Energy XXI Gulf Coast (EGC) 10-K 21 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Mar. 02, 2018	Jun. 30, 2017
Document and Entity Information
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Entity Registrant Name	Energy XXI Gulf Coast, Inc.
Entity Central Index Key	1,404,973
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 451,144,204
Entity Common Stock, Shares Outstanding		33,268,478

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	$ 151,729	$ 165,368
Accounts receivable, net
Oil and natural gas sales	55,598	69,744
Joint interest billings	6,336	6,029
Other	15,726	17,944
Prepaid expenses and other current assets	21,602	17,980
Restricted cash	6,392	32,337
Total Current Assets	257,383	309,402
Property and Equipment
Oil and natural gas properties, net - full cost method of accounting, including $200.2 million and $376.1 million of unevaluated properties not being amortized at December 31, 2017 and December 31, 2016, respectively	764,922	1,097,471
Other property and equipment, net	10,120	20,007
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	775,042	1,117,478
Other Assets
Restricted cash	25,712	25,583
Other assets	18,845	28,244
Total Other Assets	44,557	53,827
Total Assets	1,076,982	1,480,707
Current Liabilities
Accounts payable	85,122	101,117
Accrued liabilities	45,494	55,675
Asset retirement obligations	51,398	56,601
Derivative financial instruments	32,567
Current maturities of long-term debt	21	4,268
Total Current Liabilities	214,602	217,661
Long-term debt, less current maturities	73,952	74,229
Asset retirement obligations	613,453	680,507
Other liabilities	10,783	12,595
Total Liabilities	912,790	984,992
Commitments and Contingencies (Note 17)
Stockholders' Equity
Common stock, $0.01 par value, 100,000,000 shares authorized and 33,254,963 and 33,211,594 shares issued and outstanding at December 31, 2017 and December 31, 2016, respectively	333	332
Additional paid-in capital	911,144	901,658
Accumulated deficit	(747,285)	(406,275)
Total Stockholders' Equity	164,192	495,715
Total Liabilities and Stockholders' Equity	$ 1,076,982	$ 1,480,707

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Consolidated Balance Sheets
Oil and natural gas properties, net - full cost method of accounting, unevaluated properties not being amortized	$ 200.2	$ 376.1
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	33,254,963	33,211,594
Common stock, shares outstanding	33,254,963	33,211,594

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	Dec. 31, 2016	Dec. 31, 2014	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015
Revenues
Oil sales				$ 113,697	$ 118,484	$ 133,793							$ 252,277			$ 365,974	$ 481,922
Natural gas liquids sales				2,209	2,370	2,227							4,597			6,806	8,542
Natural gas sales				12,261	13,753	18,368							32,121			44,382	53,805
(Loss) Gain on derivative financial instruments				(12,466)	9,412	3,698							13,110			644	(32,625)
Total Revenues				115,701	144,019	158,086							302,105			417,806	511,644
Costs and Expenses
Lease operating				77,822	83,655	77,267							160,922			238,744	319,671
Production taxes				471	482	239							721			1,192	1,355
Gathering and transportation				(2,441)	2,678	11,222							13,900			11,459	21,666
Pipeline facility fee				10,495	10,494	10,494							20,988			31,483	41,977
Depreciation, depletion and amortization				36,131	38,685	41,896							80,581			116,712	150,151
Accretion of asset retirement obligations				9,753	9,984	13,081							23,065			32,818	42,780
Impairment of oil and natural gas properties	$ 406,275		$ 145,100			40,774							40,774			40,774	185,860	$ 406,300
General and administrative expense				15,026	20,716	23,848							42,320			57,346	72,057
Reorganization items													2,244			2,244	2,555
Total Costs and Expenses	406,275			147,257	166,694	218,821							385,515			532,772	838,072
Operating Loss	(406,275)		(211,462)	(31,556)	(22,675)	(60,735)							(83,410)			(114,966)	(326,428)
Other Income (Expense)
Other income, net				52	80	22							102			154	254
Interest expense				(3,653)	(3,642)	(3,834)							(7,476)			(11,129)	(14,836)
Total Other (Expense) Income, net				(3,601)	(3,562)	(3,812)							(7,374)			(10,975)	(14,582)
Loss Before Reorganization Items and Income Taxes	(406,275)																(341,010)
(Loss) Income Before Income Taxes	(406,275)			(35,157)	(26,237)	(64,547)							(90,784)			(125,941)	(341,010)
Income Tax Benefit																	0
Net (Loss) Income	(406,275)		$ (215,069)	$ (35,157)	$ (26,237)	$ (64,547)							$ (90,784)	$ (406,275)		$ (125,941)	(341,010)
Net (Loss) Income Attributable to Common Stockholders	$ (406,275)																$ (341,010)
(Loss) Earnings per Share
Basic (in dollars per share)	$ (12.23)																$ (10.26)
Diluted (in dollars per share)	$ (12.23)																$ (10.26)
Weighted Average Number of Common Shares Outstanding
Basic (in shares)	33,212																33,239
Diluted (in shares)	33,212																33,239
Basic and Diluted (in shares)				33,241	33,237	33,228							33,234			33,236
Predecessor
Revenues
Oil sales														256,050					$ 532,505	$ 1,025,017
Natural gas liquids sales														3,533					14,852	27,714
Natural gas sales														37,103					69,255	117,282
(Loss) Gain on derivative financial instruments																			90,506	235,439
Total Revenues														296,686					707,118	1,405,452
Costs and Expenses
Lease operating														136,578					328,183	449,972
Production taxes														482					1,442	8,385
Gathering and transportation														5,910					33,156	34,707
Pipeline facility fee														20,330					40,659
Depreciation, depletion and amortization														60,202					339,539	705,521
Accretion of asset retirement obligations														38,380					64,708	50,081
Impairment of oil and natural gas properties								$ 77,600	$ 143,100	$ 340,500	$ 1,425,800	$ 904,700		77,781	$ 2,330,500				2,814,028	2,421,884
Goodwill impairment		$ 329,300																		329,293
General and administrative expense														27,557					102,736	116,500
Total Costs and Expenses														367,220					3,724,451	4,116,343
Operating Loss							$ 12,795	(83,329)	(168,119)	(417,866)	(1,513,148)	(918,200)		(70,534)	(2,431,348)				(3,017,333)	(2,710,891)
Other Income (Expense)
Loss from equity method investees																			(10,746)	(17,165)
Other income, net														117					3,596	4,176
Gain on early extinguishment of debt										777,000	290,300	458,300			748,600				1,525,596
Interest expense														(12,580)					(405,658)	(323,308)
Total Other (Expense) Income, net														(12,463)					1,112,788	(336,297)
Loss Before Reorganization Items and Income Taxes														(82,997)					(1,904,545)	(3,047,188)
Reorganization items														2,733,608					(14,201)
(Loss) Income Before Income Taxes														2,650,611	(1,883,924)				(1,918,746)	(3,047,188)
Income Tax Benefit															51				(87)	(613,350)
Net (Loss) Income							2,771,349	(120,738)	(195,460)	160,776	(1,310,583)	(573,392)		2,650,611	(1,883,975)				(1,918,659)	(2,433,838)
Preferred Stock Dividends															5,664				5,194	11,468
Net (Loss) Income Attributable to Common Stockholders							$ 2,771,349	$ (120,738)	$ (192,612)	$ 158,398	$ (1,313,393)	$ (576,246)		$ 2,650,611	$ (1,889,639)				$ (1,923,853)	$ (2,445,306)
(Loss) Earnings per Share
Basic (in dollars per share)							$ 28.04	$ (1.23)	$ (1.97)	$ 1.65	$ (13.81)	$ (6.08)		$ 26.95	$ (19.91)				$ (20.08)	$ (25.97)
Diluted (in dollars per share)							$ 26.45	$ (1.23)	$ (1.97)	$ 1.55	$ (13.81)	$ (6.08)		$ 25.30	$ (19.91)				$ (20.08)	$ (25.97)
Weighted Average Number of Common Shares Outstanding
Basic (in shares)														98,337	94,926				95,822	94,167
Diluted (in shares)														104,787	94,926				95,822	94,167

Consolidated Statements of Stoc

Consolidated Statements of Stockholders’ Equity (Deficit) Predeccesor - USD ($) $ in Thousands	Preferred Stock5.625% Convertible Perpetual Preferred Stock	Common Stock	Paid-in Capital	Accumulated (Deficit)	Total
Beginning Balance (Predecessor) at Jun. 30, 2014	$ 1	$ 468	$ 1,837,462	$ (103,371)	$ 1,734,560
Beginning Balance (in shares) (Predecessor) at Jun. 30, 2014		93,720,000
Increase (Decrease) in Stockholders' Equity
Common stock issued, net of direct costs | Predecessor		$ 4	2,332		2,336
Common stock issued (in shares) | Predecessor		923,000
Common stock based compensation | Predecessor			4,124		4,124
Common stock dividends | Predecessor				(24,436)	(24,436)
Preferred stock dividends | Predecessor				(11,468)	(11,468)
Net (Loss) Income | Predecessor				(2,433,838)	(2,433,838)
Ending Balance (Predecessor) at Jun. 30, 2015	1	$ 472	1,843,918	(2,573,113)	(728,722)
Ending Balance (in shares) (Predecessor) at Jun. 30, 2015		94,643,000
Increase (Decrease) in Stockholders' Equity
Common stock issued, net of direct costs | Predecessor		$ 16	430		446
Common stock issued (in shares) | Predecessor		3,181,000
Common stock based compensation | Predecessor			1,336		1,336
Preferred stock dividends | Predecessor				(5,194)	(5,194)
Revision to prior period financials | Predecessor				92	92
Net (Loss) Income before revision to prior period financials | Predecessor				(1,918,751)	(1,918,751)
Net (Loss) Income | Predecessor					(1,918,659)
Ending Balance (Predecessor) at Jun. 30, 2016	1	$ 488	1,845,684	(4,496,966)	(2,650,793)
Ending Balance (in shares) (Predecessor) at Jun. 30, 2016		97,824,000
Increase (Decrease) in Stockholders' Equity
Common stock issued, net of direct costs | Predecessor		$ 16	(16)
Common stock issued, net of direct costs		$ 332	872,230		872,562
Common stock issued (in shares) | Predecessor		3,146,000
Common stock issued (in shares)		33,212,000
Common stock based compensation | Predecessor			183		183
Revision to prior period financials | Predecessor				(3,292)	(3,292)
Revision to prior period financials			21,372		21,372
Net (Loss) Income before revision to prior period financials | Predecessor				2,653,903	2,653,903
Net (Loss) Income | Predecessor					2,650,611
Net (Loss) Income				(406,275)	(406,275)
Cancellation of Predecessor equity | Predecessor	(1)	$ (504)	(1,845,851)	1,846,355	(1)
Ending Balance (Predecessor before cancellation of Predecessor equity) at Dec. 31, 2016	$ 1	504	1,845,851	(1,846,355)	1
Ending Balance at Dec. 31, 2016		$ 332	901,658	(406,275)	$ 495,715
Ending Balance (in shares) (Predecessor) at Dec. 31, 2016		100,970,000
Ending Balance (in shares) (Predecessor before cancellation of Predecessor equity) at Dec. 31, 2016		100,970,000
Ending Balance (in shares) at Dec. 31, 2016		33,212,000			33,211,594
Increase (Decrease) in Stockholders' Equity
Common stock issued, net of direct costs		$ 1			$ 1
Common stock issued (in shares)		43,000
Common stock based compensation			9,486		9,486
Net (Loss) Income				(341,010)	(341,010)
Ending Balance at Dec. 31, 2017		$ 333	$ 911,144	$ (747,285)	$ 164,192
Ending Balance (in shares) at Dec. 31, 2017		33,255,000			33,254,963

Consolidated Statements of Sto6

Consolidated Statements of Stockholders’ Equity (Deficit) Predecessor (Parenthetical) - Predecessor - Preferred Stock	6 Months Ended	12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
5.625% Convertible Perpetual Preferred Stock
Preferred stock dividend rate (as a percent)	5.625%	5.625%	5.625%	5.625%
7.25% Convertible Perpetual Preferred Stock
Preferred stock dividend rate (as a percent)		7.25%	7.25%	7.25%

Consolidated Statements of Sto7

Consolidated Statements of Stockholders’ Equity (Deficit) Successor - USD ($) $ in Thousands	Common Stock	Paid-in Capital	Accumulated (Deficit)	Total
Increase (Decrease) in Stockholders' Equity
Common stock issued, net of direct costs	$ 332	$ 872,230		$ 872,562
Common stock issued (in shares)	33,212,000
Successor common stock warrants		8,056		8,056
Revision to prior period financials		21,372		21,372
Net (Loss) Income			$ (406,275)	(406,275)
Ending Balance at Dec. 31, 2016	$ 332	901,658	(406,275)	$ 495,715
Ending Balance (in shares) at Dec. 31, 2016	33,212,000			33,211,594
Increase (Decrease) in Stockholders' Equity
Common stock issued, net of direct costs	$ 1			$ 1
Common stock issued (in shares)	43,000
Common stock based compensation		9,486		9,486
Net (Loss) Income			(341,010)	(341,010)
Ending Balance at Dec. 31, 2017	$ 333	$ 911,144	$ (747,285)	$ 164,192
Ending Balance (in shares) at Dec. 31, 2017	33,255,000			33,254,963

Consolidated Statements of Cash

Consolidated Statements of Cash Flows $ in Thousands	12 Months Ended
	Jun. 30, 2015USD ($)
Predecessor
Cash Flows From Operating Activities
Net (loss) income	$ (2,433,838)
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	705,521
Impairment of oil and natural gas properties	2,421,884
Goodwill impairment	329,293
Deferred income tax benefit	(614,383)
Change in fair value of derivative financial instruments	(52,036)
Accretion of asset retirement obligations	50,081
Loss from equity method investees	17,165
Amortization and write-off of debt issuance costs, payment of interest in kind and other	23,247
Stock-based compensation	4,124
Changes in operating assets and liabilities
Accounts receivable	51,284
Prepaid expenses and other assets	48,062
Settlement of asset retirement obligations	(106,573)
Accounts payable and accrued liabilities	(113,078)
Net Cash Provided by (Used in) Operating Activities	330,753
Cash Flows from Investing Activities
Acquisitions, net of cash	(301)
Capital expenditures	(723,829)
Insurance payments received	3,920
Change in equity method investments	12,642
Change in restricted cash	(14,676)
Proceeds from the sale of properties	261,931
Other	(135)
Net Cash (Used in) Provided by Investing Activities	(460,448)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs	2,336
Dividends to shareholders - common	(24,436)
Dividends to shareholders - preferred	(11,468)
Cash restricted under revolving credit facility related to property sold	(21,000)
Proceeds from long-term debt	2,586,572
Payments on long-term debt	(1,747,849)
Debt issuance costs	(43,352)
Other	(66)
Net Cash (Used in) Provided by Financing Activities	740,737
Net (Decrease) Increase in Cash and Cash Equivalents	611,042
Cash and Cash Equivalents, beginning of period	145,806
Cash and Cash Equivalents, end of period	$ 756,848

Organization

Organization	12 Months Ended
	Dec. 31, 2017
Organization
Organization	ENERGY XXI GULF COAST, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1 — Organization Nature of Operations Energy XXI Gulf Coast, Inc. (“EGC”), a Delaware corporation, was incorporated on February 7, 2006. Prior to emergence from the Chapter 11 Cases (as defined below), EGC was an indirect wholly owned operating subsidiary of Energy XXI Ltd (“EXXI Ltd” or the “Predecessor”). We are headquartered in Houston, Texas and have historically engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the Gulf of Mexico Shelf (“GoM Shelf”), which is an area in less than 1,000 feet of water. Emergence from Chapter 11 On April 14, 2016, EXXI Ltd, an exempt company incorporated under the laws of Bermuda and predecessor of EGC, EPL Oil & Gas, Inc. (“EPL”), an indirect wholly-owned subsidiary of EXXI Ltd and certain other indirect wholly-owned subsidiaries of EXXI Ltd filed voluntary petitions for reorganization in the Bankruptcy Court seeking relief under the provisions of Chapter 11 (the “Chapter 11 Cases”). On December 13, 2016, the Bankruptcy Court entered the Confirmation Order and on December 30, 2016, the Debtors emerged from bankruptcy. On the Emergence Date, the Debtors satisfied the conditions to effectiveness, the Plan became effective in accordance with its terms and the Debtors emerged from Chapter 11 Cases. In connection therewith, EXXI Ltd and its subsidiaries completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to EGC, as the new parent entity. Accordingly, EGC succeeded to the entire business and operations previously consolidated for accounting purposes by EXXI Ltd. In accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”), EGC applied fresh start accounting upon the Predecessor’s emergence from bankruptcy and it evaluated transaction activity between the Emergence Date and December 31, 2016 and concluded that an accounting convenience date of December 31, 2016 (the “Convenience Date”) was appropriate. The Chapter 11 proceedings and related matters are addressed in Note 3, “Chapter 11 Proceedings.”

