shares)		0
Lapse of restrictions or granting of stock awards (in shares)		(2,083)
Forfeitures (in shares)		0
Restricted stock outstanding, end of period (in shares)	3,176	1,093
Wgtd. Avg. Fair Value Per Share
Restricted stock outstanding, beginning of period (in usd per share)		$ 26.95
Issuances (in usd per share)		0
Lapse of restrictions or granting of stock awards (in usd per share)		21.78
Forfeitures (in usd per share)		0
Restricted stock outstanding, end of period (in usd per share)	$ 26.95	$ 26.95
Predecessor
Number of Restricted Shares
Restricted stock outstanding, beginning of period (in shares)	81,090	18,024	180,239	129,848
Issuances (in shares)			31,313	141,872
Lapse of restrictions or granting of stock awards (in shares)	(73,276)		(117,406)	(63,745)
Forfeitures (in shares)	(194)		(13,056)	(27,736)
Restricted stock outstanding, end of period (in shares)	18,024		81,090	180,239
Wgtd. Avg. Fair Value Per Share
Restricted stock outstanding, beginning of period (in usd per share)	$ 205.34	$ 169.42	$ 208.17	$ 299.45
Issuances (in usd per share)	6.67		8.93	167.21
Lapse of restrictions or granting of stock awards (in usd per share)	186.37		158.79	296
Forfeitures (in usd per share)	169.40		200.06	223.80
Restricted stock outstanding, end of period (in usd per share)	$ 169.42		$ 205.34	$ 208.17

REDUCTION IN WORKFORCE (Details

REDUCTION IN WORKFORCE (Details) - USD ($) $ in Millions	3 Months Ended	10 Months Ended
	Jun. 30, 2017	Dec. 31, 2017
Restructuring Cost and Reserve [Line Items]
Reduction in total workforce, percent	20.00%
Severance costs		$ 5.7
Appalachia Properties
Restructuring Cost and Reserve [Line Items]
Severance costs	$ 3

FEDERAL ROYALTY RECOVERY (Detai

FEDERAL ROYALTY RECOVERY (Details) - USD ($) $ in Millions	1 Months Ended	10 Months Ended
	Jul. 31, 2017	Dec. 31, 2017
Royalty Revenues [Line Items]
Federal royalty recovery revenue	$ 14.1
Consulting fees		$ 3.9
Other Revenue, Net
Royalty Revenues [Line Items]
Federal royalty recovery revenue	9.6
Oil And Gas Property, Lease Operating Expense
Royalty Revenues [Line Items]
Federal royalty recovery revenue	$ 4.5

OTHER OPERATIONAL EXPENSES (Det

OTHER OPERATIONAL EXPENSES (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended				10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Other operational expenses						$ 3,359
Stacking charges						$ 2,100
Predecessor
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Other operational expenses	$ 530	$ 6,187	$ 9,059	$ 27,680	$ 12,527		$ 55,453	$ 2,360
Oil and gas, subsidy charges							17,700
Predecessor | ENSCO Deep Water Drilling Rig
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Loss on contract termination							20,000
Predecessor | Saxon Appalachian Rig
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Loss on contract termination							9,900
Predecessor | Foreign Currency Items
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Other operational loss							$ 6,100

COMBINATION TRANSACTION COSTS -

COMBINATION TRANSACTION COSTS - Additional Information (Details) $ in Thousands	10 Months Ended
	Dec. 31, 2017USD ($)
Business Acquisition [Line Items]
Stock issuance costs - Talos combination	$ 183
General and Administrative Expense
Business Acquisition [Line Items]
Transaction costs	6,200
Additional Paid-In Capital
Business Acquisition [Line Items]
Stock issuance costs - Talos combination	$ 183

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Additional Information (Details)	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017USD ($)	Dec. 31, 2017USD ($)MBbls	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Loss Contingencies [Line Items]
Minimum net commitment under leases		$ 300,000
Payments related to lease obligations		500,000
Commitments to use drilling rigs and acquisition of seismic data, value		$ 8,600,000
Commitments to use drilling rigs and acquisition of seismic data, period		2 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
Minimum
Loss Contingencies [Line Items]
Potential contingency loss		75,000,000
Maximum
Loss Contingencies [Line Items]
Potential contingency loss		133,700,000
Bureau of Ocean Energy Management
Loss Contingencies [Line Items]
Contingent liability to surety insurance company		$ 115,000,000
Predecessor
Loss Contingencies [Line Items]
Payments related to lease obligations	$ 100,000		$ 700,000	$ 3,100,000