Revision of Prior Period Financ

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements	12 Months Ended
	Dec. 31, 2017
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements	Note 2 — Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements Revision of Prior Period Financial Statements During the following periods, we identified prior period pre-tax adjustments affecting the statements of operations: Year ended June 30, 2016. Preferred stock dividends were decreased by $3.2 million to reverse the previously accrued but not declared preferred stock dividend. Six Months Ended December 31, 2016. · Oil sales were increased by $1.0 million to reflect revenue associated with pipeline tariffs. · Impairment of oil and natural gas properties was decreased by $9.0 million, resulting from the reduction of asset retirement obligations and related oil and natural gas property balances of the same amount. As we were in a ceiling test impairment position at September 30, 2016, all adjustments to our asset retirement obligations through September 30, 2016 directly impacted the statement of operations for the six months ended December 31, 2016. · Reorganization items were decreased by $ 14.8 million, which is the net impact of adjustments on fresh-start accounting as of the Convenience Date. At December 31, 2016, the cumulative amount of all statement of operations adjustments for both the year ended June 30, 2016 and six months ended December 31, 2016, was $21.4 million. This amount was offset by reorganization and fresh start accounting adjustments for the Predecessor and was an adjustment to Successor’s opening equity. In evaluating whether the previously issued financial statements were materially misstated, the Company applied the guidance in Securities and Exchange Commission (“SEC”) Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements . SAB No. 108 states that registrants must quantify the impact of correcting all misstatements, including both the carryover (iron curtain method) and reversing (rollover method) effects of prior-year misstatements on the current-year consolidated financial statements, and evaluate the misstatements measured under each method in light of quantitative and qualitative factors. Under SAB No. 108, prior-year misstatements which, if corrected in the current year would be material to the current year, must be corrected by adjusting prior year financial statements, even though such correction previously was and continues to be immaterial to the prior-year financial statements. Correcting prior-year financial statements for such “immaterial misstatements” does not require previously filed reports to be amended. In accordance with accounting guidance presented in ASC 250-10 (SEC Staff Accounting Bulletin No. 99, Materiality), the Company assessed the materiality of the misstatements and concluded that they were not material to any of the Predecessor Company’s previously issued consolidated financial statements. The correction of immaterial misstatements did not have any impact on previously reported oil and natural gas reserve volumes and where applicable, the corrections have been reflected throughout the accompanying notes to the consolidated financial statements. These adjustments impacted the consolidated balance sheet as of December 31, 2016 as follows (in thousands): Successor As of December 31, 2016 As reported Adjustments As Revised ASSETS Current Assets Cash and cash equivalents $ 165,368 $ — $ 165,368 Accounts receivable, net Oil and natural gas sales 68,143 1,601 69,744 Joint interest billings 5,600 429 6,029 Other 17,944 — 17,944 Prepaid expenses and other current assets 25,957 (7,977) 17,980 Restricted cash 32,337 — 32,337 Total Current Assets 315,349 (5,947) 309,402 Property and Equipment Oil and natural gas properties, net 1,097,479 (8) 1,097,471 Other property and equipment, net 18,807 1,200 20,007 Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment 1,116,286 1,192 1,117,478 Other Assets Restricted cash 25,583 — 25,583 Other assets and debt issuance costs, net of accumulated amortization 28,244 — 28,244 Total Other Assets 53,827 — 53,827 Total Assets $ 1,485,462 $ (4,755) $ 1,480,707 LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) Current Liabilities Accounts payable $ 101,117 $ — $ 101,117 Accrued liabilities 63,660 (7,985) 55,675 Asset retirement obligations 56,601 — 56,601 Current maturities of long-term debt 4,268 — 4,268 Total Current Liabilities 225,646 (7,985) 217,661 Long-term debt, less current maturities 74,229 — 74,229 Asset retirement obligations 696,763 (16,256) 680,507 Other liabilities 14,481 (1,886) 12,595 Total Liabilities 1,011,119 (26,127) 984,992 Stockholders’ Equity Preferred stock — — — Common stock 332 — 332 Additional paid-in capital 880,286 21,372 901,658 Accumulated deficit (406,275) — (406,275) Total Stockholders’ Equity 474,343 21,372 495,715 Total Liabilities and Stockholders’ Equity $ 1,485,462 $ (4,755) $ 1,480,707 These adjustments impacted the consolidated statement of operations for the six months ended December 31, 2016 as follows (in thousands): Predecessor Six Months Ended December 31, 2016 As reported Adjustments As Revised Revenues Oil sales $ 255,040 $ 1,010 $ 256,050 Natural gas liquids sales 3,533 — 3,533 Natural gas sales 37,103 — 37,103 Total Revenues 295,676 1,010 296,686 Costs and Expenses Lease operating 137,007 (429) 136,578 Production taxes 482 — 482 Gathering and transportation 5,910 — 5,910 Pipeline facility fee 20,330 — 20,330 Depreciation, depletion and amortization 60,626 (424) 60,202 Accretion of asset retirement obligations 38,973 (593) 38,380 Impairment of oil and natural gas properties 86,820 (9,039) 77,781 General and administrative expense 27,557 — 27,557 Total Costs and Expenses 377,705 (10,485) 367,220 Operating Loss (82,029) 11,495 (70,534) Other Income (Expense) Other income, net 117 — 117 Interest expense (12,580) — (12,580) Total Other Expense, net (12,463) — (12,463) Loss Before Reorganization Items and Income Taxes (94,492) 11,495 (82,997) Reorganization items 2,748,395 (14,787) 2,733,608 Loss Before Income Taxes 2,653,903 (3,292) 2,650,611 Income Tax Expense — — — Net Income $ 2,653,903 $ (3,292) $ 2,650,611 Earnings per Share Basic $ 26.99 $ (0.04) $ 26.95 Diluted $ 25.33 $ (0.03) $ 25.30 Weighted Average Number of Common Shares Outstanding Basic 98,337 98,337 98,337 Diluted 104,787 104,787 104,787 These adjustments impacted the consolidated statement of cash flows for the six months ended December 31, 2016 as follows (in thousands): Predecessor Six Months Ended December 31, 2016 As reported Adjustments As Revised Cash Flows From Operating Activities Net income $ 2,653,903 $ (3,292) $ 2,650,611 Adjustments to reconcile net income to net cash used in operating activities: Depreciation, depletion and amortization 60,626 (424) 60,202 Impairment of oil and natural gas properties 86,820 (9,039) 77,781 Accretion of asset retirement obligations 38,973 (593) 38,380 Reorganization items (2,838,963) 14,787 (2,824,176) Amortization and write-off of debt issuance costs, payment of interest in kind and other 5,025 — 5,025 Deferred rent 3,355 — 3,355 Stock-based compensation 183 — 183 Changes in operating assets and liabilities Accounts receivable (16,545) (1,010) (17,555) Prepaid expenses and other assets (7,425) — (7,425) Change in restricted cash (25,157) — (25,157) Settlement of asset retirement obligations (18,852) — (18,852) Accounts payable and accrued liabilities 40,584 (429) 40,155 Net Cash Used in Operating Activities (17,473) — (17,473) Cash Flows from Investing Activities Capital expenditures (20,237) — (20,237) Change in restricted cash 31,748 — 31,748 Other 195 — 195 Net Cash Provided by Investing Activities 11,706 — 11,706 Cash Flows from Financing Activities Payments on long-term debt (32,088) — (32,088) Other (35) — (35) Net Cash Used in Financing Activities (32,123) — (32,123) Net Decrease in Cash and Cash Equivalents (37,890) — (37,890) Cash and Cash Equivalents, beginning of period 203,258 203,258 Cash and Cash Equivalents, end of period $ 165,368 $ $ — $ 165,368 These adjustments impacted the consolidated statement of operations for the year ended June 30, 2016 as follows (in thousands): Predecessor Year Ended June 30, 2016 As reported Adjustments As Revised Revenues Oil sales $ 531,914 $ 591 $ 532,505 Natural gas liquids sales 14,852 — 14,852 Natural gas sales 69,255 — 69,255 Gain on derivative financial instruments 90,506 — 90,506 Total Revenues 706,527 591 707,118 Costs and Expenses Lease operating 328,183 — 328,183 Production taxes 1,442 — 1,442 Gathering and transportation 33,156 — 33,156 Pipeline facility fee 40,659 — 40,659 Depreciation, depletion and amortization 339,516 23 339,539 Accretion of asset retirement obligations 64,690 18 64,708 Impairment of oil and natural gas properties 2,813,570 458 2,814,028 General and administrative expense 102,736 — 102,736 Total Costs and Expenses 3,723,952 499 3,724,451 Operating Loss (3,017,425) 92 (3,017,333) Other (Expense) Income Loss from equity method investees (10,746) — (10,746) Other income, net 3,596 — 3,596 Gain on early extinguishment of debt 1,525,596 — 1,525,596 Interest expense (405,658) — (405,658) Total Other Income, net 1,112,788 — 1,112,788 Loss Before Reorganization Items and Income Taxes (1,904,637) 92 (1,904,545) Reorganization items (14,201) — (14,201) Loss Before Income Taxes (1,918,838) 92 (1,918,746) Income Tax Benefit (87) — (87) Net Loss (1,918,751) 92 (1,918,659) Preferred Stock Dividends 8,394 (3,200) 5,194 Net Loss Attributable to Common Stockholders $ (1,927,145) $ 3,292 $ (1,923,853) Loss per Share Basic and Diluted $ (20.11) $ 0.03 $ (20.08) Weighted Average Number of Common Shares Outstanding Basic and Diluted 95,822 95,822 95,822 These adjustments impacted the consolidated statement of cash flows for the year ended June 30, 2016 as follows (in thousands): Predecessor Year Ended June 30, 2016 As reported Adjustments As Revised Cash Flows From Operating Activities Net loss $ (1,918,751) $ 92 $ (1,918,659) Adjustments to reconcile net loss to net cash (used in) provided by operating activities: Depreciation, depletion and amortization 339,516 23 339,539 Impairment of oil and natural gas properties 2,813,570 458 2,814,028 Change in fair value of derivative financial instruments 19,163 — 19,163 Accretion of asset retirement obligations 64,690 18 64,708 Loss from equity method investees 10,746 — 10,746 Gain on early extinguishment of debt (1,525,596) — (1,525,596) Amortization and write-off of debt issuance costs, payment of interest in kind and other 138,473 — 138,473 Deferred rent 9,154 — 9,154 Provision for loss on accounts receivable 3,200 — 3,200 Stock-based compensation 1,336 — 1,336 Changes in operating assets and liabilities Accounts receivable 42,742 (591) 42,151 Prepaid expenses and other assets (24,438) — (24,438) Change in restricted cash — — — Settlement of asset retirement obligations (78,273) — (78,273) Accounts payable and accrued liabilities (62,187) — (62,187) Net Cash Used in Operating Activities (166,655) — (166,655) Cash Flows from Investing Activities Acquisitions, net of cash (2,797) — (2,797) Capital expenditures (111,884) — (111,884) Insurance payments received 8,251 — 8,251 Change in restricted cash (22,136) — (22,136) Proceeds from the sale of properties 5,693 — 5,693 Other (40) — (40) Net Cash Used in Investing Activities (122,913) — (122,913) Cash Flows from Financing Activities Proceeds from the issuance of common and preferred stock, net of offering costs 334 — 334 Dividends to shareholders – preferred (5,673) — (5,673) Proceeds from long-term debt 1,121 — 1,121 Payments on long-term debt (227,884) — (227,884) Payment of debt assumed in acquisition (25,187) — (25,187) Fees related to debt extinguishment (3,526) — (3,526) Debt issuance costs (2,163) — (2,163) Other (1,044) — (1,044) Net Cash Used in Financing Activities (264,022) — (264,022) Net Decrease in Cash and Cash Equivalents (553,590) — (553,590) Cash and Cash Equivalents, beginning of period 756,848 756,848 Cash and Cash Equivalents, end of period $ 203,258 $ $ — $ 203,258 Summary of Significant Accounting Policies Principles of Consolidation and Reporting. The accompanying consolidated financial statements on December 31, 2017 include the accounts of EGC and its wholly-owned subsidiaries and for the prior periods, the accompanying consolidated financial statements include the accounts of EXXI Ltd and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. The Predecessor’s consolidated financial statements for the prior periods include certain reclassifications, including a $ 6.7 million, $ 17.9 million and $1 3.6 million reclassification from lease operating expenses to gathering and transportation expenses and a $ 21.0 million, $40.7 million and $0.0 million reclassification from gathering and transportation expenses to pipeline facility fee expense for the six month period ended December 31, 2016 and for the years ended June 30, 2016 and 2015, respectively, to conform to the current presentation. Those reclassifications did not have any impact on the Predecessor’s previously reported consolidated result of operations or cash flows. For periods subsequent to filing the Bankruptcy Petitions until the Emergence Date, we have prepared the Predecessor’s consolidated financial statements in accordance with ASC 852. 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. Fresh-start Accounting. Upon emergence from bankruptcy, in accordance with ASC 852 related to fresh-start accounting, EGC became a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Convenience Date. The effects of the Plan and the application of fresh-start accounting were reflected in our consolidated balance sheet as of December 31, 2016 and the related adjustments thereto were recorded in the consolidated statement of operations of the Predecessor as reorganization items during the six month transition period ended December 31, 2016. Accordingly, EGC’s consolidated financial statements as of and subsequent to December 31, 2016 are not and will not be comparable to the Predecessor consolidated financial statements prior to the Convenience Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented as of December 31, 2017 and prior periods. Although our accounting policies are the same as that of our Predecessor’s, our financial results for future periods following the application of fresh-start accounting will be different from historical trends, and the differences may be material. Use of Estimates. The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. The Predecessor’s proved reserves quantities of 86.6 MMBOE as of June 30, 2016 were estimated and compiled by its internal reservoir engineers and audited by Netherland, Sewell & Associates, Inc., independent oil and gas consultants (“NSAI”). As of December 31, 2016, proved reserves quantities of 121.9 MMBOE were independently estimated and compiled by our internal reservoir engineers. Pursuant to the terms of our Exit Facility, a third party engineer report is required annually, with the first report due by May 31, 2017 and we engaged NSAI to provide that report. The first NSAI report was delivered by us on May 23, 2017, and NSAI estimated our proved reserves quantities of 109.4 MMBOE as of March 31, 2017 in accordance with the guidelines established by the SEC. As of December 31, 2017, proved reserves quantities of 88.2 MMBOE were estimated by NSAI. The estimated proved reserve quantities discussed above are unaudited. Other items subject to estimates and assumptions include fair value estimates used in fresh start accounting; accounting for acquisitions and dispositions; carrying amounts of property, plant and equipment; asset retirement obligations; deferred income taxes; valuation of derivative financial instruments; reorganization items and liabilities subject to compromise, among others. Accordingly, our accounting estimates require the exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material. Cash and Cash Equivalents. We consider all highly liquid investments, with maturities of 90 days or less when purchased, to be cash and cash equivalents. As of December 31, 2017, cash and cash equivalents include $25.1 million in a money market account. The fair value estimate of money market funds was based on net asset value obtained from quoted prices in active markets and thus represents a Level 1 measurement. Restricted Cash . We maintain restricted escrow funds in trusts as required by certain contractual arrangements and disposition transactions. Amounts on deposit in trust accounts are reflected in restricted cash on our consolidated balance sheets. As of December 31, 2017 and 2016, restricted cash includes $6 million in a money market account. The fair value estimate of money market funds was based on net asset value obtained from quoted prices in active markets and thus represents a Level 1 measurement. Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are stated at historical carrying amount net of allowance for doubtful accounts. We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, primarily using the specific identification method. As of December 31, 2017, our allowance for doubtful accounts was $ 0.6 million. As of December 31, 2016, no allowance for doubtful accounts was necessary. Oil and Natural Gas Properties . We use the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless accounting for the sale as a reduction of capitalized costs would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Costs excluded from depletion or amortization represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs associated with unevaluated properties, all of which were recorded as part of fresh start accounting, are transferred to evaluated properties either (i) ratably over a period of the related field’s life, or (ii) upon determination as to whether there are any proved reserves related to the unevaluated properties or the costs are impaired or capital costs associated with the development of these properties will not be available. We evaluate the impairment of our evaluated oil and natural gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4‑10. Estimated future production volumes from oil and natural gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and natural gas reserves could be subject to revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict. For the year ended December 31, 2017, we recorded an impairment to oil and natural gas properties of $185.9 million due to the decrease in proved reserves and PV‑10 value. On December 31, 2016, the Company, subsequent to its emergence from bankruptcy, recorded an impairment of its oil and natural gas properties of approximately $406.3 million due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4‑10. The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12‑month average oil and natural gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting. For the six-month period ended December 31, 2016 and for the years ended June 30, 2016 and 2015, the Predecessor recorded an impairment to its oil and natural gas properties of $77.8 million, $2,814.0 million and $2,421.9 million, respectively. Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE (unaudited) at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million (unaudited). As of December 31, 2017, we have 22 MMBOE (unaudited) in proved undeveloped reserves. Future development costs associated with our proved undeveloped reserves at December 31, 2017 totaled approximately $356.1 million (unaudited). As scheduled in our long range plan, all of our proved undeveloped locations are expected to be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report. Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, amortization and impairment, estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves. Other Property and Equipment. Other property and equipment include buildings, data processing and telecommunications equipment, office furniture and equipment, vehicle and leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, which ranges from three to five years. Repairs and maintenance costs are expensed in the period incurred. Goodwill. Goodwill has an indefinite useful life and is not amortized, but rather is tested for impairment at least annually during the third quarter, unless events occur or circumstances change between annual tests that would more likely than not reduce the fair value of a related reporting unit below its carrying value. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. Goodwill arose in the year ended June 30, 2014 in connection with the acquisition of EPL and was recorded to our oil and gas reporting unit. At December 31, 2014, we conducted a qualitative goodwill impairment assessment and after assessing the relevant events and circumstances, we determined that performing a quantitative goodwill impairment test was necessary. Therefore, we performed steps one and two of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. See Note 6 – “Goodwill” for more information. Derivative Instruments . We have historically used various derivative instruments including crude oil and natural gas put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Any premiums paid or financed on derivative financial instruments are recorded as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or financed. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statements of operations. Debt Issuance Costs. Costs incurred in connection with the issuance of long-term debt are presented in the consolidated balance sheet as a direct deduction from the carrying amount of that debt liability and are amortized to interest expense generally over the scheduled maturity of the debt utilizing the interest method. Costs incurred in connection with line-of-credit agreements are presented as an asset and subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings under the line-of-credit arrangement. Asset Retirement Obligations . Our investment in oil and natural gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. The present value of the future costs are added to the capitalized cost of our oil and natural gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and natural gas properties that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in abandonment timing, regulatory requirements, technological advances and other factors which may be difficult to predict. Revenue Recognition. We recognize oil and natural gas revenue when the product is delivered at the contracted sales price, title is transferred and collectability is reasonably assured. The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. The amounts of imbalances were not material at December 31, 2017 and 2016. General and Administrative Expense . Under the full cost method of accounting, the portion of our general and administrative expense that is directly identified with our exploration and development activities is capitalized as part of our oil and natural gas properties. These capitalized costs include salaries, employee benefits, costs of consulting services, and other direct costs incurred to support those employees directly involved in exploration and development activities. The capitalized costs do not include costs related to production operations, general corporate overhead or similar activities. Our capitalized general and administrative expense directly related to our exploration and development activities for the year ended December 31, 2017, for the six month transition period ended December 31, 2016 and for the years ended June 30, 2016 and 2015 was $ 16.4 million $7.8 million, $17.0 million and $49.2 million, respectively. Share-Based Compensation. Compensation cost for equity awards is based on the fair value of the equity instrument which equals the market value of the underlying stock on the date of grant and is recognized over the period during which an independent director or employee is required to provide service in exchange for the award. Compensation cost for liability awards is based on the fair value of the vested award at the end of each reporting period. Income Taxes . Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties and derivative instruments for financial reporting purposes and income tax purposes. For periods ending up through and including the year ended December 31, 2017 we used the then-current U.S. Federal statutory rate of 35% for measuring these deferred tax assets and liabilities, as adjusted for any applicable state taxes. As a result of the Tax Cuts and Jobs Act of 2017, we re-measured these temporary differences at the new U.S. Federal corporate income tax rate of 21% at December 31, 2017. This resulted in a decrease to our tax-effected deferred tax assets of $204 million, and a corresponding reduction of our valuation allowance of $ 204 million. There was no net effect on income tax expense or benefit recorded for the year ended December 31, 2017 as a result of the Tax Cuts and Jobs Act of 2017. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through Depreciation, Depletion and Amortization (“DD&A”). However, due to changes contained in the Tax Cuts and Jobs Act of 2017, we are now afforded an annual election for equipment purchases after September 27, 2017 through December 31, 2022 that allows us to immediately claim tax deductions for 100% the cost of this property. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Tax Code that allow capitalization or expensing of intangible drilling and tangible property costs where management deems appropriate. On the Emergence Date, the Predecessor Company engaged in several internal restructuring transactions that: (i) assigned all of Predecessor’s assets (directly or indirectly) to EGC, and (ii) separated EXXI Ltd, Energy XXI (US Holdings) Limited (Bermuda), Energy XXI, Inc., and Energy XXI USA from EGC. This had the effect, among other things, of isolating the original parent-level equity ownership and certain intercompany loans (the “Inte

Chapter 11 Proceedings

Chapter 11 Proceedings	12 Months Ended
	Dec. 31, 2017
Chapter 11 Proceedings
Chapter 11 Proceedings	Note 3 – Chapter 11 Proceedings On April 14, 2016, EXXI Ltd, EGC, EPL and certain other subsidiaries of EXXI Ltd (together with Energy XXI Ltd, the “Debtors”) (excluding Energy XXI GIGS Services, LLC, which leases a subsea pipeline gathering system located in the shallow GoM Shelf and storage and onshore processing facilities on Grand Isle, Louisiana, Energy XXI Insurance Limited through which certain insurance coverage for its operations is obtained by the Company, Energy XXI (US Holdings) Limited, Energy XXI International Limited, Energy XXI Malaysia Limited and Energy XXI M21K, LLC, (together, the “Non-Debtors”)) filed voluntary Bankruptcy Petitions in the Bankruptcy Court seeking relief under the provisions of chapter 11 of Title 11 of the United States Bankruptcy Code. The Debtors’ Chapter 11 Cases were jointly administered under the caption “In re: Energy XXI Ltd, et al., Case No. 16‑31928.” Thereafter until emergence, the Debtors operated their businesses and managed their assets as debtors-in-possession under the jurisdiction of the Bankruptcy Court in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. As a result of filing the Bankruptcy Petitions, EXXI Ltd’s common stock was delisted from the Nasdaq Global Select Market (the “NASDAQ”) and on May 19, 2016, its registration under Section 12(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) was withdrawn. As a result, EXXI Ltd’s common stock was deemed registered pursuant to Section 12(g) of the Exchange Act pursuant to Exchange Act Rule 12g‑2(b). Concurrently with the filing of the Bankruptcy Petitions, EXXI Ltd filed a petition seeking an order for liquidation of EXXI Ltd in the Bermuda Court. On April 15, 2016, John C. McKenna was appointed as Provisional Liquidator by the Bermuda Court. In light of the Plan and the emergence of EXXI Ltd, the Bermuda Court granted the entry into a winding up order formally placing EXXI Ltd in liquidation and confirming John C. McKenna as Provisional Liquidator. The Bermuda Proceeding was completed on June 29, 2017. During the pendency of the Bermuda Proceeding, EXXI Ltd has adopted a modified reporting program with respect to its reporting obligations under federal securities laws. EXXI Ltd did not file periodic reports while the Bermuda Proceeding was pending, but continued to file current reports on Form 8‑K as required by federal securities laws. On July 15, 2016, the Bankruptcy Court entered the Order (A) Approving the Disclosure Statement and the Form and Manner of Service Related Thereto, (B) Setting Dates for the Objection Deadline and Hearing Relating to Confirmation of the Plan and (C) Granting Related Relief . On July 18, 2016, the Debtors filed the solicitation version of the Debtors’ Third Amended Disclosure Statement (as amended, modified, or supplemented from time to time, the “Disclosure Statement”). On November 21, 2016, the Debtors filed the Second Amended Proposed Joint Chapter 11 Plan of Reorganization and the solicitation version of the Second Supplement to the Disclosure Statement Setting Forth Modifications to the Plan. On November 21, 2016, the Bankruptcy Court entered the Order (A) Approving the Adequacy of the Disclosure Statement Supplement to the Debtors’ Third Amended Disclosure Statement Setting Forth Modifications to the Debtors’ Plan and the Continued Solicitation of the Plan and (B) Granting Related Relief approving updated solicitation and tabulation procedures with respect to the Plan. On December 13, 2016, the Bankruptcy Court entered the Confirmation Order pursuant to the Bankruptcy Code, which approved and confirmed the Plan as modified by the Confirmation Order. On December 30, 2016, the Debtors satisfied the conditions to effectiveness, the Plan became effective in accordance with its terms and the Company and the other Reorganized Debtors emerged from Chapter 11 Cases. In connection with the satisfaction of the conditions to effectiveness as set forth in the Confirmation Order and in the Plan, EXXI Ltd and its subsidiaries completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to EGC, as the new parent entity (the “Company”). Accordingly, EGC succeeded to the entire business and operations previously consolidated for accounting purposes by EXXI Ltd. Upon emergence from the Chapter 11 Cases, the Company adopted fresh start accounting in accordance with the provisions set forth in ASC 852, because (i) the holders of existing voting shares of EXXI Ltd prior to its emergence received less than 50% of the voting shares of EGC outstanding following its emergence from bankruptcy and (ii) the reorganization value of EXXI Ltd’s assets immediately prior to confirmation of the Plan was less than its post-petition liabilities and allowed claims. Under ASC 852, the Company is considered a new legal entity for accounting purposes. For reporting purposes, the pre-reorganization predecessor reflects the business that was transferred to EGC. The financial statements of the pre-reorganization predecessor are EXXI Ltd’s consolidated financial statements. On January 6, 2017, the Company filed a Current Report on Form 8‑K as the initial report of the Company to the SEC and as notice that the Company is the successor issuer to EXXI Ltd under Rule 12g‑3 under the Exchange Act. As a result, the shares of common stock of the Company, par value $0.01 per share, are deemed to be registered under Section 12(g) of the Exchange Act. The Company is thereby deemed subject to the informational requirements of the Exchange Act, and the rules and regulations promulgated thereunder, and in accordance therewith will file reports and other information with the Commission. On February 7, 2017, the board of directors of the Company (the “Board”) adopted a resolution to change the Company’s fiscal year end from June 30 to December 31. Unless otherwise noted, all references to “years” in this Form 10‑K refer to the twelve-month fiscal year, which, prior to July 1, 2016 ended on June 30, and, beginning after June 30, 2016, ends on December 31. Our common stock began trading on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “EXXI” at the opening of business on February 28, 2017. The audited financial statements of the Successor on December 31, 2016 reflected an impairment of our oil and natural gas properties of approximately $406.3 million which was recognized due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4‑10. The most significant difference related to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12‑month average oil and gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting. Plan of Reorganization In accordance with the Plan, the following significant transactions occurred: Prepetition Notes In accordance with the Plan, on the Emergence Date, all outstanding obligations under the following notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled: · 11.0% senior secured second lien notes due March 15, 2020 (the “Second Lien Notes”) issued pursuant to that certain Indenture, dated as of March 12, 2015, among EGC, the guarantors party thereto, and U.S. Bank, N.A., as trustee, and all amendments, supplements or modifications thereto and extensions thereof; · 6.875% senior unsecured notes due March 15, 2024 (the “EGC 6.875 Senior Notes”) issued pursuant to that certain indenture, dated May 27, 2014, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof; · 7.50% senior unsecured notes due December 15, 2021 (the “EGC 7.50% Senior Notes”) issued pursuant to that certain indenture, dated September 26, 2013, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof; · 7.75% senior unsecured notes due June 15, 2019 (the “EGC 7.75% Senior Notes”) issued pursuant to that certain indenture, dated February 25, 2011, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof; · 9.25% senior unsecured notes due December 15, 2017 (the “EGC 9.25% Senior Notes,” and together with the EGC 6.875% Senior Notes, the EGC 7.50% Senior Notes, the EGC 7.75% Senior Notes and the “EGC Unsecured Notes”) issued pursuant to that certain indenture, dated December 17, 2010, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof; · 8.25% senior unsecured notes due February 15, 2018 (the “EPL 8.25% Senior Notes”) issued pursuant to that certain indenture, dated as of February 14, 2011, by and EGC, the guarantors party thereto, and U.S. Bank National Association, as trustee, and all amendments, supplements or modifications thereto and extensions thereof; and · 3.0% senior convertible notes due on December 15, 2018 (the “EXXI 3.0% Senior Convertible Notes”) issued pursuant to that certain indenture dated as of November 22, 2013 among EXXI Ltd and Wilmington Savings Fund Society, FSB, as trustee, and all amendments, supplements or modifications thereto and extensions thereof. Prepetition Revolving Credit Facility and Exit Facility On the Emergence Date, by operation of the Plan, all outstanding obligations under the Second Amended and Restated First Lien Credit Agreement (the “Prepetition Credit Agreement” or the “Prepetition Revolving Credit Facility”) and the related collateral agreements were cancelled and the credit agreements governing such obligations were cancelled. Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into a new three-year secured credit facility (the “Exit Facility”) with the prior lenders under the Prepetition Revolving Credit Facility. The Exit Facility is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors proved reserves and proved developed producing reserves. The Exit Facility is comprised of two facilities: (i) a term loan facility (the “Exit Term Loan”) resulting from the conversion of the remaining drawn amount under the Prepetition Revolving Credit Facility of approximately $74 million plus accrued default interest, fees and expenses and (ii) a revolving credit facility (the “Exit Revolving Facility”) resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility, which provides for the making of revolving loans and the issuance of letters of credit. On the Emergence Date, the aggregate commitments under the Exit Revolving Facility were $227.8 million, all of which will be utilized to maintain in effect outstanding letters of credit, including $225 million of letters of credit issued in favor of Exxon Mobil Corporation (“ExxonMobil”) to secure certain plugging and abandonment obligations. Equity Interests and Warrant Agreement As a result of the Plan, there were no assets remaining in EXXI Ltd, and, under Bermuda law, shareholders (including preferred shareholders) of EXXI Ltd received no payments, and all of its existing share-based compensation plans were also cancelled. EXXI Ltd was dissolved at the conclusion of the Bermuda Proceeding, and as such, the shareholders no longer have any interest in EXXI Ltd as a matter of Bermuda law. On the Emergence Date, EGC entered into a warrant agreement (the “Warrant Agreement”) with Continental Stock Transfer & Trust Company, as Warrant Agent. Pursuant to the terms of the Plan, EGC issued 2,119,889 warrants to certain prepetition noteholders pursuant to the Plan. On the Emergence Date, the Company issued 100% of its shares of common stock to certain of the Debtors’ creditors pursuant to the Plan. The Company issued (i) 27,897,739 shares of common stock, pro rata, to holders of the claims arising from the Second Lien Notes, (ii) 3,985,391 shares of common stock, pro rata, to holders of the claims arising from the EGC Unsecured Notes (the “EGC Unsecured Notes Claims”), (iii) 1,328,464 shares of common stock, pro rata, to holders of the claims arising from the EPL 8.25% Senior Notes (the “EPL Unsecured Notes Claims”), (iv) 1,271,933 warrants, pro rata, to holders of the EGC Unsecured Notes Claims; and (v) 847,956 warrants, pro rata, to holders of the EPL Unsecured Notes Claims. The Confirmation Order and Plan provide for the exemption of the offer and sale of the shares of the Company’s common stock and warrants (including shares of the Company’s common stock issuable upon the exercise thereof) from the registration requirements of the Securities Act of 1933 (the “Securities Act”) pursuant to Section 1145(a)(1) of the Bankruptcy Code. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under the Plan from registration under Section 5 of the Securities Act and state laws if certain requirements are satisfied. Long Term Incentive Plan As of the Emergence Date, the Company also entered into the Energy XXI Gulf Coast, Inc. 2016 Long Term Incentive Plan (the “2016 LTIP”), which is a comprehensive equity-based award plan as part of the go-forward compensation for the Reorganized Debtors’ officers, directors, employees and consultants (“Service Providers”). Amendments to Articles of Incorporation or Bylaws. Pursuant to the Plan, on the Emergence Date, the Company’s certificate of incorporation and bylaws were amended and restated in their entirety. Each of the Company’s Second Amended and Restated Certificate of Incorporation (our “Certificate of Incorporation”) and second amended and restated bylaws became effective on the Emergence Date. Under the Certificate of Incorporation, the total number of all shares of capital stock that the Company is authorized to issue is 110 million shares, consisting of 100 million shares of the Company’s common stock, par value $0.01 per share, and 10 million shares of preferred stock, par value $0.01 per share . Liabilities Subject to Compromise Liabilities subject to compromise represent liabilities incurred prior to the commencement of the bankruptcy proceedings which may be affected by the Chapter 11 process. These amounts represented EXXI Ltd’s allowed claims and its best estimate of claims expected to be allowed which were to be resolved as part of the bankruptcy proceedings. See Note 4 – “Fresh Start Accounting” on final determination on liabilities subject to compromise by the Bankruptcy Court. Interest Expense The Debtors discontinued recording interest on debt classified as liabilities subject to compromise on the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $176.5 million, representing interest expense from the Petition Date through December 31, 2016 with approximately $52.8 million, representing interest expense from the Petition Date through June 30, 2016. Executory Contracts Under the Bankruptcy Code, the Debtors have the right to assume, amend and assume, or reject certain contracts, subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the assumption of a contract requires a debtor to satisfy pre-petition obligations under the contract, which may include payment of pre-petition liabilities in whole or in part. Rejection of a contract is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a pre-petition general unsecured claim for damages. Parties to contracts rejected by a debtor may file proofs of claim against that debtor’s estate for damages. On November 29, 2016, the Debtors filed the Schedule of Rejected Executory Contracts and Unexpired Leases and the Modifications to Schedule of Assumed Executory Contracts and Unexpired Leases as part of the Plan Supplement [Docket No. 1713]. The assumption and rejection of the Debtors’ executory contracts and unexpired leases, as applicable, occurred on the effective date of the Plan in accordance with the terms of the Plan. Potential Claims The Debtors have filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims were required to file proofs of claim by August 22, 2016 (the “Bar Date”). Through the claims resolution process, differences in amounts scheduled by the Debtors and claims filed by creditors were investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. As of December 31, 2017, all claims have been settled except for certain Class 11 claims that will be paid at their pro rata share of the approximately $1.5 million General Unsecured Claim Distribution defined in the Plan.

Fresh Start Accounting

Fresh Start Accounting	12 Months Ended
	Dec. 31, 2017
Fresh Start Accounting
Fresh Start Accounting	Note 4 – Fresh Start Accounting On the Emergence Date, the Debtors satisfied the conditions to effectiveness, the Plan became effective in accordance with its terms and the Company and the other reorganized Debtors emerged from Chapter 11. In connection with the satisfaction of the conditions to effectiveness as set forth in the Confirmation Order and in the Plan, EXXI Ltd and EGC completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to EGC. Accordingly, EGC succeeded to the entire business and operations previously consolidated for accounting purposes at EXXI Ltd. EGC applied fresh start accounting in accordance with the provisions set forth in ASC 852 on the Convenience Date, because (i) the holders of existing voting shares of EXXI Ltd prior to its emergence received less than 50% of the voting shares of EGC outstanding following its emergence from bankruptcy and (ii) the reorganization value of EXXI Ltd’s assets immediately prior to confirmation of the Plan was less than its post-petition liabilities and allowed claims. Adopting fresh start accounting resulted in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit and we allocated the reorganization value to our individual assets based on their estimated fair values. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, the consolidated financial statements on or after the Convenience Date are not comparable with the consolidated financial statements prior to that date. Reorganization Value. Reorganization value represents the fair value of the Company’s total assets prior to the consideration of the liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. Under fresh start accounting, we allocated the reorganization value to our individual assets based on their estimated fair values. Our reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s interest bearing long term debt and shareholders’ equity. In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the Bankruptcy Court to be in the range of $600 million to $900 million. Based on the estimates and assumptions used in determining the enterprise value, as further discussed below, we estimated the enterprise value to be approximately $ 815.1 million. This valuation analysis was prepared using reserve information, development schedules, other financial information and financial projections and applying standard valuation techniques, including risked net asset value analysis and public comparable company analyses. Valuation of Oil and Gas Properties. Our principal assets are our oil and gas properties, which we account for under the full cost method of accounting as described in Note 2 “–Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements”. With the assistance of valuation experts, we determined the fair value of our 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 Emergence Date. Our internal reservoir engineers developed full cycle production models for all of our developed wells and identified undeveloped drilling locations within our leased acreage. The undeveloped locations were categorized based on varying levels of risk using industry standards. The proved locations were limited to wells expected to be drilled in the Company’s five year plan. The locations were then segregated into geographic areas. Future cash flows before application of risk factors were estimated by using the New York Mercantile Exchange (“NYMEX”) four year forward prices for West Texas Intermediate (“WTI”) oil and Henry Hub natural gas with inflation adjustments applied to periods beyond four years. These prices were adjusted for typical differentials realized by us for location and product quality adjustments. Transportation cost estimates were based on agreements in place at the Emergence Date. Development and operating costs were based on our recent cost trends adjusted for inflation. Risk factors were determined separately for each geographic area. Based on the geological characteristics of each area appropriate risk factors for each of the reserve categories were applied. We and our valuation experts considered production, geological and mechanical risk to determine the probability factor for each reserve category in each area. The risk adjusted after tax cash flows were discounted at 11.1%. This 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 industry participants. The after tax cash flow computations included utilization of the Company’s unamortized tax basis in the properties as of the Emergence Date. Plugging and abandonment costs were included in the cash flow projections for undeveloped reserves but were excluded for developed reserves since the fair value of this liability was determined separately and included in the Emergence Date liabilities reported on the December 31, 2016 balance sheet. From this analysis we concluded the fair value of our proved reserves was $1,127.6 million, the value of our probable reserves was $295.3 million and the value of our possible reserves was $80.8 million as of the Convenience Date. The value of probable and possible reserves was classified as unevaluated costs. We also reviewed our undeveloped leasehold acreage and concluded that the fair value of our probable and possible reserves appropriately captured the fair value of our undeveloped leasehold acreage. Although the Company believes the assumptions and estimates used to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment. The following table reconciles the enterprise value to the estimated fair value of the Successor Company’s common stock as of the Convenience Date ( in thousands ): December 31, 2016 Enterprise Value $ 815,119 Add: Cash and cash equivalents 165,368 Less: Fair value of debt (78,497) Fair Value of Successor common stock and warrants 901,990 Less: Fair value of warrants (8,056) Fair Value of Successor common stock $ 893,934 Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into a new three-year secured credit facility (the “Exit Facility”). The Exit Facility is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors proved reserves and proved developed producing reserves. The Exit Facility is comprised of two facilities: (i) a term loan facility (the “Exit Term Loan”) resulting from the conversion of the remaining drawn amount plus accrued default interest, fees and expenses under the Prepetition Revolving Credit Facility of approximately $74 million and (ii) a revolving credit facility (the “Exit Revolving Facility”) resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility which provides, subject to the limitations noted below, for the making of revolving loans and the issuance of letters of credit. On the Emergence Date, the Company entered into a Warrant Agreement with Continental Stock Transfer & Trust Company, as Warrant Agent. On the Emergence Date, pursuant to the terms of the Plan, the Company issued 2,119,889 warrants to holders of the EGC Unsecured Notes Claims and holders of the EPL Unsecured Notes Claims. The warrants are exercisable from the date of the Warrant Agreement until December 30, 2021 (the “Expiration Date”). The warrants are initially exercisable for one share of the Company’s common stock per warrant (such rate, as adjusted pursuant to the Warrant Agreement, being the “Warrant Exercise Shares”) at an initial exercise price of $43.66 (the “Exercise Price”). The Warrant Exercise Shares and Exercise Price are subject to customary anti-dilution adjustments. No adjustments to the applicable Exercise Price or Warrant Exercise Shares are required unless the cumulative adjustments required would result in an increase or decrease of at least 1.0% in the applicable Exercise Price or the Warrant Exercise Shares. Additionally, if an adjustment in Exercise Price would reduce the Exercise Price to an amount below par value of the common stock, then such adjustment in Exercise Price will reduce the Exercise Price to the par value of the common stock. The fair value of the warrants was $3.80 per warrant. A Black- Scholes pricing model with the following assumptions was used in determining the fair value: The following table reconciles the enterprise value to the estimated reorganization value as of the Emergence Date ( in thousands ): December 31, 2016 Enterprise Value $ 815,119 Add: Cash and cash equivalents 165,368 Add: Other working capital liabilities 156,792 Add: Other long-term liabilities 12,595 Add: Asset retirement obligation 737,108 Reorganization value of Successor assets $ 1,886,982 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. Consolidated Balance Sheet The adjustments set forth in the following consolidated balance sheet reflect the effect of the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”), fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). On the Convenience Date, subsequent to the restructuring adjustments and fair value adjustments, we recorded an impairment of our oil and natural gas properties of approximately $406.3 million, primarily due to pricing differences between the 12‑month average oil and gas prices used in the ceiling test and the forward strip prices used to estimate the fresh start fair value of oil and gas properties of the Company (reflected in the column “Impairment”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions. The following table reflects the reorganization and application of ASC 852 and the Convenience Date ceiling test impairment on our consolidated balance sheet as of December 31, 2016 after making adjustments to correct immaterial misstatements. For a detailed explanation of these adjustments, p lease see Note 2 “—Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements” ( in thousands ): As of December 31, 2016 Predecessor Reorganization Fresh-Start Successor Impairment Successor ASSETS Current Assets Cash and cash equivalents $ 164,817 $ 551 (1) $ — $ 165,368 $ — $ 165,368 Accounts receivable, net — — Oil and natural gas sales 69,744 — — 69,744 — 69,744 Joint interest billings 6,029 — — 6,029 — 6,029 Other 18,909 (965) (3) — 17,944 — 17,944 Prepaid expenses and other current assets 46,123 (26,260) (2) (1,883) (10) 17,980 — 17,980 Restricted cash 32,888 (551) (1) — 32,337 — 32,337 Total Current Assets 338,510 (27,225) (1,883) 309,402 — 309,402 Property and Equipment Oil and natural gas properties, net 491,521 — 1,012,225 (11) 1,503,746 (406,275) 1,097,471 Other property and equipment, net 15,049 — 4,958 (12) 20,007 — 20,007 Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment 506,570 — 1,017,183 1,523,753 (406,275) 1,117,478 Other Assets Restricted cash 25,583 — — 25,583 — 25,583 Other assets 30,174 — (1,930) (13) 28,244 — 28,244 Total Other Assets 55,757 — (1,930) 53,827 — 53,827 Total Assets $ 900,837 $ (27,225) $ 1,013,370 $ 1,886,982 $ (406,275) $ 1,480,707 LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) Current Liabilities Accounts payable $ 67,876 $ 33,241 (3) $ — $ 101,117 $ — $ 101,117 Accrued liabilities 40,517 15,158 (3)(4) — 55,675 — 55,675 Asset retirement obligations 58,537 — (1,936) (14) 56,601 — 56,601 Current maturities of long-term debt 74,046 (69,778) (5) — 4,268 — 4,268 Total Current Liabilities 240,976 (21,379) (1,936) 217,661 — 217,661 Long-term debt, less current maturities — 74,229 (5) — 74,229 — 74,229 Asset retirement obligations 492,931 — 187,576 (14) 680,507 — 680,507 Other liabilities 22,776 2,345 (3) (12,526) (15) 12,595 — 12,595 Total Liabilities Not Subject to Compromise 756,683 55,195 173,114 984,992 — 984,992 Liabilities subject to compromise 2,931,419 (2,931,419) (6) — — — — Total Liabilities 3,688,102 (2,876,224) 173,114 984,992 — 984,992 Stockholders’ Equity (Deficit) Preferred stock (Predecessor) 7.25% Convertible perpetual preferred stock (Predecessor) — — — — — — 5.625% Convertible perpetual preferred stock (Predecessor) — — — — — — Common stock (Predecessor) 504 (504) (7) — — — — Common stock (Successor) — 332 (8) — 332 — 332 Additional paid-in capital (Predecessor) 1,845,851 (1,845,851) (7) — — — — Additional paid-in capital (Successor) — 901,658 (8) — 901,658 — 901,658 Accumulated deficit (4,633,620) 3,793,364 (9) 840,256 (16) — (406,275) (406,275) Total Stockholders’ (Deficit) Equity (2,787,265) 2,848,999 840,256 901,990 (406,275) 495,715 Total Liabilities and Stockholders’ (Deficit) Equity $ 900,837 $ (27,225) $ 1,013,370 $ 1,886,982 $ (406,275) $ 1,480,707 Reorganization Adjustments (1) (2) (3) (4) (5) (6) in thousands ): On December 31, 2016 Predecessor Debt 11.0% Senior Secured Second Lien Notes due 2020 $ 1,450,000 8.25% Senior Notes due 2018 213,677 6.875% Senior Notes due 2024 143,993 3.0% Senior Convertible Notes due 2018 363,018 7.5% Senior Notes due 2021 238,071 7.75% Senior Notes due 2019 101,077 9.25% Senior Notes due 2017 249,452 4.14% Promissory Note due 2017 4,001 Capital lease obligations 450 Total debt 2,763,739 Accounts payable 37,424 Accrued liabilities 130,256 Total liabilities subject to compromise 2,931,419 Fair value of equity and warrants issued per the Plan (901,990) Fair value of reinstated accounts payable and accrued liabilities to be settled in cash (43,509) Cash payment for 3.0% Senior Convertible Notes (2,000) Gain on settlement of liabilities subject to compromise $ 1,983,920 (7) (8) (9) in thousands ): December 31, 2016 Gain on settlement of liabilities subject to compromise $ 1,983,920 Cancellation of EXXI Ltd equity 1,846,355 Accrual of success fee (12,651) Payments made of plan support parties (24,260) Net impact to accumulated deficit $ 3,793,364 Fresh Start Adjustments (10) (11) (12) (13) (14) 37.1 million. (15) (16) 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” in the consolidated statements of operations. The following table summarizes reorganization items ( in thousands ): Predecessor Six Months Ended Year Ended December 31, June 30, 2016 2016 Gain on settlement of liabilities subject to compromise $ 1,983,920 $ — Fresh start adjustments 840,256 — Reorganization legal and professional fees and expenses (90,568) (14,201) Gain (loss) on reorganization items $ 2,733,608 $ (14,201)