SUPPLEMENTAL INFORMATION ON O92

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED - Additional Information (Details) $ in Thousands	Dec. 31, 2016USD ($)$ / bbl$ / Mcf	Mar. 31, 2017USD ($)$ / bbl$ / Mcf	Feb. 28, 2017USD ($)	Dec. 31, 2017USD ($)project$ / bbl	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2016USD ($)$ / bbl$ / Mcf	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)project$ / bbl	Dec. 31, 2017USD ($)Bcfeproject$ / bbl	Dec. 31, 2016USD ($)Bcfe$ / bbl$ / Mcf	Dec. 31, 2015USD ($)Bcfe$ / bbl$ / Mcf	Mar. 01, 2017$ / bbl$ / Mcf
Reserve Quantities [Line Items]
Asset retirement costs included in development cost				$ (17,446)							$ (17,446)	$ (17,446)
Write-down of oil and gas properties		$ 256,435		$ 0	$ 0	$ 0					$ 256,435
Average 12-month oil prices net of differentials | $ / bbl		45.40		50.05							50.05	50.05			56.01
Average 12-month gas prices net of differentials | $ / Mcf	2.34	2.24					2.34						2.34		2.52
Average 12-month natural gas liquids prices net of differentials | $ / bbl	22.90						22.90						22.90
Specifically identified drilling projects | project				34							34	34
Projects expected to be evaluated											4 years
Annual discount rate for discounting future cash flows											10.00%
Predecessor
Reserve Quantities [Line Items]
Proved reserves			$ 380,800
Probable and possible reserves			16,800
Unevaluated properties reserves			80,200
Asset retirement costs included in development cost	$ (4,461)		0				$ (4,461)						$ (4,461)	$ (43,901)
Write-down of oil and gas properties			$ 0				$ 73,094	$ 36,484	$ 118,649	$ 129,204			$ 357,431	$ 1,362,447
Average 12-month oil prices net of differentials | $ / bbl	40.15						40.15						40.15	51.16
Average 12-month gas prices net of differentials | $ / Mcf	1.71						1.71						1.71	2.19
Average 12-month natural gas liquids prices net of differentials | $ / bbl	9.46						9.46						9.46	16.40
Decrease in written down value of oil and gas properties													$ 50,700	$ 143,900
Percentage of proved oil and natural gas reserves	34.00%
Scenario, Adjustment
Reserve Quantities [Line Items]
Revisions of previous estimates | Bcfe													15	(95)
Well Performance | Scenario, Adjustment
Reserve Quantities [Line Items]
Revisions of previous estimates | Bcfe												4	(6)	7
Appalachia Drilling Program | Scenario, Adjustment
Reserve Quantities [Line Items]
Revisions of previous estimates | Bcfe												17
Gold of Mexico Basin
Reserve Quantities [Line Items]
Percentage of proved oil and natural gas reserves											100.00%
NGLs (MBbls)
Reserve Quantities [Line Items]
Average 12-month gas prices net of differentials | $ / bbl		19.18													14.18

SUPPLEMENTAL INFORMATION ON O93

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED - Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract]
Proved properties	$ 713,157
Unevaluated properties	102,187
Less: accumulated depreciation, depletion and amortization	(353,462)
Predecessor
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract]
Proved properties		$ 9,616,236
Unevaluated properties		373,720
Less: accumulated depreciation, depletion and amortization		(9,178,442)
United States
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract]
Proved properties	713,157
Unevaluated properties	102,187
Total proved and unevaluated properties	815,344
Less: accumulated depreciation, depletion and amortization	(353,462)
Net proved oil and gas properties	$ 461,882
United States | Predecessor
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract]
Proved properties		9,572,082
Unevaluated properties		373,720
Total proved and unevaluated properties		9,945,802
Less: accumulated depreciation, depletion and amortization		(9,134,288)
Net proved oil and gas properties		$ 811,514

SUPPLEMENTAL INFORMATION ON O94

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED - Financial Data Related to Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended							10 Months Ended	12 Months Ended
	Mar. 31, 2017	Feb. 28, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated DD&A:
Foreign currency translation adjustment										$ 0
Write-down of oil and gas properties	$ (256,435)		$ 0	$ 0	$ 0					(256,435)
Balance, end of year			(353,462)							(353,462)	$ (353,462)
Costs incurred during the period (expensed):
Lease operating expenses										49,800
Transportation, processing and gathering expenses										4,084
Production taxes										629
Accretion expense										21,151
United States
Costs incurred during the period (capitalized):
Acquisition costs, net of sales of unevaluated properties										(8,371)
Exploratory costs										12,079
Development costs										33,356
Salaries, general and administrative costs										7,495
Interest										3,927
Less: overhead reimbursements										(1,004)
Total costs incurred during the year										47,482
Balance, end of year (fully evaluated at December 31, 2016 and 2015)			815,344							815,344	815,344
Accumulated DD&A:
Write-down of oil and gas properties										(256,435)
Balance, end of year			(353,462)							(353,462)	(353,462)
Net proved oil and gas properties			$ 461,882							461,882	461,882
Costs incurred during the period (expensed):
Lease operating expenses										49,800
Transportation, processing and gathering expenses										4,084
Production taxes										629
Accretion expense										21,151
Expensed costs – United States										$ 75,664
Predecessor
Accumulated DD&A:
Balance, beginning of year		$ (9,178,442)									(9,178,442)
Foreign currency translation adjustment		0										$ (6,073)	$ 2,605
Write-down of oil and gas properties		0				$ (73,094)	$ (36,484)	$ (118,649)	$ (129,204)			(357,431)	(1,362,447)
Balance, end of year						(9,178,442)						(9,178,442)
Costs incurred during the period (expensed):
Lease operating expenses		8,820										79,650	100,139
Transportation, processing and gathering expenses		6,933										27,760	58,847
Production taxes		682										3,148	6,877
Accretion expense		5,447										40,229	25,988
Predecessor | United States
Oil and gas properties – United States and Canada, proved and unevaluated:
Balance, beginning of year		9,945,802									9,945,802
Costs incurred during the period (capitalized):
Acquisition costs, net of sales of unevaluated properties		(324)										3,923	(14,158)
Exploratory costs		2,055										17,891	104,169
Development costs		12,547										102,665	266,982
Salaries, general and administrative costs		2,976										21,753	27,984
Interest		2,524										26,634	41,339
Less: overhead reimbursements		0										(521)	(913)
Total costs incurred during the year		19,778										172,345	425,403
Balance, end of year (fully evaluated at December 31, 2016 and 2015)						9,945,802						9,945,802
Accumulated DD&A:
Balance, beginning of year		(9,134,288)									(9,134,288)
Write-down of oil and gas properties											0	(357,079)	(1,314,817)
Balance, end of year						(9,134,288)						(9,134,288)
Net proved oil and gas properties						811,514						811,514
Costs incurred during the period (expensed):
Lease operating expenses		8,820										79,650	100,139
Transportation, processing and gathering expenses		6,933										27,760	58,847
Production taxes		682										3,148	6,877
Accretion expense		5,447										40,229	25,988
Expensed costs – United States		21,882										150,787	191,851
Predecessor | CANADA
Oil and gas properties – United States and Canada, proved and unevaluated:
Balance, beginning of year		44,154							42,484		44,154	42,484	36,579
Costs incurred during the period (capitalized):
Acquisition costs												(498)	(2,862)
Exploratory costs												2,168	8,767
Total costs incurred during the year												1,670	5,905
Balance, end of year (fully evaluated at December 31, 2016 and 2015)						44,154						44,154	42,484
Accumulated DD&A:
Balance, beginning of year		$ (44,154)							$ (42,484)		$ (44,154)	(42,484)	0
Foreign currency translation adjustment												(1,318)	5,146
Write-down of oil and gas properties												(352)	(47,630)
Balance, end of year						(44,154)						(44,154)	(42,484)
Net proved oil and gas properties						$ 0						$ 0	$ 0