Acquisitions and Dispositions

Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2017
Acquisitions and Dispositions
Acquisitions and Dispositions	Note 5 – Acquisitions and Dispositions Acquisition of interest in M21K On August 11, 2015, pursuant to a stock purchase agreement (the “M21K Purchase Agreement”) between Energy XXI M21K, LLC (“EXXI M21K”), in which EXXI Ltd owned 20% interest, and Energy XXI GOM, LLC, an indirect wholly owned subsidiary of EXXI Ltd, we acquired all of the remaining equity interests of M21K, LLC (“M21K”) for consideration consisting of the assumption of all obligations and liabilities of M21K including approximately $25.2 million associated with M21K’s first lien credit facility, which was required to be paid at closing (the “M21K Acquisition”). The sellers retained certain overriding royalty interests applicable only to the extent that production proceeds during any calendar month average in excess of $65.00/Bbl WTI and $3.50/MMbtu Henry Hub and limited to a term of four years or an aggregate amount of $20 million, whichever occurs earlier. In addition, with respect to the Eugene Island 330 and South Marsh Island 128 fields, in the event we sell our interest in one or both of these fields, the overriding royalty interests with respect to such sold field shall terminate; provided, however if such sale occurs within four years of the effective date of the M21K Purchase Agreement and the consideration received for such sale is greater than the allocated value for such field as specified in the M21K Purchase Agreement, then we are obligated to pay an amount equal to 20% of the portion of the consideration received in excess of the specified allocated value of such field. Prior to this transaction which was effective as of August 1, 2015, we had owned a 20% interest in M21K through our investment in EXXI M21K. See Note 8 – “Equity Method Investments.” The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their estimated fair values on August 11, 2015 ( in thousands ): Oil and natural gas properties – evaluated $ 73,910 Oil and natural gas properties – unevaluated 39,278 Asset retirement obligations (66,700) Net working capital * (21,301) Fair value of debt assumed (25,187) Cash paid $ — * Sale of the Grand Isle Gathering System On June 30, 2015, we sold certain real and personal property constituting a subsea pipeline gathering system located in the shallow GoM shelf and storage and onshore processing facilities on Grand Isle, Louisiana (the “GIGS”) to Grand Isle Corridor, LP (“Grand Isle Corridor”), a wholly-owned subsidiary of CorEnergy Infrastructure Trust, Inc. for cash consideration of $245 million, plus the assumption by Grand Isle Corridor of the asset retirement obligations associated with the estimated decommissioning costs for the GIGS. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss recognized. The net reduction to the full cost pool related to this sale was $248.9 million. Also on June 30, 2015, we entered into a triple-net lease agreement with Grand Isle Corridor pursuant to which we will continue to use and operate the GIGS as further discussed in Note 17 – “Commitments and Contingencies.” Sale of interests in the East Bay field On June 30, 2015, we sold our interest in the East Bay field to Whitney Oil & Gas, LLC and Trimont Energy (NOW), LLC, for cash consideration of $21 million plus the assumption of asset retirement obligations estimated at $55.1 million. The cash consideration was payable in two installments with $5 million received at closing and the remainder in fiscal year 2016. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field. Revenues and expenses related to the field were included in our results of operations through June 30, 2015. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss recognized. The net reduction to the full cost pool related to this sale was $68.9 million. Subsequent to June 30, 2015, post-closing adjustments reduced the total cash consideration to $20.3 million and the maximum receivable under the overriding royalty interest to $6.4 million. The final settlement occurred in January 2017.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2017
Goodwill
Goodwill	Note 6 - Goodwill ASC 350, Intangibles—Goodwill and Other , requires that intangible assets with indefinite lives, including goodwill, be evaluated for impairment on an annual basis or more frequently if events occur or circumstances change that could potentially result in impairment. Our annual goodwill impairment test is performed at least annually during the third quarter. Impairment testing for goodwill is done at the reporting unit level. We have only one reporting unit, which includes all of our oil and natural gas properties. Accordingly, all of our goodwill, as well as all of our other assets and liabilities, are included in our single reporting unit. At December 31, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase in our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. In light of the form of the acquisition of EPL (a purchase of stock), this goodwill had no tax basis when recognized, which resulted in no income tax benefit when impaired. In estimating the fair value of our reporting unit and our estimated reserves, we used an income approach which estimated fair value primarily based on the anticipated cash flows associated with our estimated reserves, discounted using an assumed weighted average cost of capital based on market participant data. The estimation of the fair value of our reporting unit and our estimated reserves includes the use of significant inputs not observable in the market, such as estimates of reserves quantities, the weighted average cost of capital (discount rate), future pricing and future capital and operating costs. The use of these unobservable inputs results in the fair value estimate being classified as a Level 3 measurement. Although we believe the assumptions and estimates used in the fair value calculation of our reporting unit were reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. At June 30, 2016, included in other assets and debt issuance costs, net of accumulated amortization, on our consolidated balance sheets was $0.8 million of goodwill associated with the acquisition of a catering business on August 21, 2015. On the Convenience Date, there was no goodwill after recording the effect of the consummation of the transactions contemplated by the Plan.

Property and Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2017
Property and Equipment
Property and Equipment	Note 7 – Property and Equipment Property and equipment consists of the following ( in thousands ): Successor December 31, December 31, 2017 2016 Oil and gas properties Proved properties $ 1,307,009 $ 1,127,608 Less: accumulated depreciation, depletion, amortization and impairment (742,286) (406,275) Proved properties, net 564,723 721,333 Unevaluated properties 200,199 376,138 Oil and gas properties, net 764,922 1,097,471 Other property and equipment 13,780 20,007 Less: accumulated depreciation (3,660) — Other property and equipment, net 10,120 20,007 Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment $ 775,042 $ 1,117,478 See Note 4 – “Fresh Start Accounting” for the methodology and assumptions used in arriving at fair value fresh start adjustments on the Convenience Date. Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE (unaudited) at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million (unaudited). As of December 31, 2017, we have 22 MMBOE (unaudited) in proved undeveloped reserves. Future development costs associated with our proved undeveloped reserves at December 31, 2017 totaled approximately $356.1 million (unaudited). As scheduled in our long range plan, all of our proved undeveloped locations are expected to be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report. Costs associated with unevaluated properties, all of which were recorded as part of fresh start accounting, are transferred to evaluated properties either (i) ratably over a period of the related field’s life, or (ii) upon determination as to whether there are any proved reserves related to the unevaluated properties or the costs are impaired or capital costs associated with the development of these properties will not be available. For the year ended December 31, 2017, the costs associated with unevaluated properties decreased by $1 75.9 million, of which $ 121.8 million was transferred to evaluated properties due to the forward price outlook and management intent making certain unevaluated properties uneconomical and the remaining $ 54.1 million was the ratable amortization to the evaluated properties. Under the full cost method of accounting, at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12‑month period discounted at 10%, plus the lower of cost or fair market value of unevaluated properties and excluding cash flows related to estimated abandonment costs associated with developed properties) to the net capitalized costs of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the amount of the discounted cash flows. For the year ended December 31, 2017, we recorded an impairment to oil and natural gas properties of $185.9 million due to the decrease in proved reserves and PV‑10 value. On December 31, 2016, the Company, subsequent to its emergence from bankruptcy, recorded an impairment of its oil and natural gas properties of approximately $406.3 million due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4‑10. The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12‑month average oil and natural gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting. For the six-month period ended December 31, 2016 and for the years ended June 30, 2016 and 2015, the Predecessor recorded an impairment to its oil and natural gas properties of $77.8 million, $2,814.0 million and $2,421.9 million, respectively.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2017
Equity Method Investments
Equity Method Investments	Note 8 - Equity Method Investments Prior to the M21K Acquisition on August 11, 2015 discussed previously in Note 4 – “Acquisitions and Dispositions,” we owned a 20% interest in EXXI M21K which was engaged in the acquisition, exploration, development and operation of oil and natural gas properties offshore in the Gulf of Mexico, through its wholly owned subsidiary, M21K. EGC received a management fee from M21K for providing administrative assistance in carrying out its operations. We also provided a guarantee related to the payment of asset retirement obligations and other liabilities of M21K. EXXI M21K was a guarantor of a $100 million first lien credit facility agreement entered into by M21K, which had a $40 million borrowing base and under which $28.0 million in loans and $1.2 million in letters of credit were outstanding as of June 30, 2015. At June 30, 2015, M21K was in default due to a breach of certain covenants under this agreement. On August 11, 2015, we acquired all of the equity interests of M21K and repaid the outstanding balance under the M21K credit facility. See Note 15 – “Related Party Transactions.” We recorded an equity loss of $10.7 million and $17.4 million for the years ended June 30, 2016 and 2015, respectively. The equity loss for the year ended June 30, 2015 includes an other-than-temporary impairment related to our investment in EXXI M21K of $11.8 million.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Long-Term Debt
Long-Term Debt	Note 9 – Long-Term Debt Long-term debt consists of the following ( in thousands ): Successor December 31, December 31, 2017 2016 Exit Facility $ 73,996 $ 73,996 4.14% Promissory Note due 2017 — 4,001 Capital lease obligations 21 500 Total debt 74,017 78,497 Less: debt issue costs 44 — Less: current maturities 21 4,268 Total long-term debt $ 73,952 $ 74,229 Maturities of long-term debt as of December 31, 2017 are as follows (in thousands ) Twelve Months Ending December 31, 2018 $ 21 2019 73,996 2020 — 2021 — 2022 — Thereafter — $ 74,017 Exit Facility Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into a secured Exit Facility, which matures on December 30, 2019. The Exit Facility is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors’ proved developed producing reserves as well as our total proved reserves. The Exit Facility consists of two facilities: (i) a term loan facility (the “Exit Term Loan”) resulting from the conversion of the remaining drawn amount plus accrued default interest, fees and expenses under the Debtors’ Second Amended and Restated First Lien Credit Agreement (the “Prepetition Revolving Credit Facility”) of approximately $74 million and (ii) a revolving credit facility (the “Exit Revolving Facility”) resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility which provides, subject to the limitations noted below, for the making of revolving loans and the issuance of letters of credit. Interest on the outstanding amount of the Exit Term Loan, at the Company’s option, will accrue at an interest rate equal to either: (i) the Alternative Base Rate (as defined in the Exit Facility) plus 3.5% per annum or (ii) the one-month LIBO Rate (as defined in the Exit Facility) plus 4.5% per annum. Interest on the Exit Term Loan bearing interest at the Alternative Base Rate will be payable quarterly; interest on the Exit Term Loan bearing interest at the LIBO Rate will be payable monthly. On the Emergence Date, the aggregate credit capacity under the Exit Revolving Facility was approximately $227.8 million, all of which was utilized to maintain in effect outstanding letters of credit, including $225 million of letters of credit issued in favor of ExxonMobil to secure certain plugging and abandonment obligations related to assets in the GoM. On April 26, 2016, pursuant to the redetermination of our plugging and abandonment liabilities with ExxonMobil, it was then agreed that subsequent to the Predecessor Company’s emergence from the Chapter 11 proceedings, the letters of credit issued in favor of ExxonMobil would be reduced to $200 million from the existing amount of $225 million and, on March 13, 2017, the letters of credit issued in favor of ExxonMobil were reduced to $200 million. Each existing letter of credit may be renewed or replaced (in each case, in an outstanding amount not to exceed the outstanding amount of the existing letter of credit). Following the reduction of $25 million in the letters of credit issued in favor of ExxonMobil, the credit capacity under the Exit Revolving Facility was permanently reduced by 50% of the $25 million reduction in the letters of credit, or $12.5 million. The remaining 50%, or $12.5 million, of such aggregate reduction is available for borrowing, under specific circumstances, as revolving loans subject to a maximum for all such loans of (i) $25 million prior to the date the borrowing base is initially determined and (ii) the borrowing base, on and after the date the borrowing base is initially determined. The borrowing base will be initially determined at a date elected by the Company, and will be redetermined semi-annually thereafter. Currently, the Company has not elected a date for the initial borrowing base determination. The Company must make a mandatory prepayment of the revolving loans and, if necessary, cash collateralize the outstanding letters of credit if a reduction in the revolving credit capacity would cause the revolving credit exposure to exceed the revolving credit capacity. On or after the determination of the borrowing base, the Company must also make a mandatory prepayment of the revolving loans and, if necessary, cash collateralize the outstanding letters of credit not in favor of ExxonMobil if a borrowing base deficiency arises. The Exit Facility contains covenants and events of default customary for reserve-based lending facilities. In addition, for each fiscal quarter ending on and after March 31, 2018, the Company must maintain a Current Ratio (as defined in the Exit Facility) of no less than 1.00 to 1.00 and a First Lien Leverage Ratio (as defined in the Exit Facility) of no greater than 4.00 to 1.00 calculated on a trailing four quarter basis. Furthermore, for each fiscal quarter ending on and after March 31, 2018, if the Asset Coverage Ratio (as defined in the Exit Facility) is less than 1.50 to 1.00, the Company must make a mandatory prepayment of the Exit Term Loan in an amount equal to the lesser of (i) 7.5% of the aggregate outstanding principal amount of the Exit Term Loan on the Emergence Date and (ii) the then outstanding principal amount of the Exit Term Loan. Based upon the Company’s current expectations with respect to its capital resources, capital expenditures, results from operations and commodity prices, the Company believes that it is reasonably likely that it will be required to make a mandatory prepayment with respect to each fiscal quarter ending on and after March 31, 2018. In that case, the first such payment of approximately $5.55 million would be required to be paid during the fiscal quarter ending June 30, 2018. Any such mandatory prepayment would not, in and of itself, constitute a default under the Exit Facility. Interest on the outstanding amount of revolving loans borrowed under the Exit Revolving Facility, at the Company’s option, will accrue at an interest rate equal to either (i) the Alternative Base Rate plus 3.5% per annum or (ii) the one, three or six month LIBO Rate plus 4.5% per annum. Interest on revolving loans that bear interest at the Alternative Base Rate will be payable quarterly; interest on revolving loans that bear interest at the LIBO Rate will be payable at the end of each interest period or, if an interest period exceeds three months, at the end of every three months. The stated amount of each letter of credit issued under the Exit Revolving Facility accrues fees at the rate of 4.5% per annum. There is an issuance fee of 0.25% per annum charged on the stated amount of each letter of credit issued after the Emergence Date. Unused credit capacity under the Exit Revolving Facility will accrue a commitment fee of 0.50% payable quarterly in arrears. The Exit Facility is guaranteed by substantially all of the wholly-owned subsidiaries of the Company, subject to customary exceptions, and is secured by first priority security interests on substantially all assets of each Reorganized Debtor guarantor. Under the Exit Facility, the borrower will not declare or make a restricted payment, or make any deposit for any restricted payment. Restricted payments include declaration or payment of dividends. On March 3, 2017, the Company, entered into an amendment to the Exit Facility (the “Amendment”). The Amendment, among other things, included updates necessary to reflect the Company changing its fiscal year end from June 30 to December 31. As a result, the Company must now deliver a December 31 reserve report prepared by a third-party engineer by March 1 of each year (or by May 31 with respect to 2017 only) and a reserve report prepared by the Company’s engineers by September 1 of each year. Further, a second amendment and waiver to the Exit Facility (the “Second Amendment”) was entered into by the Company on April 24, 2017. The Second Amendment amended the requirement of the “as of” date from January 1, 2017 to April 1, 2017, only with respect to the first reserve report prepared by a third-party reservoir engineer. Additionally, the Amendment also revised the calculation of: (i) the net present value of the future net revenues expected to accrue to the proved reserves of the Company and its subsidiaries and (ii) the asset coverage ratio, which are calculated by removing the effects of derivative agreements with any counterparties that are not lenders under the Exit Facility. Furthermore, the requirement for the Company and its subsidiaries to have mortgages covering at least 90% of the total value of their proved reserves was amended to require the mortgages to cover at least 90% of the revised net present value of the proved reserves. As of December 31, 2017, we had approximately $74 million in borrowings and $202. 6 million in letters of credit issued under the Exit Facility. Prepetition Revolving Credit Facility The Prepetition Revolving Credit Facility was entered into by EGC in May 2011. The Prepetition Revolving Credit Facility had a maximum facility amount and borrowing base of $327.2 million, of which such amount $99.4 million was the borrowing base under the sub-facility established for EPL prior to the Chapter 11 Cases. Borrowings under the Prepetition Revolving Credit Facility were limited to a borrowing base based on oil and natural gas reserve values. The scheduled date of maturity of the Prepetition Credit Agreement was April 9, 2018. As a result of the filing of the Bankruptcy Petitions, the highest of the margins applied and default interest was accruing under the facility through an additional 2.00% payment of interest in kind (“PIK”) interest. PIK interest totaling $4.7 million was accrued from the Petition Date through December 31, 2016. Following the modification to the cash collateral order, which was approved by the Bankruptcy Court on October 24, 2016, approximately $30.1 million of restricted cash maintained by EGC related to our Prepetition Credit Agreement was withdrawn on October 25, 2016 and applied to permanently reduce the amount outstanding under its Prepetition Credit Agreement to $69.3 million, thereby resulting in a further reduction to the maximum facility amount and borrowing base to $297.1 million. On the Emergence Date, by operation of the Plan, all outstanding obligations under the Prepetition Revolving Credit Facility and the related collateral agreements were cancelled and the credit agreements governing such obligations were cancelled. Prepetition Senior Notes The Predecessor had issued the following prepetition Senior Notes, which in accordance with the Plan, on the Emergence Date, all outstanding obligations under these notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled ( in thousands ): Issue Date Face value Maturity Date 11.0% Senior Secured Second Lien Notes 3/12/2015 1,450,000 3/15/2020 8.25% Senior Notes (1) 6/3/2014 510,000 2/15/2018 6.875% Senior Notes 5/27/2014 650,000 3/15/2024 3.0% Senior Convertible Notes 11/18/2013 400,000 12/15/2018 7.5% Senior Notes 9/26/2013 500,000 12/15/2021 7.75% Senior Notes 2/25/2011 250,000 6/15/2019 9.25% Senior Notes 12/17/2010 750,000 12/15/2017 (1) 8.25% Senior Notes was assumed in the EPL Acquisition. During the year ended June 30, 2016, our Predecessor repurchased certain of its unsecured notes in aggregate principal amounts as follows: $506.0 million of 6.875% Senior Notes due 2024 (the “6.875% Senior Notes”), $261.9 million of 7.5% Senior Notes due 2021(the “7.5% Senior Notes”), $148.9 million of 7.75% Senior Notes due 2019 (the “7.75% Senior Notes”), $296.3 million of 8.25% Senior Notes due 2018 (the “8.25% Senior Notes”) and $500.6 million of 9.25% Senior Notes due 2017 (the “9.25% Senior Notes”). Our Predecessor repurchased these notes in open market transactions at a total cost of approximately $215.9 million, (excluding accrued interest), and we recorded a gain on the repurchases totaling approximately $1,492.4 million, net of associated debt issuance costs and certain other expenses. All of the notes repurchased in February 2016, except for the 8.25% Senior Notes with face value of $266.6 million and 9.25% Senior Notes with face value of $471.1 million which both continue to be held by EGC were cancelled at June 30, 2016 and the remaining EGC and EPL senior notes held by EGC were cancelled on December 19, 2016. In addition, in March 2016 certain bondholders holding $37 million in face value of Predecessor’s 3.0% Senior Convertible Notes requested a conversion of their notes into common stock. Upon conversion, we recorded a gain of approximately $33.2 million after proportionate adjustment to the related debt issue costs, accrued interest and original debt issue discount. As a result of the covenant violations that existed at March 31, 2016 that were not cured prior to the filing of the Bankruptcy Petitions, EGC’s pre-petition secured indebtedness under the Prepetition Revolving Credit Facility and Second Lien Notes, Energy XXI Ltd’s pre-petition unsecured indebtedness under the 3.0% Senior Convertible Notes, EGC’s pre-petition unsecured indebtedness under the 6.875% Senior Notes, the 7.5% Senior Notes, the 7.75% Senior Notes and the 9.25% Senior Notes and EPL’s pre-petition unsecured indebtedness under the 8.25% Senior Notes became immediately due and payable and any efforts to enforce such payment obligations were automatically stayed as a result of Chapter 11. Accordingly, all of EXXI Ltd’s outstanding indebtedness was classified as current in the consolidated balance sheet and it accelerated the amortization of the associated debt premium and original issue discount, fully amortizing those amounts as of March 31, 2016. In addition, except for amounts related to the Prepetition Revolving Credit Facility, EXXI Ltd accelerated the amortization of the remaining debt issuance costs related to its outstanding indebtedness, fully amortizing those costs as of March 31, 2016. EXXI Ltd continued to accrue interest on the Prepetition Revolving Credit Facility subsequent to the Petition Date until the Convenience Date. However, for all of its other indebtedness, in accordance with ASC 852, Reorganizations , it accrued interest only up to the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the Predecessor consolidated statements of operations was approximately $176.5 million, representing interest expense from the Petition Date through the Emergence Date, of which $123.7 pertained to the six month transition period ended December 31, 2016. 4.14% Promissory Note In September 2012, the Predecessor entered into a promissory note of $5.5 million to acquire other property and equipment. In accordance with the Plan, on the Emergence Date, all outstanding obligations under the promissory note were reinstated. Under this note, which was secured by such other property and equipment, we were required to make monthly payments of approximately $52,000 and were to pay one lump-sum payment of $3.3 million at maturity in October 2017. This note carried an interest rate of 4.14% per annum. This note was repaid in full on September 29, 2017. Derivative Instruments Premium Financing We financed premiums on derivative instruments that we purchased with our hedge counterparties. Substantially all of our hedge transactions were with Lenders under the Prepetition Revolving Credit Facility. Derivative instruments premium financing was accounted for as debt and this indebtedness is pari passu with borrowings under the Prepetition Revolving Credit Facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value, net of derivative instrument premium financing. As of December 31, 2016, June 30, 2016 and 2015, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $0, $0 and $10.6 million, respectively. Interest Expense The filing of the Bankruptcy Petitions constituted an event of default with respect to the Predecessor’s existing debt obligations. Accordingly, the Predecessor’s pre-petition secured indebtedness under the Prepetition Revolving Credit Facility, Second Lien Notes and EPL and EGC unsecured notes became immediately due and payable and any efforts to enforce such payment obligations were automatically stayed as a result of the Chapter 11 Cases. In addition, as a result of the covenant violations that existed at March 31, 2016 that were not cured prior to the filing of the Bankruptcy Petitions, all of our outstanding indebtedness was classified as current in the consolidated balance sheet at March 31, 2016, and we accelerated the amortization of the associated debt premium and original issue discount, fully amortizing those amounts as of March 31, 2016. In addition, except for amounts related to the Prepetition Revolving Credit Facility, the Predecessor accelerated the amortization of the remaining debt issuance costs related to its outstanding indebtedness, fully amortizing those costs as of March 31, 2016. The Predecessor continued to accrue interest on the Prepetition Revolving Credit Facility subsequent to the Petition Date until the Emergence Date. However, for all our other indebtedness, in accordance with accounting guidance in ASC 852, Reorganizations, the Predecessor accrued interest only up to the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $176.5 million, representing interest expense from the Petition Date through Emergence Date, of which $123.7 pertained to the six month transition period ended December 31, 2016. Interest expense consisted of the following ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Exit Term Loan $ 4,050 $ — $ — $ — Exit Revolving Facility 10,127 — — — Prepetition Revolving Credit Facility — 11,670 15,703 25,506 11.0% Second Lien Notes due 2020 — — 125,852 48,505 8.25% Senior Notes due 2018 — — 27,899 42,075 6.875% Senior Notes due 2024 — — 18,033 44,701 3.0% Senior Convertible Notes due 2018 — — 9,340 12,000 7.50% Senior Notes due 2021 — — 17,414 37,500 7.75% Senior Notes due 2019 — — 8,200 19,375 9.25% Senior Notes due 2017 — — 44,944 69,375 4.14% Promissory Note due 2017 134 — 130 192 Amortization of debt issue cost - Prepetition Revolving Credit Facility — 725 5,185 12,491 Accretion of original debt issue discount, 11.0% Second Lien Notes due 2020 — — 6,249 2,358 Accretion of original debt issue discount, 11.0% Second Lien Notes due 2020 - accelerated — — 44,855 — Amortization of debt issue cost – 11.0% Second Lien Notes due 2020 — — 5,047 1,887 Amortization of debt issue cost – 11.0% Second Lien Notes due 2020 - accelerated — — 36,243 — Amortization of fair value premium – 8.25% Senior Notes due 2018 — — (8,818) (11,108) Amortization of fair value premium – 8.25% Senior Notes due 2018 - accelerated — — (7,961) — Amortization of debt issue cost – 6.875% Senior Notes due 2024 — — 457 1,127 Amortization of debt issue cost – 6.875% Senior Notes due 2024 - accelerated — — 1,946 — Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 — — 8,917 11,232 Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 - accelerated — — 33,370 — Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 — — 1,142 1,439 Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 - accelerated — — 4,271 — Amortization of debt issue cost – 7.50% Senior Notes due 2021 — — 478 1,051 Amortization of debt issue cost – 7.50% Senior Notes due 2021 - accelerated — — 2,822 — Amortization of debt issue cost – 7.75% Senior Notes due 2019 — — 168 388 Amortization of debt issue cost – 7.75% Senior Notes due 2019 - accelerated — — 491 — Amortization of debt issue cost – 9.25% Senior Notes due 2017 — — 1,902 2,358 Amortization of debt issue cost – 9.25% Senior Notes due 2017 - accelerated — — 913 — Derivative instruments financing and other 525 185 466 856 $ 14,836 $ 12,580 $ 405,658 $ 323,308

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligations
Asset Retirement Obligations	Note 10 – Asset Retirement Obligations The following table describes the changes in our asset retirement obligations ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, 2017 2016 Beginning of period total $ 737,108 $ 537,637 Liabilities incurred 11,353 13,880 Liabilities settled (55,820) (18,852) Revisions* (70,570) (19,577) Accretion expense 42,780 38,380 End of period total 551,468 Fair value fresh start adjustments 185,640 End of period total 664,851 737,108 Less: End of period, current portion 51,398 56,601 End of period, noncurrent portion $ 613,453 $ 680,507 * , resulting from updated estimates as to when the associated wells would cease to be economic, and the downward revision for the six months ended December 31, 2016 was primarily due to declining service costs resulting from the decline in commodity prices and decrease in demand for oil field services due to excess capacity. See Note 4 – “Fresh Start Accounting” for the methodology and assumptions used in arriving at fair value fresh start adjustments on the Convenience Date.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Financial Instruments
Derivative Financial Instruments	Note 11 – Derivative Financial Instruments We enter into derivative transactions to reduce exposure to fluctuations in the price of crude oil and natural gas with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We have historically used various instruments, including financially settled crude oil and natural gas puts, put spreads, swaps, costless collars and three-way collars in our derivative portfolio. With a costless collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. In a fixed price swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the swap fixed price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the swap fixed price. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying consolidated balance sheets. Any gains or losses resulting from changes in fair value of our outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statements of operations. Most of our crude oil production is sold at Heavy Louisiana Sweet. We have historically included contracts indexed to NYMEX-WTI, ICE Brent futures and Argus-LLS futures in our derivative portfolio to closely align and manage our exposure to the associated price risk. On March 14, 2016, the fourteenth amendment to the Prepetition Revolving Credit Facility became effective and required us to unwind certain derivative transactions and use the proceeds therefrom to repay amounts of outstanding loans to EPL under the Prepetition Revolving Credit Facility, and for such repayments to then result in an automatic and permanent reduction in EXXI Ltd’s borrowing base. Accordingly, on March 15, 2016, EXXI Ltd unwound and monetized all of its outstanding crude oil and natural gas contracts and $50.6 million was applied to reduce amounts outstanding under the Prepetition Revolving Credit Facility. The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of derivative arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements. The Company did not enter into any derivative instruments during the six month transition period ended December 31, 2016, accordingly, there were no outstanding derivative contracts on December 31, 2016. As of December 31, 2017, we had the following open crude oil derivative positions: Weighted Average Type of Volumes Contract Price Remaining Contract Term Contract Index (MBbls) Swaps January 2018 - December 2018 Swaps NYMEX-WTI $ 50.68 January 2018 - June 2018 Swaps Argus-LLS $ 55.45 January 2018 - June 2018 Swaps ICE Brent $ 56.59 The fair value of our derivative instruments in our consolidated balance sheets were as follows ( in thousands ) Successor Asset Derivative Instruments Liability Derivative Instruments December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Balance Fair Value Balance Fair Value Balance Fair Value Balance Fair Value Derivative financial instruments Current $ — Current $ — Current $ 32,567 Current $ — Non-Current — Non-Current — Non-Current — Non-Current — Total Gross Commodity Derivative Instruments subject to enforceable master netting agreement — — 32,567 — Derivative financial instruments Current — Current — Current — Current — Non-Current — Non-Current — Non-Current — Non-Current — Total gross amounts offset in Balance Sheets — — — — Net amounts presented in Balance Sheets Current — Current — Current 32,567 Current — Non-Current — Non-Current — Non-Current — Non-Current — $ — $ — $ 32,567 $ — The following table presents information about the components of the gain (loss) on derivative instruments ( in thousands ). Year Ended Six Months December 31, Ended Year Ended June 30, Gain (loss) on derivative financial instruments 2017 2016 2016 2015 Cash Settlements $ (58) $ — $ 59,081 $ 81,049 Proceeds from monetizations — — 50,588 102,354 Change in fair value (32,567) — (19,163) 52,036 Total gain (loss) on derivative financial instruments $ (32,625) $ — $ 90,506 $ 235,439 We monitor the creditworthiness of our counterparties who are also a part of our bank lending group. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of our financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. As of December 31, 2017, we had no collateral deposits with our counterparties.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity
Stockholders' Equity	Note 12 – Stockholders’ Equity Successor Common and Preferred Stock Amendments to Articles of Incorporation or Bylaws Pursuant to the Plan, on the Emergence Date, the Company’s certificate of incorporation and bylaws were amended and restated in their entirety. Each of the Company’s Certificate of Incorporation and second amended and restated bylaws became effective on the Emergence Date. Under our Certificate of Incorporation, the total number of all shares of capital stock that we are authorized to issue is 110 million shares, consisting of 100 million shares of the Company’s common stock, par value $0.01 per share, and 10 million shares of preferred stock, par value $0.01 per share. In order to permit Mr. Reddin to be appointed CEO on an interim basis, the Board adopted the Third Amended and Restated Bylaws (the “Bylaws”) on February 2, 2017. Pursuant to the Bylaws, Section 4.1 was amended to provide that the positions of Chairman of the Board and Chief Executive Officer may be held by the same person only if (i) the two positions are held by the same person solely on an interim basis and (ii) the Board elects a Lead Independent Director for any period in which the two positions are held by the same person. Accordingly, the Bylaws added a new Section 3.8 to establish the position of Lead Independent Director and specified that position’s duties. The Bylaws provide that, during any period in which a Lead Independent Director is serving, the Lead Independent Director may, among other responsibilities, call and preside over all meetings of independent directors and, in the Chairman of the Board’s absence, preside over all meetings of the Company’s stockholders and of the Board. Registration Rights Agreement On the Emergence Date, the Company entered into a registration rights agreement with certain holders representing 10% or more of the Company’s common stock outstanding on that date or who acquire 10% or more of the Company’s common stock outstanding within six months of the Emergence Date (the “Holders”). The Registration Rights Agreement provides resale registration rights for the Holders’ Registerable Securities (as defined in the Registration Rights Agreement). On February 28, 2017, in accordance with the requirements of the Registration Rights Agreement, the Company filed a registration statement on Form S‑3 relating to the resale of an aggregate of 9,272,285 shares of our common stock, which may be offered for sale from time to time by the selling stockholders named in the Form S‑3 prospectus. The number of shares the selling stockholders may sell consists of 9,049,929 shares of common stock that are currently issued and outstanding and 222,356 shares of common stock that they may receive if they exercise their warrants. The selling stockholders acquired all of the shares of common stock and warrants covered by the Form S‑3 prospectus in a distribution pursuant to Section 1145 under the United States Bankruptcy Code in connection with our plan of reorganization that became effective on the Emergence Date. We are not selling any shares of common stock under the Form S‑3 prospectus and will not receive any proceeds from the sale of common stock by the selling stockholders. The registration statement on Form S‑3 was declared effective by the SEC as of March 23, 2017. On February 28, 2017, pursuant to our satisfaction of all the listing requirements, our common stock began trading on NASDAQ under the symbol “EXXI” at the opening of business. Warrant Agreement On the Emergence Date, the Company issued 2,119,889 warrants to holders of the EGC Unsecured Notes Claims and holders of the EPL Unsecured Notes Claims. The warrants are exercisable from the date of the Warrant Agreement until the Expiration Date. The warrants are initially exercisable for one share of common stock per warrant at an initial exercise price of $43.66. The Warrant Exercise Shares and Exercise Price are subject to customary anti-dilution adjustments. No adjustments to the applicable Exercise Price or Warrant Exercise Shares are required unless the cumulative adjustments required would result in an increase or decrease of at least 1.0% in the applicable Exercise Price or the Warrant Exercise Shares. Additionally, if an adjustment in Exercise Price would reduce the Exercise Price to an amount below par value of the common stock, then such adjustment in Exercise Price will reduce the Exercise Price to the par value of the common stock. Upon the occurrence of certain events prior to the Expiration Date constituting a recapitalization, reorganization, reclassification, consolidation, merger, sale of all or substantially all of the Company’s equity securities or assets or other transaction, in each case which is effected in such a way that the holders of common stock are entitled to receive (either directly or upon subsequent liquidation) cash, stock, securities or other assets or property with respect to or in exchange for common stock (any such event, “Organic Change”), each holder of warrants will be entitled to receive, upon exercise of a Warrant, such cash, stock, securities or other assets or property as would have been issued or payable in such Organic Change (as if the holder had exercised such Warrant immediately prior to such Organic Change) with respect to or in exchange, as applicable, for the number of Warrant Exercise Shares that would have been issued upon exercise of such warrants, if such warrants had been exercised immediately prior to the occurrence of such Organic Change. Holders of warrants are not entitled, by virtue of holding warrants, to vote, to consent, to receive dividends, to consent or to receive notice as stockholders with respect to any meeting of stockholders for the election of the Company’s directors or any other matter, or to exercise any rights whatsoever as the Company’s stockholders unless, until and only to the extent such holders become holders of record of shares of common stock issuable upon exercise of the warrants. The warrants permit a holder of warrants to exercise the warrants for net share or “cashless” settlement in lieu of paying the Exercise Price by authorizing the Company to withhold and not issue to such holder, in payment of the Exercise Price, a number of such Warrant Exercise Shares equal to (i) the number of Warrants Exercise Shares for which the warrants are being exercised, multiplied by (ii) the Exercise Price, and divided by (iii) the Current Sale Price (as defined in the Warrant Agreement) on the Exercise Date. Shares of common stock and warrants issued and outstanding On the Emergence Date, the Company issued (i) 27,897,739 shares of common stock, pro rata, to holders of the claims arising from the Second Lien Notes, (ii) 3,985,391 shares of common stock, pro rata, to holders of the claims arising from the EGC Unsecured Notes Claims, (iii) 1,328,464 shares of common stock, pro rata, to holders of the claims arising from the EPL Unsecured Notes Claims, (iv) 1,271,933 warrants, pro rata, to holders of the EGC Unsecured Notes Claims; and (v) 847,956 warrants, pro rata, to holders of the EPL Unsecured Notes Claims. The Confirmation Order and Plan provide for the exemption of the offer and sale of the shares of common stock and the warrants (including shares of Common Stock issuable upon the exercise thereof) from the registration requirements of the Securities Act pursuant to Section 1145(a)(1) of the Bankruptcy Code. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under the Plan from registration under Section 5 of the Securities Act and state laws if certain requirements are satisfied. As of December 31, 2017, 33,2 54,963 shares of common stock and 2,119,889 warrants were outstanding. Predecessor Common Stock EXXI Ltd’s common stock was traded on the NASDAQ under the symbol “EXXI” prior to its delisting in connection with the commencement of the Chapter 11 proceedings. EXXI Ltd’s common stock resumed trading on the OTC Pink under the symbol “EXXIQ” on April 25, 2016. As a result of filing of the Bankruptcy Petitions, EXXI Ltd’s common stock was suspended from trading on the NASDAQ on April 25, 2016. A Form 25‑NSE was filed with the SEC on May 19, 2016, which removed EXXI Ltd’s securities from listing and registration on NASDAQ. EXXI Ltd’s shareholders were entitled to one vote for each share of common stock held on all matters to be voted on by shareholders. EXXI Ltd had 200,000,000 authorized common shares, par value of $0.005 per share. On April 14, 2016, we received a letter from The NASDAQ Listing Qualifications Staff stating that the Staff has determined that the EXXI Ltd’s securities would be delisted from NASDAQ. The decision was reached by the Staff under NASDAQ Listing Rules 5101, 5110(b) and IM‑5101‑1 as a result of our filing the Bankruptcy Petitions, the associated public interest concerns raised by the Bankruptcy Petitions, concerns regarding the residual equity interest of EXXI Ltd’s listed securities holders and concerns about EXXI Ltd’s ability to sustain compliance with all requirements for continued listing on NASDAQ. On February 24, 2016, EXXI Ltd received a deficiency notice from NASDAQ stating that, based on the closing bid price of its common stock for the prior 30 consecutive business days, EXXI Ltd no longer met the minimum $1.00 per share requirement under NASDAQ Listing Rule 5450(a)(1). Because we did not request an appeal, trading of EXXI Ltd’s common stock was suspended at the opening of business on April 25, 2016, and a Form 25‑NSE was filed with the SEC on May 19, 2016, which removed EXXI Ltd’s securities from listing and registration on NASDAQ. EXXI Ltd’s securities resumed trading on the OTC Markets Group Inc.’s OTC Pink under the symbol “EXXIQ” on April 25, 2016. On December 30, 2016, upon emergence from the Chapter 11 Cases, EXXI Ltd’s common shares were removed from the OTC Market. The Predecessor’s Board adopted a NOL Shareholder Rights Agreement (the “Rights Plan”) designed to preserve substantial tax assets of our U.S. subsidiaries. The Rights Plan is intended to protect our tax benefits and to allow all of our existing shareholders to realize the long-term value of their investment in the Company. As of December 30, 2016, no Rights had been exercised. Predecessor Preferred Stock EXXI Ltd’s bye-laws authorized the issuance of 7,500,000 shares of preferred stock. The Predecessor Board was empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of the holders of common stock. Dividends on both the 5.625% Perpetual Convertible Preferred Stock (“5.625% Preferred Stock”) and the 7.25% Perpetual Convertible Preferred Stock (“7.25% Preferred Stock”) were to be paid in cash, shares of EXXI Ltd’s common stock, or a combination thereof and were payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year. As a result of filing the Bankruptcy Petitions, EXXI Ltd no longer accrued dividends on preferred stock, accordingly, EXXI Ltd suspended the quarterly dividends on the 5.625% Preferred Stock and the 7.25% Preferred Stock effective January 1, 2016. Preferred stock dividends that would have accrued from the Petition Date through December 31, 2016 totaled approximately $5.7 million. As a result of the Plan, there are no assets remaining in EXXI Ltd, and under Bermuda law, preferred stockholders of EXXI Ltd received no payments. EXXI Ltd was dissolved at the conclusion of the Bermuda Proceeding, and as such, the preferred stockholders no longer have any interest in EXXI Ltd as a matter of Bermuda law. Conversion of Preferred Stock During the six months ended December 31, 2016, we cancelled and converted 300,248 shares of our 5.625% Preferred Stock into a total of 3,145,549 shares of common stock using a conversion rate of 10.4765 common shares per preferred share. During the year ended June 30, 2016, we cancelled and converted 150,787 shares of our 5.625% Preferred Stock into a total of 1,579,522 shares of common stock using a conversion rate of 10.4765 common shares per preferred share. During the year ended June 30, 2015, we cancelled and converted a total of 5,000 shares of our 7.25% Preferred Stock into a total of 46,472 shares of common stock using a conversion rate of 9.2940 common shares per preferred share. During the year ended June 30, 2015, we also cancelled and converted one share of our 5.625% Preferred Stock into 11 shares of common stock using a conversion rate of 10.2409 common shares per preferred share.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Information
Supplemental Cash Flow Information	Note 13 – Supplemental Cash Flow Information The following table presents our supplemental cash flow information ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Cash paid for interest $ 14,867 $ 7,493 $ 229,569 $ 243,238 Cash paid for income taxes — — 150 933 The following table presents our non-cash investing and financing activities ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Derivative instruments premium financing $ — $ — $ — $ 12,025 Changes in capital expenditures accrued in accounts payable (1,944) 10,242 (37,151) (168,569) Acquisition of property against joint interest billings receivable (1,500) — — Inventory transferred to oil and natural gas properties — — 7,081 — Changes in asset retirement obligations (59,217) (5,697) (2,583) 49,495 Changes in other property and equipment (327) Monetization of derivative instruments applied to Revolving Credit Facility — — 50,588 —