SUPPLEMENTAL INFORMATION ON O95

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED - Amortization of Investment in Oil and Gas Properties (Details) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended							10 Months Ended	12 Months Ended
	Mar. 31, 2017USD ($)	Feb. 28, 2017USD ($)$ / bbl	Dec. 31, 2017USD ($)$ / bbl	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2016USD ($)$ / bbl	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)$ / bbl	Dec. 31, 2017USD ($)$ / bbl	Dec. 31, 2016USD ($)$ / bbl	Dec. 31, 2015USD ($)$ / bbl
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Depreciation, depletion and amortization										$ 99,890
Write-down of oil and gas properties	$ 256,435		$ 0	$ 0	$ 0					$ 256,435
DD&A per Boe | $ / bbl			16.61							16.61	16.61
United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Depreciation, depletion and amortization										$ 97,027
Write-down of oil and gas properties										$ 256,435
Predecessor
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Depreciation, depletion and amortization		$ 37,429										$ 220,079	$ 281,688
Write-down of oil and gas properties		0				$ 73,094	$ 36,484	$ 118,649	$ 129,204			357,431	1,362,447
Predecessor | United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Depreciation, depletion and amortization		$ 36,751										215,737	277,088
Write-down of oil and gas properties											$ 0	$ 357,079	$ 1,314,817
DD&A per Boe | $ / bbl		17.05				16.10						16.10	19.15

SUPPLEMENTAL INFORMATION ON O96

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED - Net Costs Incurred on Unevaluated Properties (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	$ 58,359	$ (9,155)	$ 49,204
Exploration costs	38,651	10,405	49,056
Capitalized interest	0	3,927	3,927
Total unevaluated costs	97,010	$ 5,177	$ 102,187
Predecessor
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	959			$ (71,378)	$ (115,767)
Exploration costs	(6,063)			(21,579)	(16,315)
Capitalized interest	2,524			26,634	41,339
Total unevaluated costs	$ (2,580)			$ (66,323)	$ (90,743)

SUPPLEMENTAL INFORMATION ON O97

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED - Summary of Estimated Proved Oil and Natural Gas Reserve (Details) MMcf in Thousands, MBbls in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017MMcfMBbls	Dec. 31, 2017MMcfMBbls	Dec. 31, 2016MMcfMBbls	Dec. 31, 2015MMcfMBbls
Oil (MBbls)
Oil and gas properties – United States, proved and unevaluated:
Revisions of previous estimates | MBbls		3,769
Production | MBbls		(4,169)
Estimated proved reserves, ending balance | MBbls		21,876
Estimated proved developed reserves: | MBbls		20,275
Estimated proved undeveloped reserves: | MBbls		1,601
NGLs (MBbls)
Oil and gas properties – United States, proved and unevaluated:
Revisions of previous estimates | MBbls		(94)
Production | MBbls		(403)
Estimated proved reserves, ending balance | MBbls		2,305
Estimated proved developed reserves: | MBbls		1,689
Estimated proved undeveloped reserves: | MBbls		616
Natural Gas (MMcf)
Oil and gas properties – United States, proved and unevaluated:
Revisions of previous estimates | MMcf		(2,801)
Production | MMcf		(7,616)
Estimated proved reserves, ending balance | MMcf		50,116
Estimated proved developed reserves: | MMcf		37,946
Estimated proved undeveloped reserves: | MMcf		12,170
Oil, Natural Gas and NGLs (MBoe)
Oil and gas properties – United States, proved and unevaluated:
Revisions of previous estimates | MMcf		3,208
Production | MMcf		(5,841)
Estimated proved reserves, ending balance | MMcf		32,533
Estimated proved developed reserves: | MMcf		28,288
Estimated proved undeveloped reserves: | MMcf		4,245
Predecessor | Oil (MBbls)
Oil and gas properties – United States, proved and unevaluated:
Estimated proved reserves, beginning balance | MBbls	23,280	22,276	30,276	42,397
Revisions of previous estimates | MBbls	730		(751)	(6,818)
Extensions, discoveries and other additions | MBbls			63	862
Purchase of producing properties | MBbls				685
Sale of reserves | MBbls	(826)			(859)
Production | MBbls	(908)		(6,308)	(5,991)
Estimated proved reserves, ending balance | MBbls	22,276		23,280	30,276
Estimated proved developed reserves: | MBbls	18,344		18,269	21,734
Estimated proved undeveloped reserves: | MBbls	3,932		5,011	8,542
Predecessor | NGLs (MBbls)
Oil and gas properties – United States, proved and unevaluated:
Estimated proved reserves, beginning balance | MBbls	10,629	2,802	6,458	27,817
Revisions of previous estimates | MBbls	(2)		6,352	(20,777)
Extensions, discoveries and other additions | MBbls			2	11
Purchase of producing properties | MBbls				1,808
Sale of reserves | MBbls	(7,417)			0
Production | MBbls	(408)		(2,183)	(2,401)
Estimated proved reserves, ending balance | MBbls	2,802		10,629	6,458
Estimated proved developed reserves: | MBbls	1,515		9,255	4,784
Estimated proved undeveloped reserves: | MBbls	1,287		1,374	1,674
Predecessor | Natural Gas (MMcf)
Oil and gas properties – United States, proved and unevaluated:
Estimated proved reserves, beginning balance | MMcf	117,320	60,533	121,858	493,843
Revisions of previous estimates | MMcf	1,242		24,858	(362,102)
Extensions, discoveries and other additions | MMcf			45	1,499
Purchase of producing properties | MMcf				26,136
Sale of reserves | MMcf	(52,992)			(1,061)
Production | MMcf	(5,037)		(29,441)	(36,457)
Estimated proved reserves, ending balance | MMcf	60,533		117,320	121,858
Estimated proved developed reserves: | MMcf	35,865		90,741	90,262
Estimated proved undeveloped reserves: | MMcf	24,668		26,579	31,596
Predecessor | Oil, Natural Gas and NGLs (MBoe)
Oil and gas properties – United States, proved and unevaluated:
Estimated proved reserves, beginning balance | MMcf	53,462	35,166	57,043	152,520
Revisions of previous estimates | MMcf	935		9,744	(87,945)
Extensions, discoveries and other additions | MMcf			73	1,123
Purchase of producing properties | MMcf				6,849
Sale of reserves | MMcf	(17,075)			(1,036)
Production | MMcf	(2,156)		(13,398)	(14,468)
Estimated proved reserves, ending balance | MMcf	35,166		53,462	57,043
Estimated proved developed reserves: | MMcf	25,836		42,647	41,562
Estimated proved undeveloped reserves: | MMcf	9,330		10,815	15,481