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2017
Employee Benefit Plans
Employee Benefit Plans	Note 14 – Employee Benefit Plans Successor Long Term Incentive Plan 2016 Long Term Incentive Plan As of the Emergence Date, the Company entered into the Energy XXI Gulf Coast, Inc. 2016 Long Term Incentive Plan (the “2016 LTIP”), which is a comprehensive equity-based award plan as part of the compensation for the Company’s officers, directors, employees and consultants (the “Service Providers”). The total number of shares of our common stock reserved and available for delivery with respect to awards under the 2016 LTIP is 1,859,552 shares (or 5% of the total new equity). The compensation committee (the “Committee”) of the board of directors of the Company (the “Board”) generally administers the 2016 LTIP and will determine the types of equity based awards (which may include stock option, stock appreciation rights, restricted stock, restricted stock units, bonus stock awards, performance awards, other stock based awards or cash awards) and the terms and conditions (including vesting and forfeiture restrictions) of such awards. Awards under the 2016 LTIP will be awarded to the Service Providers selected in the discretion of the Committee; provided, however, that 3% of the 5% total new equity on a fully diluted basis reserved under the 2016 LTIP must be allocated no later than 120 days after the Emergence Date. As of April 29, 2017, the 3% of total new equity had been allocated by the Board. Under the 2016 LTIP, stock options are issued with an exercise price that is not less than the fair market value of our common stock on the date of grant and expire 10 years from the grant date. Stock options that have been granted to date generally vest ratably over a three-year period. The following table sets forth our stock option activity for the year ended December 31, 2017. Weighted Weighted Average Average Remaining Exercise Price Contractual Options Per Share Terms (in years) Outstanding as of December 31, 2016 - $ — — Granted 372,597 28.92 Exercised - - Forfeited (72,448) 28.97 Outstanding as of December 31, 2017 300,149 $ 28.91 9.3 Exercisable on December 31, 2017 — $ — The fair value of the stock options on the date of grant is expensed on a straight-line basis over the applicable vesting period. The Company estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The Company does not have a long history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. As we do not have sufficient historical stock option exercise experience upon which to base an estimate of expected term, we used the simplified method for estimating expected term . The risk-free interest rate is based on the related United States Treasury yield curve for periods within the expected term of the stock options at the time of the grant. The Company does not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero. As of December 31, 2017, we had 3 00,149 unvested stock options and $ 1.7 million in unrecognized compensation cost related to unvested stock options. The cost is expected to be recognized over a weighted-average period of 1.3 years. Under the 2016 LTIP, restricted stock units may be granted from time to time as approved by the Committee. To date, the restricted stock units granted by the Committee have a vesting date up to three years from the date of grant and each restricted stock unit represents a right to receive one share of our common stock. The following table sets forth the activity related to restricted stock units for the year ended December 31, 2017. Restricted Average Stock Grant Date Units Fair Value Outstanding as of December 31, 2016 - $ — Granted 775,344 24.22 Vested (68,814) 24.21 Forfeited (93,730) 24.48 Outstanding as of December 31, 2017 612,800 $ 24.19 The fair value of our restricted stock units equals the market value of the underlying common stock on the date of grant . As of December 31, 2017, we had 612,800 unvested restricted stock units and $ 8.5 million in unrecognized compensation cost related to unvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 1.3 years. The following table sets forth stock-based compensation expense ( in thousands ): Successor Year Ended December 31, 2017 Stock Options $ 1,453 Restricted Stock Units 8,033 Total compensation expense recognized $ 9,486 Predecessor Long Term Incentive Plan Prior to the Emergence Date, the Predecessor Company maintained the Energy XXI Services, LLC 2006 Long-Term Incentive Plan (the “2006 Incentive Plan”) an incentive and retention program for its employees. Participation shares (or “Restricted Stock Units”) were issued from time to time at a value equal to its common share price at the time of issue. The Restricted Stock Units generally vested equally over a three-year period. When vesting occurred, the Predecessor Company paid the employee an amount equal to the Predecessor Company’s then current common share price times the number of Restricted Stock Units. The Predecessor Company also awarded performance units (“Performance Units”), including both time-based performance units (“Time-Based Performance Units”) and Total Shareholder Return (“TSR”) Performance-Based Units (“TSR Performance-Based Units”). Both the Time-Based Performance Units and TSR Performance-Based Units vested equally over a three-year period. In addition, prior to the Emergence Date, the Predecessor Company maintained the director compensation program which provided for an annual stock award in lieu of cash payment, employee stock purchase plan which allowed employees to purchase its common stock at a 15% discount from the lower of the common stock closing price on the first or last day of the offering period and had granted stock options to its certain officers. For the six-month period ended December 31, 2016 and for the years ended June 30, 2016 and June 30, 2015, the Predecessor recognized total compensation expense related to restricted stock units and performance based units of $( 0.05) million, $(2,583) million and $3,939 million, respectively. As a result of the Plan, there were no assets remaining in the Predecessor Company, all common shares of the Predecessor Company were cancelled and its shareholders received no payments with respect to the common shares, and the Predecessor Company was dissolved pursuant to Bermuda law at the conclusion of the Bermuda Proceeding. As a result, all awards under the 2006 Incentive Plan that remained unvested, including performance-based awards and all of share-based compensation plans at the Emergence Date were cancelled. Defined Contribution Plans Prior to the Emergence Date, the Predecessor Company’s employees were covered by a discretionary noncontributory profit sharing plan. The plan provided for annual discretionary employer contributions that could vary from year to year. The Predecessor Company also sponsored a qualified 401(k) Plan that provided for matching. Pursuant to the terms of the Plan, on the Emergence Date we assumed the Predecessor Company’s defined contribution plans. The contributions under these plans were as follows ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2017 2016 2016 2015 Profit Sharing Plan $ — $ — $ — $ — $ (768) 401(k) Plan 1,702 — 638 2,852 3,192 Total contributions $ 1,702 $ — $ 638 $ 2,852 $ 2,424

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions
Related Party Transactions	Note 15 — Related Party Transactions Successor Related Party Transactions On the Emergence Date, the Company entered into a Registration Rights Agreement with the Holders representing 10% or more of the Common Stock outstanding on that date or who acquire 10% or more of the Common Stock outstanding within six months of the Emergence Date. On the Emergence Date, the Company also entered into the Warrant Agreement with Continental Stock Transfer & Trust Company, as Warrant Agent and issued 2,119,889 warrants to holders of the EGC Unsecured Notes Claims and holders of the EPL Unsecured Notes Claims. For more information see Note 12 – “Stockholders’ Equity.” On February 2, 2017, John D. Schiller, Jr., Bruce W. Busmire and Antonio de Pinho resigned as President and CEO, Chief Financial Officer and Chief Operating Officer, respectively. In connection with Mr. Schiller’s termination of employment, the employment-related provisions of Mr. Schiller’s Executive Employment Agreement, dated as of December 30, 2016 (the “Schiller Employment Agreement”) were terminated as of February 2, 2017. Under the Schiller Employment Agreement, Mr. Schiller was entitled to receive the following benefits, subject to his entry into a waiver and release agreement (i) a lump-sum cash severance payment in the amount of $2 million, and (ii) reimbursement for the monthly cost of maintaining health benefits for Mr. Schiller and his spouse and eligible dependents as of the date of his termination for a period of 18 months to the extent Mr. Schiller elects Consolidated Omnibus Budget Reconciliation Act of 1985, as amended (“COBRA”) continuation coverage, less applicable taxes and withholding. The $2 million cash severance payment was made on April 3, 2017, the 60th day after the termination date. Payments and benefits are subject to Mr. Schiller’s continued compliance with certain confidentiality, non-competition, non-solicitation and non-disparagement provisions of the waiver and release agreement. In addition on February 2, 2017, we entered into a consulting agreement (the “Schiller Consulting Agreement”) with Mr. Schiller, pursuant to which Mr. Schiller agreed to serve as a special advisor to the Board during a transition period of up to six months. In consideration for those services, we agreed to pay Mr. Schiller a consulting fee of $50,000 per month for up to six months. All amounts due under Schiller Consulting Agreement have been paid as of August 9, 2017. Prior to their departure from the Company, Mr. Busmire and Mr. de Pinho were not party to employment agreements with us, nor did they participate in a severance plan. We paid Mr. Busmire and Mr. de Pinho severance payments on February 15, 2017 in the amount of $750,000 each, less applicable taxes and withholdings, in consideration for the performance of the terms and conditions set forth in their Resignation Agreement and General Release, including, without limitation, a general release and non-disparagement provision. We have also agreed to reimburse Mr. Busmire and Mr. de Pinho for the monthly cost of maintaining health benefits for Mr. Busmire and Mr. de Pinho and their respective spouses and eligible dependents as of the date of their termination for a period of 18 months to the extent Mr. Busmire and Mr. de Pinho elect COBRA continuation coverage. On August 24, 2017, Hugh A. Menown resigned as Executive Vice President, Chief Accounting Officer and Interim Chief Financial Officer. In connection with his separation from the Company, Mr. Menown was entitled to receive the following severance benefits under the Company’s employee severance plan subject to his entry into a waiver and release of claims agreement: (i) a lump-sum cash severance payment in the amount of $580,000, and (ii) to the extent Mr. Menown elects COBRA continuation coverage, medical and dental benefits for him and his spouse for a period of 12 months after termination, subject to the payment of the same monthly premium he was paying at termination, in each case, less any applicable taxes and withholding. The $580,000 cash severance payment was made on September 1, 2017. In addition on August 24, 2017, we entered into a consulting agreement with Mr. Menown, pursuant to which Mr. Menown has agreed to serve as an advisor to the Company during a transition period of up to six months. In consideration for those services, we agreed to pay Mr. Menown a consulting fee of $28,333.33 per month for up to six months. All amounts due to Mr. Menown have been paid as of February 6, 2018. Predecessor Related Party Transactions Prior to the M21K Acquisition on August 11, 2015, we had a 20% interest in EXXI M21K and accounted for this investment using the equity method. We had provided a guarantee related to the payment of asset retirement obligations and other liabilities of M21K in the EP Energy property acquisition estimated at $65 million and $1.8 million, respectively. For the LLOG Exploration acquisition, we guaranteed payment of asset retirement obligations of M21K estimated at $36.7 million. For the Eugene Island 330 and South Marsh Island 128 properties purchase, we guaranteed payment of asset retirement obligations of M21K estimated at $18.6 million. For these guarantees, M21K agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates. For the years ended June 30, 2016 and 2015, we received $0.3 million and $3.7 million, respectively, related to such guarantees. Prior to the M21K Acquisition, we also received a management fee of $0.98 per BOE produced for providing administrative assistance in carrying out M21K operations. For the years ended June 30, 2016 and 2015, we received management fees of $0.2 million and $3.3 million, respectively. Effective January 15, 2015, the Predecessor Board appointed one of its members, James LaChance, to serve as interim Chief Strategic Officer. In that position, Mr. LaChance pursued discussions with lenders and noteholders to improve our available capital, leverage ratios and average debt maturity, as directed by our Chief Executive Officer, in consultation with the Predecessor Board. Mr. LaChance’s duties as interim Chief Strategic Officer were separate from, and in addition to, his responsibilities as a member of the Board of Directors. In light of the significant increase in the amount of time Mr. LaChance was required to spend performing in that new role, EXXI Ltd and Mr. LaChance entered into an interim Chief Strategic Officer consulting agreement (the “Consulting Agreement”), with an effective date of January 15, 2015. Under the Consulting Agreement, Mr. LaChance was paid $200,000 per month for his services as interim Chief Strategic Officer. The consulting agreement expired on July 15, 2015. For years ended June 30, 2016 and 2015, Mr. LaChance earned and was paid consulting fees of $0.1 million and $1.1 million, respectively, under the Consulting Agreement. In accordance with the Consulting Agreement, Mr. LaChance was also entitled to a success fee if he continuously provided consulting services through the closing of one or a series of transactions to provide us and our affiliates with additional capital of more than $1,000 million. The amount of this success fee was capped at $6 million, with up to $5 million payable upon achievement of objective criteria set forth in the Consulting Agreement and up to an additional $1 million payable in the Predecessor Board’s discretion, based on qualitative factors. The success fee was earned and Mr. LaChance received, on March 12, 2015, 1,644,737 RSUs based on a price of $3.04 per share (the value weighted average price of EXXI Ltd’s common stock for the period from December 1, 2014 through January 31, 2015), representing the full $5 million portion of the success fee. With respect to the discretionary portion of the success fee, the Predecessor Board awarded Mr. LaChance the full $1 million amount on October 15, 2015. Fifty percent of this amount was paid in cash in October 2015 and the other fifty percent was paid in the form of 231,482 RSUs, based on a price of $2.16 per share, which was the closing price of EXXI Ltd’s common stock on October 15, 2015. All of the outstanding 1,876,219 RSUs were settled in cash for $1,182,018 on March 12, 2016 based on a price of $0.63 per share. On October 9, 2015, the Predecessor Board determined that the positions of Chief Executive Officer and Chairman of the Board should be held by two different individuals. As a result of that determination, the Predecessor Board elected Mr. LaChance to serve as Chairman of the Board, effective as of October 15, 2015, to serve in such capacity until the earlier of his resignation or removal. Mr. LaChance did not receive any compensation for serving as Chairman of the Board, other than pursuant to director compensation programs that were applicable to other non-employee directors. During the years ended June 30, 2015 and 2014, the Company’s former Chief Executive Officer and President John D. Schiller, Jr. borrowed funds from personal acquaintances or their affiliates, certain of whom provide services to us (“Vendor Loans”). During the year ended December 31, 2017 certain of those lenders provided services to the Company totaling $10.6 million. During the six months ended December 31, 2016 certain of those lenders provided services to the Company totaling $3.3 million. During the years ended June 30, 2016 and 2015, certain of those lenders provided services to the Predecessor Company totaling $35.9 million and $34.7 million, respectively. During 2014, one of the directors on the Predecessor Board made a personal loan to Mr. Schiller at a time prior to becoming a member of the Predecessor Board but while a managing director at Mount Kellett Capital Management LP, which at the time owned a majority interest in Energy XXI M21K and 6.3% of EXXI Ltd’s common stock. From time to time, we have entered into arrangements in the ordinary course of business with entities in which Cornelius Dupré II, who was appointed to the Predecessor Board in October 2010, had an ownership interest. These entities provide us with oil field services. During the year ended December 31, 2017 and during the six month transition period ended December 31, 2016 no payments were made and during fiscal year ended June 30, 2016 and 2015 EXXI Ltd made aggregate payments of approximately $5.6 million and $2.0 million, respectively to these entities for those services.

Earnings (Loss) per Share

Earnings (Loss) per Share	12 Months Ended
	Dec. 31, 2017
Earnings (Loss) per Share
Earnings (Loss) per Share	Note 16 — Earnings (Loss) per Share Basic earnings (loss) per share of common stock is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the year. Except when the effect would be anti-dilutive, the diluted earnings per share include the impact of convertible preferred stock, convertible notes, restricted stock, stock options and other potential common stock equivalents. The following table sets forth the calculation of basic and diluted (loss) earnings per share (“EPS”) ( in thousands, except per share data ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 Net (loss) income $ (341,010) $ (406,275) $ 2,650,611 $ (1,918,659) $ (2,433,838) Preferred stock dividends — — — 5,194 11,468 Net (loss) income attributable to common stockholders $ (341,010) $ (406,275) $ 2,650,611 $ (1,923,853) $ (2,445,306) Weighted average shares outstanding for basic EPS 33,239 33,212 98,337 95,822 94,167 Add dilutive securities — — 6,450 — — Weighted average shares outstanding for diluted EPS 33,239 33,212 104,787 95,822 94,167 (Loss) earnings per share Basic $ (10.26) $ (12.23) $ 26.95 $ (20.08) $ (25.97) Diluted $ (10.26) $ (12.23) $ 25.30 $ (20.08) $ (25.97) The Company’s restricted stock units granted to the members of the Board during the year ended December 31, 2017 are treated as outstanding for basic loss per share calculations since these shares are entitled to participate in dividends declared on common shares, if any, and undistributed earnings. As participating securities, the shares of restricted stock are included in the calculation of basic EPS using the two-class method. For the year ended December 31, 2017, no net loss was allocated to the participating securities. On December 31, 2017, 3,132,729 shares of potential Successor common stock were excluded from the diluted average shares due to an anti-dilutive effect. On December 31, 2016, 2,119,889 shares of potential Successor common stock were excluded from the diluted average shares due to an anti-dilutive effect. For the years ended June 30, 2016 and 2015, 9,439,104 and 8,642,434 shares of potential common stock, respectively, were excluded from the diluted average shares due to an anti-dilutive effect.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies
Commitments and Contingencies	Note 17 — Commitments and Contingencies Litigation. We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. As described below, most of our pending legal proceedings have been stayed by virtue of filing the Bankruptcy Petitions on April 14, 2016. We do not believe the ultimate resolution of any such actions will have a material effect on our consolidated financial position, results of operations or cash flows. On June 17, 2016, the SEC filed a proof of claim against EXXI Ltd asserting a general unsecured claim in the amount of $3.9 million based on alleged violations of the federal securities laws by EXXI Ltd pertaining to the failure to disclose: (i) certain funds borrowed by our former President and CEO John D. Schiller, Jr. from personal acquaintances or their affiliates, certain of which provided EXXI Ltd and certain of its subsidiaries with services, (ii) a personal loan made to Mr. Schiller by one of the directors on the Predecessor Board at a time prior to becoming a member of the Predecessor Board, (iii) Mr. Schiller’s pledge of EXXI Ltd stock to a certain financial institution and (iv) certain perquisites and compensation to Mr. Schiller, including in connection with certain expense reimbursements. The SEC’s claim against EXXI Ltd has been classified as a general unsecured claim to be paid, if at all, its pro rata share of the approximately $1.5 million General Unsecured Claim Distribution defined in the Plan, and, as such, is subject to the Settlement, Release, Injunction, and Related Provisions contained in Article VIII of the Plan, and also is subject to the Confirmation Order. On February 21, 2018, the SEC withdrew its proof of claim. EGC has been cooperating with the SEC in connection with the issues that gave rise to this EXXI Ltd proof of claim, and intends to continue to do so. Lease Commitments. We have non-cancelable operating leases for office space and other assets that expire through December 31, 2018. In addition, on June 30, 2015, we entered into an agreement to assume the operating lease agreement for the Grand Isle Gathering System from our Predecessor as further described below. As of December 31, 2017, future minimum lease commitments under our operating leases are as follows ( in thousands ): Year Ending December 31, Successor 2018 $ 36,035 2019 36,509 2020 43,545 2021 49,598 2022 48,575 Thereafter 152,176 Total $ 366,438 For the year ended December 31, 2017, rent expense, including rent incurred on short-term leases but excluding the GIGS Lease, (defined below), was approximately $ 24.1 million. For the six month transition period ended December 31, 2016, rent expense, including rent incurred on short-term leases but excluding the GIGS Lease, was approximately $11.9 million. For the years ended June 30, 2016 and 2015, rent expense, including rent incurred on short-term leases but excluding the GIGS Lease, was approximately $6.0 million and $6.4 million, respectively. On June 30, 2015, in connection with the closing of the sale of the Grand Isle Gathering System, Energy XXI GIGS Services, LLC, an indirect wholly-owned subsidiary of the Predecessor Company (the “Tenant”), entered into a triple-net lease (the “GIGS Lease”) with Grand Isle Corridor pursuant to which we will continue to operate the Grand Isle Gathering System. The primary term of the GIGS Lease is 11 years from the closing of the sale, with one renewal option, which will be the lesser of nine years or 75% of the expected remaining useful life of the Grand Isle Gathering System. The operating lease utilizes a minimum rent plus a variable rent structure, which is linked to the oil revenues we realize from the Grand Isle Gathering System above a predetermined oil revenue threshold. During the initial term, we will make fixed minimum monthly rental payments, which vary over the term of the lease. The aggregate annual minimum cash monthly payments for the six month transition period ended December 31, 2016 was approximately $17 million, and such payment amounts average $40.5 million per year over the life of the lease. Under the terms of the GIGS Lease, we retain any revenues generated from transporting third party volumes. Under the terms of the GIGS Lease, we control the operation, maintenance, management and regulatory compliance associated with the Grand Isle Gathering System, and we are responsible for, among other matters, maintaining the system in good operating condition, paying all utilities, insuring the assets, repairing the system in the event of any casualty loss, paying property and similar taxes associated with the system, and ensuring compliance with all environmental and other regulatory laws, rules and regulations. The GIGS Lease also imposes certain obligations on Grand Isle Corridor, including confidentiality of information and keeping the Grand Isle Gathering System free of certain liens. In addition, we have, under certain circumstances, a right of first refusal during the term of the GIGS Lease and for two years thereafter to match any proposed transfer by Grand Isle Corridor of its interest as lessor under the GIGS Lease or its interest in the Grand Isle Gathering System. On December 30, 2016, the Tenant, the Company and Grand Isle Corridor entered into an Assignment and Assumption Agreement pursuant to which the Tenant assigned to the Company its right, title, interest, and obligations in and to the purchase and sale agreement relating to the GIGS. Additionally, EGC assumed the obligations of EXXI Ltd as guarantor of Tenant’s obligations under the GIGS Lease pursuant to the Assignment and Assumption of Guaranty and Release Agreement, dated December 30, 2016. Under the GIGS Lease, an event of default would have been triggered by the Tenant upon (i) the filing by either the Tenant or EXXI Ltd of a Bankruptcy Petition or (ii) the failure of either the Tenant, EXXI Ltd or now EGC to make any payment of principal or interest with respect to certain material debt of the Tenant, EXXI Ltd, as the former guarantor, or EGC after giving effect to any applicable cure period or the failure to perform under an agreement or instrument relating to such material debt (collectively, the “Specified Defaults”). Although the Tenant did not file a voluntary petition for reorganization under Chapter 11, the Debtors’ filing of the Bankruptcy Petitions and failure to comply with our material debt instruments, would, among other things, have allowed Grand Isle Corridor to terminate the Lease. As a result, the Tenant and Grand Isle Corridor entered into a waiver to the GIGS Lease, dated as of April 13, 2016, whereby Grand Isle Corridor waived its right to exercise its remedies set forth under the GIGS Lease in the event of the Specified Defaults, except its ability to exercise observer rights as detailed in the GIGS Lease. Letters of Credit and Performance Bonds. As of December 31, 2017, we had approximately $334.1 million of performance bonds outstanding and $200 million in letters of credit issued to ExxonMobil relating to assets in the Gulf of Mexico. In April 2015, the Predecessor received letters from the BOEM stating that certain of its subsidiaries no longer qualified for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. Accordingly, as of December 31, 2017, approximately $18 2.4 million of our performance bonds are lease and/or area bonds issued to the BOEM, to which the BOEM has access to ensure our commitment to comply with the terms and conditions of those leases. As of December 31, 2017, we also maintained approximately $15 1.7 million in performance bonds issued to predecessor third party assignors including certain state regulatory bodies for wells and facilities pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. As of December 31, 2017, we had $49. 8 million in cash collateral provided to surety companies associated with the bonding requirements of the BOEM and third party assignors. To address the supplemental bonding and other financial assurance concerns expressed to us by the BOEM in April 2015 and thereafter, the Predecessor submitted a long-term financial assurance plan (the “Long-Term Plan”) to the agency. Further, the Predecessor submitted a proposed plan amendment on June 28, 2016 that would revise the executed Long-Term Plan (the “Proposed Plan Amendment”). We continue to work with the BOEM under the Long-Term Plan and the Proposed Plan Amendment. Drilling Rig Commitments. As of December 31, 2017, we have $ 0.6 million committed under a rig contract for recompletions and plugging and abandonment activities with a contract term that ended on January 20, 2018. Subsequent to December 31, 2017, we committed $14 million under two rig contracts with contract terms ranging between two months and six months. Other. We maintain restricted escrow funds as required by certain contractual arrangements. At December 31, 2017, our restricted cash included $25.7 million in cash collateral associated with our bonding requirements, and approximately $6.1 million in a trust for future plugging, abandonment and other decommissioning costs related to the East Bay field that was sold to Whitney Oil & Gas, LLC and Trimont Energy (NOW), LLC on June 30, 2015 and those funds held in trust will be transferred to the buyers of our interests in that field. We and our oil and gas joint interest owners are subject to periodic audits of the joint interest accounts for leases in which we participate and/or operate. As a result of these joint interest audits, amounts payable or receivable by us for costs incurred or revenue distributed by the operator or by us on a lease may be adjusted, resulting in adjustments to our net costs or revenues and the related cash flows. When they occur, these adjustments are recorded in the current period, which generally is one or more years after the related cost or revenue was incurred or recognized by the joint account. We do not believe any such adjustments will be material.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Taxes
Income Taxes	Note 18 — Income Taxes Successor Income Taxes On the Emergence Date, the Predecessor Company engaged in several internal restructuring transactions that: (i) assigned all of Predecessor’s assets (directly or indirectly) to EGC, and (ii) separated EXXI Ltd, Energy XXI (US Holdings) Limited (Bermuda), Energy XXI, Inc., and Energy XXI USA from EGC. This had the effect, among other things, of isolating the original parent-level equity ownership and certain intercompany loans (the “Intercompany Loans”) from EGC. Then, pursuant to the Plan, the prepetition notes other than the 4.14% promissory note of $5.5 million, the Prepetition Revolving Credit Facility and 100% of the EGC stock owned by Energy XXI USA, Inc., were cancelled. Additionally, new EGC shares and warrants were issued to former creditors as set out in the Plan. 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 Internal Revenue Code of 1986, as amended (the “Tax Code”) provides that a debtor in a bankruptcy case (such as the Chapter 11 Cases) 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 Plan (the “Tax Attribute Reduction Rules”). 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. As a result of fresh start accounting, significant historic deferred tax assets and liabilities were reduced, including the liability for accrued outbound 30% withholding tax on the Intercompany Loans from the Predecessor’s Bermuda parent, as these obligations were extinguished in the Plan and are not obligations of the Successor entities. With the NOL carryover being reduced by the Tax Attribute Reduction Rules, the principal deferred tax assets and liabilities of the Successor after fresh-start accounting relate to our oil and gas properties. The remaining tax bases of our oil and natural gas properties are greater than their respective book carrying values as determined in fresh-start accounting and after reflecting 2017 activity such that we have recorded a deferred tax asset for those properties. These adjustments reflect the change in estimate from prior filings resulting from recently filed pre-emergence income tax returns for the Predecessor. We have recorded a deferred tax asset for the asset retirement obligation (which has no tax basis and will be tax deductible or result in additional tax basis in assets when settled) and other items that exceed the deferred tax liability for oil and natural gas properties. As such, we recorded an after-tax valuation allowance of $168 million at December 31, 2016, which results in no net deferred tax asset or liability appearing on our statement of financial position. This increase in net tax basis reflects the change in estimate from prior filings resulting from recently filed pre-emergence income tax returns for the Predecessor. We recorded this valuation allowance at this date after an evaluation of all available evidence (including our recent history of Predecessor losses) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, these deferred tax assets were unrecoverable. After filing of our initial Form 10-K for the year ended December 31, 2016, tax returns for the Predecessor reflecting the effect of the Tax Attribute Reduction rules were filed resulting in total additional tax basis of $633 million. This amount is made up of an increase in the amount of $663 million related to the change in total CODI excluded (as detailed in the table below), less $30 million related to other changes in estimates of tax attributes resulting from the filings of these tax returns that is unrelated to the Tax Attribute Reduction Rules. These changes were primarily due to: changes in estimate of the amount of the CODI realized and excluded from taxable income and an additional NOL being generated by the Predecessor (including entities not a part of the Successor tax group) that absorbed the CODI exclusion net of other adjustments unrelated to the change in estimate of the CODI exclusion. This change in estimate of the effects of CODI coupled with a decrease in tax return-to-provision adjustment in those tax returns resulted in us increasing our valuation allowance by $224 million (after-tax) in the year ended December 31, 2017. The changes in our tax attributes resulting from the excluded CODI as a result of the tax attribute reduction rules is set out in the following table. Successor After Return to Provision As Filed Adjustment (in thousands) Pre-tax reductions in: Net operating loss carryovers $ 486 $ 681 Oil and natural gas properties 1,485 915 EPL stock basis 543 304 Other 67 18 CODI excluded requiring attribute reduction $ 2,581 $ 1,918 Tax Code Sections 382 and 383 provide an annual limitation with respect to the ability of a corporation to utilize its tax attributes, including as the tax basis in certain assets (net unrealized built-in-losses), against future U.S. taxable income in the event of a change in ownership. The Company’s emergence from the Chapter 11 Cases was considered a change in ownership for purposes of Tax Code Section 382. The limitation under the Tax Code is based on the value of the loss corporation as of the Convenience Date, which reflects value after giving effect to the Plan’s steps. However, this and prior ownership changes and resulting annual limitation will have limited, if any, effect on the Company’s NOLs since all of the NOLs were extinguished by the Tax Attribute Reduction Rules. No cash income taxes were paid during the year ended December 31, 2017, and, based upon current commodity pricing and planned development activity, no cash income taxes have been paid or are expected to be paid or owed for the tax year ending December 31, 2017. We have estimated our effective income tax rate for the year to be zero, as we are forecasting a pre-tax loss at this time. We do not believe that our net deferred tax assets are realizable in the future on a more-likely-than-not basis at this time. A post-Emergence Date pre-tax NOL of approximately $339 million resulting from our post-Emergence Date losses represents our only NOL carryforwards. This post-Emergence Date NOL is not subject to limitation in future usage by the ownership changes rules of Tax Code section 382 or the Tax Attribute Reduction Rules resulting from the Plan, but this NOL cannot be carried back to pre-Emergence Date years to create a cash income tax refund. If, however, the Company were to experience post-Emergence Date changes in stock ownership of greater than 50% within any three-year look back period, this post-Emergence Date NOL would be subject to Tax Code section 382 limitations based upon stock value and other factors at such time. Predecessor Income Taxes The Predecessor Company was a Bermuda company and was generally not subject to income tax in Bermuda. It historically operated through its various subsidiaries in the United States, and, accordingly, U.S. income taxes were provided based upon those U.S. operations and U.S. withholding tax on interest owed to its Bermuda parent on intercompany indebtedness. Pursuant to the Restructuring Support Agreement discussed in Note 3– “Chapter 11 Proceedings” the Predecessor filed bankruptcy and dissolution petitions in the United States and Bermuda, respectively, on the Petition Date. These filings generally had no immediate effect on the Predecessor’s income tax year or income tax reporting requirements. The Predecessor’s Bermuda companies recorded income tax expense reflecting 30% U.S. withholding tax on any interest (and interest equivalents) accrued on indebtedness of the U.S. companies held by them through the Petition Date. During the year ended June 30, 2016, and for the six-month period ended December 30, 2016, no cash withholding tax payments were made on interest expense or management fees accrued to the Bermuda entities. During fiscal year 2015, changes in expectations regarding future taxable income, consistent with net losses recorded during the current fiscal year (that are heavily influenced by oil and gas property impairments), caused management to record a net increase in the valuation allowance of $356.8 million resulting in a balance of $379.3 million at June 30, 2015. Due to continuing losses, management recorded an additional valuation allowance of $650 million resulting in a balance of $1,029.3 million at June 30, 2016. This increase to the valuation allowance against net deferred tax assets due to management’s judgment that the existing U.S. federal NOL carryforwards are not, on a more-likely-than-not basis, likely recoverable in future years. Our (loss) income before income taxes attributable to U.S. and non-U.S. operations are as follows ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 U.S. (loss) income $ (341,010) $ (406,275) $ 2,650,611 $ (1,913,626) $ (3,050,659) Non-U.S. (loss) income — — — (5,120) 3,471 (Loss) income before income taxes $ (341,010) $ (406,275) $ 2,650,611 $ (1,918,746) $ (3,047,188) The components of our income tax benefit are as follows ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 Current U.S. $ — $ — $ — $ — $ 933 Non U.S. — — — — — State — — — (87) 99 Total current — — — (87) 1,032 Deferred U.S. — — — — (564,569) State — — — — (49,813) Total deferred — — — — (614,382) Total income tax benefit $ — $ — $ — $ (87) $ (613,350) The following is a reconciliation of statutory income tax expense to our income tax benefit ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 (Loss) income before income taxes $ (341,010) $ (406,275) $ 2,650,611 $ (1,918,746) $ (3,047,188) Statutory rate 35 % 35 % 35 % 35 % 35 % Income tax (benefit) expense computed at statutory rate (119,354) (142,196) 927,714 (671,561) (1,066,516) Reconciling items Federal withholding obligation — — — 8,161 10,331 Nontaxable foreign income — — — 1,791 91 Change in valuation allowance 138,561 142,196 (1,029,335) 650,011 356,798 State income taxes (benefit), net of federal tax benefit — — — (87) (32,314) Non-deductible transaction and restructuring costs 894 — 36,874 — 440 Return to provision adjustments (224,339) — — — — Tax Cuts and Jobs Act of 2017 204,137 — — — — Tax basis in shortfall on partnership dissolution — — — 6,501 — Fresh start adjustments to deferred tax balances: Asset retirement obligation — — 190,715 — — Net operating loss — — 163,027 — — Accrued interest expense — — 115,560 — — Oil and natural gas properties and other property and equipment — — 611,834 — — Deferred state income taxes — — 54,793 — — Withholding taxes — — (81,635) — — Cancellation of stockholders deficit — — (290,665) — — Cancellation of indebtedness income — — (702,972) — — Other fresh start deferred income taxes, net — — 3,284 — — Goodwill impairment — — — — 115,253 Other – Net 101 — 806 5,097 2,567 Income tax benefit $ — $ — $ — $ (87) $ (613,350) For the year ended December 31, 2017, we recorded no income tax expense or benefit. We incurred an additional net operating loss during this period that was reduced by non-deductible restructuring costs, consistent with prior periods. We additionally recognized the return to provision adjustment in CODI from the six-month period ended December 31, 2016 due to the filing of both the year ended June 30, 2016 tax return and the six-month period ended December 30, 2016 tax return. This has no effect on earnings but caused an upward adjustment on our valuation allowance. The most significant difference in the effective tax rate for the Predecessor’s year ended June 30, 2016 that differs from prior year’s activity (apart from changes in the valuation allowance) relates to the non-deductibility of certain bankruptcy restructuring related expenses. Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of deferred taxes are detailed in the table below ( in thousands ): Successor December 31, 2017 2016 Deferred tax assets – non current Oil, natural gas properties and other property and equipment $ 66,297 $ — Asset retirement obligation 139,619 257,988 Tax loss carryforwards on U.S. operations 71,268 — Employee benefit plans 1,698 — Tax partnership activity 676 — Derivative instruments and other 6,839 — Other 19,809 11,120 Total deferred tax assets – non current 306,206 269,108 Deferred tax liabilities Oil, natural gas properties and other property and equipment — (101,463) Total deferred tax liabilities – non current — (101,463) Valuation allowance (306,206) (167,645) Net deferred tax $ — $ — At December 31, 2017, current year activity resulted in an NOL carryover of $3 39 million, which will expire in 2037 if unused. At December 30, 2016, immediately prior to the Emergence Date, the Predecessor had US federal NOL carryforwards of approximately $681 million which were completely eliminated by the Tax Attribution Reduction Rules. We do not have significant state NOL carryforwards from pre-Emergence Date years. Recognizing the late enactment of the Tax Cuts and Jobs Act of 2017 and complexity of accurately accounting for its impact, the SEC in SAB 118 provided guidance that allows registrants to provide a reasonable estimate of the impact of the Tax Cuts and Jobs Act of 2017 in their financial statements and adjust the reported impact in a measurement period not to exceed one year. While we believe we have recorded the predominate effects of the Tax Cuts and Jobs Act of 2017 in provisional accounting the fourth quarter of 2017 (related to the corporate tax rate decrease from 35% to 21%), we continue to assess the impact of the Tax Cuts and Jobs Act of 2017 on our business in order to complete our analysis. Any adjustment to the provisional amounts recorded during the year ended December 31, 2017 will be reported in the reporting period in which any such adjustments are determined in the period in which the adjustments are made. Neither the Predecessor nor the Successor has recorded reserves for uncertain tax positions. The Predecessor filed initial tax returns for the tax year ended June 30, 2006 as well as the returns for the tax years ended June 30, 2007 through 2015. The statute of limitations for examination of NOLs and other similar attribute carryforwards does not begin to run until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under U.S. federal tax law. On January 12, 2015, the U.S. Internal Revenue Service formally notified management that they had completed their examination of the U.S. federal income tax return for the year ended June 30, 2013, and that no changes were proposed to the tax reported (zero) or any tax attribute carried forward.

Concentrations of Credit Risk

Concentrations of Credit Risk	12 Months Ended
	Dec. 31, 2017
Concentration of Credit Risk
Concentrations of Credit Risk	Note 19 — Concentrations of Credit Risk Major Customers . We market substantially all of our oil and natural gas production from the properties we operate. We also market more than half of our oil and natural gas production from the fields we do not operate. The majority of our operated natural gas, oil and condensate production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices. Chevron USA (“Chevron”), Shell Trading Company (“Shell”), Plains Marketing, LP (“Plains”) and Trafigura Trading, LLC (“Trafigura”) accounted for approximately 26%, 25%, 18% and 12%, respectively, of our total oil and natural gas revenues during year ended December 31, 2017. Trafigura, Chevron and Shell accounted for approximately 27%, 26%, and 26%, respectively, of our total oil and natural gas revenues during the six months ended December 31, 2016. Trafigura accounted for approximately 22% of our total oil and natural gas revenues during the year ended June 30, 2016. Chevron accounted for approximately 22% and 24% of our total oil and natural gas revenues during the years ended June 30, 2016 and 2015, respectively. Shell accounted for approximately 21% and 29% of our total oil and natural gas revenues during the years ended June 30, 2016 and 2015, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 26% of our total oil and natural gas revenues during the year ended June 30, 2015. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the event that Trafigura, Chevron or Shell curtailed their purchases. Accounts Receivable . Substantially all of our accounts receivable result from oil and natural gas sales and joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Derivative Instruments . Derivative instruments also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and other substantive counterparties who are also a part of our bank lending group. We monitor the creditworthiness of our hedge counterparties and during the year ended December 31, 2017, we did not have any event of nonperformance by our counterparties. At December 31, 2016 and June 30, 2016, we had no derivative instruments outstanding. Cash and Cash Equivalents . We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents with major high credit quality financial institutions. At times cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation. Geographic Concentration. Virtually all of our current operations and proved reserves are concentrated in the Gulf of Mexico region. Therefore, we are exposed to operational, regulatory and other risks associated with the Gulf of Mexico, including the risk of adverse weather conditions. We maintain insurance coverage against some, but not all, of the operating risks to which our business is exposed.

Fair Value

Fair Value	12 Months Ended
	Dec. 31, 2017
Fair Value
Fair Value	Note 20 — Fair Value Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy: · Level 1 – quoted prices in active markets for identical assets or liabilities. · Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs). · Level 3 – unobservable inputs that reflect our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability. For cash and cash equivalents, restricted cash, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and certain notes payable, the carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. The carrying value of the Exit Facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy. Upon adoption of fresh start accounting, the non-recurring fair value adjustment related to our property and equipment, asset retirement obligation and common stock warrants was $1,007.4 million, $185.6 million and $8.1 million, respectively using Level 3 inputs within the fair value hierarchy. See Note 4 – “Fresh Start Accounting.” Our commodity derivative instruments historically consisted of financially settled crude oil and natural gas puts, swaps, put spreads, zero-cost collars and three way collars. We estimated the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published London Interbank offered rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 11 – “Derivative Financial Instruments.” The fair value of our restricted stock units equals the market value of the underlying common stock on the date of grant . For our stock options, we utilize the Black-Scholes-Merton model to determine fair value, which incorporates various assumptions listed here to value the stock option awards. The dividend yield on our common stock was zero. The expected volatility is based on comparable companies’ asset volatilities. The risk-free interest rate is the related United States Treasury yield curve for periods within the expected term of the option at the time of grant. The results of the Monte Carlo simulation model are used for Predecessor’s TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on the valuation of the TSR Performance-Based Units. During the year ended December 31, 2017, six months ended December 31, 2016 and the year ended June 30, 2016, we did not have any transfers from or to Level 3. The following table presents the fair value of our Level 2 financial instruments ( in thousands ): Successor Level 2 As of As of December 31, December 31, 2017 2016 Assets: Oil and natural gas derivatives $ — $ — Liabilities: Oil and natural gas derivatives $ 32,567 $ — The following table sets forth the carrying values and estimated fair values of our long-term debt instruments which are classified as Level 2 financial instruments ( in thousands ): Successor December 31, 2017 2016 Carrying Value Estimated Carrying Value Estimated Exit Facility $ 73,996 $ 73,996 $ 73,996 $ 73,996 Total $ 73,996 $ 73,996 $ 73,996 $ 73,996 (1) In accordance with the Plan, on the Emergence Date, all outstanding obligations under these notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled. The following table sets forth our Level 3 financial instruments ( in thousands ): Predecessor Six Months Ended Year Ended Year Ended December 31, June 30, June 30, 2016 2016 2015 Liabilities: Performance-based performance units Balance at beginning of period $ — $ 33 $ 6,910 Vested — (775) — Grants charged to general and administrative expense — 760 (6,877) Balance at end of period $ — $ 18 $ 33

Prepayments and Accrued Liabili

Prepayments and Accrued Liabilities	12 Months Ended
	Dec. 31, 2017
Prepayments and Accrued Liabilities
Prepayments and Accrued Liabilities	Note 21 — Prepayments and Accrued Liabilities Prepayments and accrued liabilities consist of the following ( in thousands ): Successor December 31, 2017 2016 Prepaid expenses and other current assets Advances to joint interest partners $ 1,381 $ 650 Insurance 5,949 9,600 Inventory 394 470 Royalty deposit 1,021 1,273 Other 12,857 5,987 Total prepaid expenses and other current assets $ 21,602 $ 17,980 Accrued liabilities Advances from joint interest partners 81 374 Employee benefits and payroll 6,791 4,491 Interest payable 185 233 Accrued hedge payable 2,491 — Undistributed oil and gas proceeds 20,079 22,715 Severance taxes payable 558 628 Escrowed reorganization expenses — 25,987 Other 15,309 1,247 Total accrued liabilities $ 45,494 $ 55,675

Comparative Period Information

Comparative Period Information	12 Months Ended
	Dec. 31, 2017
Comparative Period Information
Comparative Period Information	Note 22 — Comparative Period Information The following tables present certain transition and comparative period financial information for the six-month period ended December 31, 2016 and 2015, respectively. We made adjustments to correct immaterial misstatements for the six months ended December 31, 2016. For a detailed explanation of these adjustments, see Note 2 — “Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements.” Predecessor Six Months Ended December 31, 2016 (1) 2015 (2) (Unaudited) (In thousands) Total Revenues $ 296,686 $ 442,438 Operating loss (70,534) (2,431,348) Income (loss) before income taxes 2,650,611 (1,883,924) Income tax expense (benefit) — 51 Net Income (loss) $ 2,650,611 $ (1,883,975) Preferred stock dividends — 5,664 Net Income (Loss) Attributable to Common Stockholders $ 2,650,611 $ (1,889,639) Earnings (Loss) per Share Basic $ 26.95 $ (19.91) Diluted $ 25.30 $ (19.91) Weighted Average Number of Common Shares Outstanding Basic 98,337 94,926 Diluted 104,787 94,926 Predecessor Six Months Ended December 31, 2016 (1) 2015 (2) (Unaudited) (In thousands) Net cash used in operating activities $ (17,473) $ (89,924) Net cash provided by (used in) investing activities 11,706 (82,872) Net cash used in financing activities (32,123) (258,162) Net decrease in cash and cash equivalents $ (37,890) $ (430,958) (1) Included in Operating income (loss) is impairment of oil and natural gas properties of $86.8 million and also included in Net income (loss) are reorganization items being gain on settlement of liabilities subject to compromise of $ 1.983.9 million, fair value adjustment of $8 40.3 and reorganization expenses of $90.6 million. (1) (2) Included in Operating income (loss) is impairment of oil and natural gas properties of $2,330.5 million and also included in Net income (loss) is gain on early extinguishment of debt of $748.6 million.