SUPPLEMENTAL INFORMATION ON O98

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED - Summary of Standardized Measure of Discounted Future Net Cash Flows (Details) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2017USD ($)$ / bbl	Mar. 31, 2017$ / bbl$ / Mcf	Mar. 01, 2017$ / bbl$ / Mcf	Dec. 31, 2016USD ($)$ / bbl$ / Mcf	Dec. 31, 2015USD ($)$ / bbl$ / Mcf
Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Future cash inflows					$ 1,264,809
Future production costs					(497,538)
Future development costs					(431,752)
Future income taxes					0
Future net cash flows					335,519
10% annual discount					57,591
Standardized measure of discounted future net cash flows	$ 303,086	$ 393,110			$ 393,110
Proved Reserves Average Prices [Abstract]
Average 12-month oil prices net of differentials (in usd per Bbl) | $ / bbl					50.05	45.40	56.01
Average 12-month natural gas liquids prices net of differentials (in usd per Bbl) | $ / bbl								22.90
Average 12-month gas prices net of differentials (in usd per Mcf) | $ / Mcf						2.24	2.52	2.34
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 period		303,086
Sales and transfers of oil, natural gas and NGLs produced, net of production costs		(164,612)
Changes in price, net of future production costs		66,192
Extensions and discoveries, net of future production and development costs		0
Changes in estimated future development costs, net of development costs incurred during the period		88,111
Revisions of quantity estimates		96,454
Accretion of discount		30,309
Net change in income taxes		0
Purchases of reserves in-place		0
Sales of reserves in-place		0
Changes in production rates due to timing and other		(26,430)
Net change in standardized measure		90,024
Standardized measure at end of period	303,086	393,110
Predecessor
Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Future cash inflows								$ 1,236,097	$ 1,921,329
Future production costs								(480,815)	(651,396)
Future development costs								(638,988)	(679,355)
Future income taxes								0	0
Future net cash flows								116,294	590,578
10% annual discount								109,628	13,259
Standardized measure of discounted future net cash flows	225,922	303,086	$ 603,837	$ 1,418,792				$ 225,922	$ 603,837
Proved Reserves Average Prices [Abstract]
Average 12-month oil prices net of differentials (in usd per Bbl) | $ / bbl								40.15	51.16
Average 12-month natural gas liquids prices net of differentials (in usd per Bbl) | $ / bbl								9.46	16.40
Average 12-month gas prices net of differentials (in usd per Mcf) | $ / Mcf								1.71	2.19
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 period	225,922	$ 303,086	603,837	1,418,792
Sales and transfers of oil, natural gas and NGLs produced, net of production costs	(46,137)		(223,948)	(340,477)
Changes in price, net of future production costs	17,455		(448,861)	(237,747)
Extensions and discoveries, net of future production and development costs	0		5,243	1,573
Changes in estimated future development costs, net of development costs incurred during the period	20,756		54,406	731,115
Revisions of quantity estimates	36,557		139,759	(1,458,652)
Accretion of discount	22,592		60,384	174,456
Net change in income taxes	0		0	325,768
Purchases of reserves in-place	0		0	3,493
Sales of reserves in-place	14,584		0	0
Changes in production rates due to timing and other	11,357		35,102	(14,484)
Net change in standardized measure	77,164		(377,915)	(814,955)
Standardized measure at end of period	$ 303,086		$ 225,922	$ 603,837

SUMMARIZED QUARTERLY FINANCIA99

SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED - Results of Operations by Quarter (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended							10 Months Ended	12 Months Ended
	Mar. 31, 2017	Feb. 28, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Results Of Operations By Quarter [Line Items]
Operating revenue	$ 25,809		$ 76,327	$ 79,525	$ 76,722					$ 250,284
Income (loss) from operations	(258,594)		5,302	2,653	(4,519)					(255,158)
Net income (loss)	$ (259,613)		$ 17,138	$ 1,297	$ (6,461)					$ (247,639)
Basic income (loss) per share (in usd per share)	$ (12.98)		$ 0.86	$ 0.06	$ (0.32)					$ (12.38)
Diluted income (loss) per share (in usd per share)	$ (12.98)		$ 0.86	$ 0.06	$ (0.32)					$ (12.38)
Write-down of oil and gas properties	$ 256,435		$ 0	$ 0	$ 0					$ 256,435
Gain (loss) on Appalachia Properties divestiture	0		0	(132)	27					(105)
Reorganization items	0		0	0	0					0
Other expense	$ 0		$ 369	$ 47	$ 814					1,230
Restructuring fees										739
Other operational expenses										$ 3,359
Predecessor
Results Of Operations By Quarter [Line Items]
Operating revenue		$ 68,922				$ 113,107	$ 94,427	$ 89,319	$ 80,677		$ 377,392	$ 544,649
Income (loss) from operations		209,119				(90,234)	(72,128)	(174,656)	(172,150)		(509,168)	(1,365,323)
Net income (loss)		$ 630,317				$ (116,406)	$ (89,635)	$ (195,761)	$ (188,784)		$ (590,586)	$ (1,090,915)
Basic income (loss) per share (in usd per share)		$ 110.99				$ (20.76)	$ (16.01)	$ (35.05)	$ (33.89)		$ (105.63)	$ (197.45)
Diluted income (loss) per share (in usd per share)		$ 110.99				$ (20.76)	$ (16.01)	$ (35.05)	$ (33.89)		$ (105.63)	$ (197.45)
Write-down of oil and gas properties		$ 0				$ 73,094	$ 36,484	$ 118,649	$ 129,204		$ 357,431	$ 1,362,447
Gain (loss) on Appalachia Properties divestiture		213,453									0	0
Reorganization items		(437,744)				10,947	0	0	0		10,947	0
Other expense		13,336									596	434
Restructuring fees		0				13,424	5,784	9,436	953		29,597	0
Other operational expenses		$ 530				$ 6,187	$ 9,059	$ 27,680	$ 12,527		$ 55,453	$ 2,360

NEW YORK STOCK EXCHANGE COMP100

NEW YORK STOCK EXCHANGE COMPLIANCE (Details) - USD ($)	May 17, 2016	Dec. 31, 2017	Dec. 31, 2016	Jul. 01, 2016
Fresh-Start Adjustment [Line Items]
Stockholders' equity		$ 308,168,000
Predecessor
Fresh-Start Adjustment [Line Items]
NASDAQ listing rules, minimum market value of publicly held shares	$ 50,000,000
NASDAQ listing rules, number of consecutive business days	30 days
Stockholders' equity			$ (637,282,000)	$ 50,000,000