Selected Quarterly Financial Da

Selected Quarterly Financial Data – Unaudited	12 Months Ended
	Dec. 31, 2017
Selected Quarterly Financial Data – Unaudited
Selected Quarterly Financial Data – Unaudited	Note 23 — Selected Quarterly Financial Data – Unaudited Unaudited quarterly financial data are as follows ( in thousands, except per share amounts ): Successor Quarter Ended December 31, (2) September 30, June 30, March 31, (3) 2017 2017 2017 2017 Revenues $ 93,838 $ 115,701 $ 144,019 $ 158,086 Operating loss (211,462) (31,556) (22,675) (60,735) Net loss $ (215,069) $ (35,157) $ (26,237) $ (64,547) Net loss per share (1) Basic and Diluted $ (6.47) $ (1.06) $ (0.79) $ (1.94) (1) The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income (loss) for that quarter and the weighted average number of shares outstanding during that quarter. (2) Included in Operating loss is impairment of oil and natural gas properties of $1 45.1 million. (3) Included in Operating loss is impairment of oil and natural gas properties of $40.8 million. We made adjustments to correct immaterial misstatements within our previously reported quarterly financial statements. These immaterial misstatements affected certain line items within the cash flow from operations section and did not change the total amount of previously reported cash flows. For a detailed explanation of these adjustments, please see Note 2 “—Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements.” Predecessor Quarter Ended December 31, (7) September 30, (6) June 30, (2) March 31, (3) December 31, (4) September 30, (5) 2016 2016 2016 2016 2015 2015 Revenues $ 153,723 $ 142,963 $ 148,395 $ 116,285 $ 184,615 $ 257,823 Operating income (loss) 12,795 (83,329) (168,119) (417,866) (1,513,148) (918,200) Net income (loss) $ 2,771,349 $ (120,738) $ (195,460) $ 160,776 $ (1,310,583) $ (573,392) Preferred stock dividends — — (2,848) 2,378 2,810 2,854 Net income (loss) attributable to common stockholders $ 2,771,349 $ (120,738) $ (192,612) $ 158,398 $ (1,313,393) $ (576,246) Net income (loss) per share attributable to common stockholders (1) Basic $ 28.04 $ (1.23) $ (1.97) $ 1.65 $ (13.81) $ (6.08) Diluted 26.45 (1.23) (1.97) 1.55 (13.81) (6.08) (1) The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. (2) Included in Operating loss is impairment of oil and natural gas properties of $143.1 million. (3) Included in Operating loss is impairment of oil and natural gas properties of $340.5 million and also included in Net loss is gain on early extinguishment of debt of $777.0 million. (4) Included in Operating loss is impairment of oil and natural gas properties of $1,425.8 million and also included in Net loss is gain on early extinguishment of debt of $290.3 million. (5) Included in Operating loss is impairment of oil and natural gas properties of $904.7 million and also included in Net loss is gain on early extinguishment of debt of $458.3 million. (6) Included in Operating loss is impairment of oil and natural gas properties of $77.6 million and also included in Net loss is reorganization expenses of $32.6 million. (7) Included in Net income are gain on settlement of liabilities subject to compromise of $ 1,983.9 million, fair value adjustment gain of $840.3 million and reorganization expenses of $58.0 million. The effect of these adjustments in our consolidated quarterly income statements was as follows: Successor Successor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 As reported Adjustments As Revised As reported Adjustments As Revised Revenues Oil sales $ 114,991 $ (1,294) $ 113,697 $ 366,792 $ (818) $ 365,974 Natural gas liquids sales 2,209 — 2,209 6,806 — 6,806 Natural gas sales 12,261 — 12,261 44,382 — 44,382 Gain on derivative financial instruments (12,466) — (12,466) 644 — 644 Total Revenues 116,995 (1,294) 115,701 418,624 (818) 417,806 Costs and Expenses Lease operating 77,822 — 77,822 238,315 429 238,744 Production taxes 471 — 471 1,192 — 1,192 Gathering and transportation (2,441) — (2,441) 11,459 — 11,459 Pipeline facility fee 10,495 — 10,495 31,483 — 31,483 Depreciation, depletion and amortization 36,066 65 36,131 116,733 (21) 116,712 Accretion of asset retirement obligations 9,892 (139) 9,753 32,339 479 32,818 Impairment of oil and natural gas properties (2,357) 2,357 — 40,849 (75) 40,774 General and administrative expense 15,026 — 15,026 57,346 — 57,346 Reorganization items — — — (1,529) 3,773 2,244 Total Costs and Expenses 144,974 2,283 147,257 528,187 4,585 532,772 Operating Loss (27,979) (3,577) (31,556) (109,563) (5,403) (114,966) Other Income (Expense) Other income, net 52 — 52 154 — 154 Interest expense (3,653) — (3,653) (11,129) — (11,129) Total Other Expense , net (3,601) — (3,601) (10,975) — (10,975) Loss Before Income Taxes (31,580) (3,577) (35,157) (120,538) (5,403) (125,941) Income Tax Expense — — — — — — Net Loss $ (31,580) $ (3,577) $ (35,157) $ (120,538) $ (5,403) $ (125,941) Loss per Share Basic and Diluted $ (0.95) $ (0.11) $ (1.06) $ (3.63) $ (0.16) $ (3.79) Weighted Average Number of Common Shares Outstanding Basic and Diluted 33,241 33,241 33,241 33,236 33,236 33,236 Successor Successor Three Months Ended June 30, 2017 Six Months Ended June 30, 2017 As reported Adjustments As Revised As reported Adjustments As Revised Revenues Oil sales $ 118,180 $ 304 $ 118,484 $ 251,801 $ 476 $ 252,277 Natural gas liquids sales 2,370 — 2,370 4,597 — 4,597 Natural gas sales 13,753 — 13,753 32,121 — 32,121 Gain on derivative financial instruments 9,412 — 9,412 13,110 — 13,110 Total Revenues 143,715 304 144,019 301,629 476 302,105 Costs and Expenses Lease operating 85,336 (1,681) 83,655 160,493 429 160,922 Production taxes 482 — 482 721 — 721 Gathering and transportation 2,678 — 2,678 13,900 — 13,900 Pipeline facility fee 10,494 — 10,494 20,988 — 20,988 Depreciation, depletion and amortization 38,661 24 38,685 80,667 (86) 80,581 Accretion of asset retirement obligations 10,050 (66) 9,984 22,447 618 23,065 Impairment of oil and natural gas properties (848) 848 — 43,206 (2,432) 40,774 General and administrative expense 20,716 — 20,716 42,320 — 42,320 Reorganization items (3,773) 3,773 — (1,529) 3,773 2,244 Total Costs and Expenses 163,796 2,898 166,694 383,213 2,302 385,515 Operating Loss (20,081) (2,594) (22,675) (81,584) (1,826) (83,410) Other Income (Expense) Other income, net 80 — 80 102 — 102 Interest expense (3,642) — (3,642) (7,476) — (7,476) Total Other Expense , net (3,562) — (3,562) (7,374) — (7,374) Loss Before Income Taxes (23,643) (2,594) (26,237) (88,958) (1,826) (90,784) Income Tax Expense — — — — — — Net Loss $ (23,643) $ (2,594) $ (26,237) $ (88,958) $ (1,826) $ (90,784) Loss per Share Basic and Diluted $ (0.71) $ (0.08) $ (0.79) $ (2.68) $ (0.05) $ (2.73) Weighted Average Number of Common Shares Outstanding Basic and Diluted 33,237 33,237 33,237 33,234 33,234 33,234 Successor Three Months Ended March 31, 2017 As reported Adjustments As Revised Revenues Oil sales $ 133,621 $ 172 $ 133,793 Natural gas liquids sales 2,227 — 2,227 Natural gas sales 18,368 — 18,368 Gain on derivative financial instruments 3,698 — 3,698 Total Revenues 157,914 172 158,086 Costs and Expenses Lease operating 75,157 2,110 77,267 Production taxes 239 — 239 Gathering and transportation 11,222 — 11,222 Pipeline facility fee 10,494 — 10,494 Depreciation, depletion and amortization 42,006 (110) 41,896 Accretion of asset retirement obligations 12,397 684 13,081 Impairment of oil and natural gas properties 44,054 (3,280) 40,774 General and administrative expense 23,848 — 23,848 Total Costs and Expenses 219,417 (596) 218,821 Operating Loss (61,503) 768 (60,735) Other Income (Expense) Other income, net 22 — 22 Interest expense (3,834) — (3,834) Total Other Expense , net (3,812) — (3,812) Loss Before Income Taxes (65,315) 768 (64,547) Income Tax Expense — — — Net Loss $ (65,315) $ 768 $ (64,547) Loss per Share Basic and Diluted $ (1.97) $ 0.02 $ (1.94) Weighted Average Number of Common Shares Outstanding Basic and Diluted 33,228 33,228 33,228 Predecessor Three Months Ended December 31, 2016 As reported Adjustments As Revised Revenues $ 153,065 $ 658 $ 153,723 Operating income 11,708 1,087 12,795 Net income $ 2,785,049 (13,700) $ 2,771,349 Income per Share Basic $ 28.17 $ (0.14) $ 28.04 Diluted $ 26.58 $ (0.13) $ 26.45 Weighted Average Number of Common Shares Outstanding Basic 98,850 98,850 98,850 Diluted 104,787 104,787 104,787 Predecessor Three Months Ended September 30, 2016 As reported Adjustments As Revised Revenues Oil sales $ 122,732 $ 352 $ 123,084 Natural gas liquids sales 2,144 — 2,144 Natural gas sales 17,735 — 17,735 Gain on derivative financial instruments — — — Total Revenues 142,611 352 142,963 Costs and Expenses Lease operating 65,170 — 65,170 Production taxes 214 — 214 Gathering and transportation 7,534 — 7,534 Pipeline facility fee 10,165 — 10,165 Depreciation, depletion and amortization 31,573 (432) 31,141 Accretion of asset retirement obligations 19,437 (362) 19,075 Impairment of oil and natural gas properties 86,820 (9,262) 77,558 General and administrative expense 15,435 — 15,435 Total Costs and Expenses 236,348 (10,056) 226,292 Operating Loss (93,737) 10,408 (83,329) Other Income (Expense) Other income, net 62 — 62 Interest expense (4,838) — (4,838) Total Other Expense , net (4,776) — (4,776) Loss Before Reorganization Items and Income Taxes (98,513) 10,408 (88,105) Reorganization items (32,633) — (32,633) Loss Before Income Taxes (131,146) 10,408 (120,738) Income Tax Expense — — — Net Loss $ (131,146) $ 10,408 $ (120,738) Loss per Share Basic and Diluted $ (1.34) $ 0.11 $ (1.23) Weighted Average Number of Common Shares Outstanding Basic and Diluted 97,824 97,824 97,824

Supplementary Oil and Gas Infor

Supplementary Oil and Gas Information – Unaudited	12 Months Ended
	Dec. 31, 2017
Supplementary Oil and Gas Information – Unaudited
Supplementary Oil and Gas Information – Unaudited	Note 24 – Supplementary Oil and Gas Information – Unaudited The supplementary data presented reflects information for all of our oil and natural gas producing activities. Costs incurred for oil and natural gas property acquisition, exploration and development activities are as follows ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Property acquisitions Proved $ 96 $ 1,500 $ 26,400 $ — Unevaluated — — — 2,304 Exploration costs 669 — 1,400 38,183 Development costs 62,283 22,300 57,400 608,605 Oil and natural gas property costs excluded from the amortization base represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs associated with unevaluated properties, all of which were recorded as part of fresh start accounting, are transferred to evaluated properties either (i) ratably over a period of the related field’s life, or (ii) upon determination as to whether there are any proved reserves related to the unevaluated properties or the costs are impaired or capital costs associated with the development of these properties will not be available. As of December 31, 2017, we have 22 MMBOE in proved undeveloped reserves. Future development costs associated with our proved undeveloped reserves at December 31, 2017 totaled approximately $356.1 million. Estimated Net Quantities of Oil and Natural Gas Reserves As of December 31, 2017 the estimates of the net proved oil and natural gas reserves of our oil and natural gas properties located entirely within the U.S. are based on evaluations prepared by NSAI. From June 30, 2013 through June 30, 2016, the Company utilized third-party engineers to audit its internal calculations of reserves and as of December 31, 2016, the reserve quantities were estimated and compiled by its internal reservoir engineers. The Company did not have a fully-engineered third-party report prepared since 2012. Under the terms of its First Lien Exit Credit Agreement executed in 2016, a third party engineer report was required annually, with the first report due by May 31, 2017. As a result, we had a fully-engineered report prepared by NSAI as of March 31, 2017 and the Company plans to have any future annual reserve reports fully-engineered by a third-party engineering firm. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available. Estimated quantities of proved domestic oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves in thousands of barrels (“MBbls”) and millions of cubic feet (“MMcf”) for each of the periods indicated were as follows: Natural Gas Oil Liquids Natural Gas Total (MBbls) (MBbls) (MMcf) (MBOE) Proved reserves at June 30, 2014 (Predecessor) 175,816 9,573 364,856 246,198 Production (14,272) (987) (37,472) (21,504) Extensions, discoveries and other additions 10,056 517 40,330 17,295 Revisions of previous estimates (32,115) (1,615) (75,617) (46,333) Sales of reserves (9,889) (12) (13,554) (12,160) Proved reserves at June 30, 2015 (Predecessor) 129,596 7,476 278,543 183,496 Production (12,624) (923) (33,973) (19,209) Extensions, discoveries and other additions 1,370 46 1,729 1,704 Revisions of previous estimates (61,347) (3,237) (158,681) (91,031) Purchases of reserves 5,145 871 33,529 11,604 Proved reserves at June 30, 2016 (Predecessor) 62,140 4,233 121,147 86,564 Production (5,482) (167) (13,485) (7,897) Extensions, discoveries and other additions 31,846 375 27,788 36,852 Revisions of previous estimates 6,746 (1,293) 5,788 6,418 Proved reserves at December 31, 2016 (Successor) 95,250 3,148 141,238 121,937 Production (9,324) (288) (17,282) (12,493) Extensions, discoveries and other additions 5,691 217 7,030 7,082 Revisions of previous estimates (17,261) (1,397) (58,001) (28,327) Proved reserves at December 31, 2017 (Successor) 74,356 1,680 72,985 88,199 Proved developed reserves June 30, 2014 (Predecessor) 106,900 5,889 222,916 149,942 June 30, 2015 (Predecessor) 88,607 5,406 187,993 125,345 June 30, 2016 (Predecessor) 62,140 4,233 121,147 86,564 December 31, 2016 (Successor) 63,728 2,777 113,603 85,439 December 31, 2017 (Successor) 55,005 1,335 58,918 66,160 Proved undeveloped reserves June 30, 2014 (Predecessor) 68,916 3,684 141,940 96,256 June 30, 2015 (Predecessor) 40,989 2,070 90,550 58,151 June 30, 2016 (Predecessor) — — — — December 31, 2016 (Successor) 31,522 371 27,635 36,498 December 31, 2017 (Successor) 19,351 345 14,067 22,039 Our proved reserves decreased by 33.7 MMBOE or by approximately 28% from 121.9 MMBOE at December 31, 2016 to 88.2 MMBOE as of December 31, 2017. The decrease was primarily due to: · 17.4 MMBOE of negative revisions of proved undeveloped reserves. These reserves were written off primarily due to updated technical assessments of undeveloped reserves and, due to delayed drilling activity during 2017 and changes to the Company’s drilling schedule, the SEC’s requirement that undeveloped reserves be developed within five years of the initial booking. · 12.5 MMBOE of production during the period. · 10.7 MMBOE of reserves that became uneconomic due to increased estimates of lease operating expenses. · 9.6 MMBOE of negative revisions of proved developed non-producing reserves. Of these negative revisions, 4.2 MMBOE were primarily due to the revised drilling schedule truncating proved economic field lives and 5.2 MMBOE were due to updated technical assessments. These were offset by: · 7.1 MMBOE of new reserves that were added after technical reviews of the assets. · Upward revisions of 7.0 MMBOE of reserves due to increased product prices and improved field economics. · Upward revisions of 3.3 MMBOE of proved developed producing reserves due to performance. As of December 31, 2017, we have 22 MMBOE in proved undeveloped reserves. Future development costs associated with our proved undeveloped reserves at December 31, 2017 totaled approximately $356.1 million. As scheduled in our long range plan, all of our proved undeveloped locations are expected to be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report. Standardized Measure of Discounted Future Net Cash Flows Future cash inflows as of December 31, 2017 were computed using the following prices: the average oil price prior to quality, transportation fees, and regional price differentials was $47.79 per barrel of oil (calculated using the unweighted average first-day-of-the-month West Texas Intermediate posted prices during the 12‑month period ending on December 31, 2017). The report forecasts crude oil and NGL production separately. The average realized adjusted product prices weighted by production over the remaining lives of the properties, used to determine future net revenues were $50.99 per barrel of oil and $26.79 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials. For natural gas, the average Henry Hub price used was $2.98 per MMBtu, prior to adjustments for energy content, transportation fees, and regional price differentials (calculated using the unweighted average first-day-of-the-month Henry Hub spot price). The average adjusted realized natural gas price, weighted by production over the remaining lives of the properties used to determine future net revenues, was $2.85 per Mcf after adjusting for energy content, transportation fees, and regional price differentials. The standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves follows ( in thousands ): Successor Predecessor As of As of As of December 31, December 31, June 30, 2017 2016 2016 2015 Future cash inflows $ 4,044,208 $ 4,344,985 $ 2,966,317 $ 10,641,151 Less related future Production costs 2,714,819 2,648,363 2,223,645 4,131,526 Development and abandonment costs 1,425,847 1,571,271 1,033,717 1,970,526 Income taxes — — — 168,655 Future net cash flows (96,458) 125,351 (291,045) 4,370,444 Less: Ten percent annual discount for estimated timing of cash flows (111,594) (23,494) (349,398) 1,613,034 Standardized measure of discounted future net cash flows (Predecessor) $ 58,353 $ 2,757,410 Standardized measure of discounted future net cash flows (Successor) $ 15,136 $ 148,845 The increase in our proved reserves had a significant impact on our estimated standardized measure values of the proved reserves which increased from approximately $58.4 million as of June 30, 2016 to approximately $1 48.8 million as of December 31, 2016, mainly due to the following: · The booking of 36.5 MMBOE of proved undeveloped reserves from contingent resource category, and · The increase in proved developed reserves value resulting from greater economic field life due to the booking of proved undeveloped reserves and the delay of significant abandonment costs for all fields. The discounted PV‑10 of the properties as of December 31, 2017, December 31, 2016 and June 30, 2016 are higher than the undiscounted value due to the projected significant plugging and abandonment activity at the end of the life of the properties that are heavily discounted. Changes in Standardized Measure of Discounted Future Net Cash Flows A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves follows ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Beginning of period (Predecessor) $ 148,845 $ 58,353 $ 2,757,410 $ 5,947,525 Revisions of previous estimates Changes in prices and costs 252,357 (104,993) (3,287,459) (2,959,883) Changes in quantities (198,211) 53,585 (214,631) (2,390,099) Additions to proved reserves resulting from extensions, discoveries, other additions and improved recovery, less related costs 8,908 325,892 26,911 201,234 Purchases (sales) of reserves in place — — 212,961 (244,507) Accretion of discount 14,885 (893) 215,297 760,175 Sales, net of production and gathering and transportation costs (224,976) (131,947) (212,581) (676,949) Net change in income taxes — — 77,025 1,576,954 Changes in rate of production and other (22,862) (2,704) 4,189 (191,668) Development costs incurred 3,878 11,283 10,493 237,173 Changes in estimated future development and abandonment costs 32,312 (59,731) 468,738 497,455 Net change (133,709) 90,492 (2,699,057) (3,190,115) End of period (Predecessor) $ 58,353 $ 2,757,410 End of period (Successor) $ 15,136 $ 148,845

Revision of Prior Period Fina33

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements (Policies)	12 Months Ended
	Dec. 31, 2017
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements
Revision of Prior Period Financial Statements	Revision of Prior Period Financial Statements During the following periods, we identified prior period pre-tax adjustments affecting the statements of operations: Year ended June 30, 2016. Preferred stock dividends were decreased by $3.2 million to reverse the previously accrued but not declared preferred stock dividend. Six Months Ended December 31, 2016. · Oil sales were increased by $1.0 million to reflect revenue associated with pipeline tariffs. · Impairment of oil and natural gas properties was decreased by $9.0 million, resulting from the reduction of asset retirement obligations and related oil and natural gas property balances of the same amount. As we were in a ceiling test impairment position at September 30, 2016, all adjustments to our asset retirement obligations through September 30, 2016 directly impacted the statement of operations for the six months ended December 31, 2016. · Reorganization items were decreased by $ 14.8 million, which is the net impact of adjustments on fresh-start accounting as of the Convenience Date. At December 31, 2016, the cumulative amount of all statement of operations adjustments for both the year ended June 30, 2016 and six months ended December 31, 2016, was $21.4 million. This amount was offset by reorganization and fresh start accounting adjustments for the Predecessor and was an adjustment to Successor’s opening equity. In evaluating whether the previously issued financial statements were materially misstated, the Company applied the guidance in Securities and Exchange Commission (“SEC”) Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements . SAB No. 108 states that registrants must quantify the impact of correcting all misstatements, including both the carryover (iron curtain method) and reversing (rollover method) effects of prior-year misstatements on the current-year consolidated financial statements, and evaluate the misstatements measured under each method in light of quantitative and qualitative factors. Under SAB No. 108, prior-year misstatements which, if corrected in the current year would be material to the current year, must be corrected by adjusting prior year financial statements, even though such correction previously was and continues to be immaterial to the prior-year financial statements. Correcting prior-year financial statements for such “immaterial misstatements” does not require previously filed reports to be amended. In accordance with accounting guidance presented in ASC 250-10 (SEC Staff Accounting Bulletin No. 99, Materiality), the Company assessed the materiality of the misstatements and concluded that they were not material to any of the Predecessor Company’s previously issued consolidated financial statements. The correction of immaterial misstatements did not have any impact on previously reported oil and natural gas reserve volumes and where applicable, the corrections have been reflected throughout the accompanying notes to the consolidated financial statements.
Principles of Consolidation and Reporting	Principles of Consolidation and Reporting. The accompanying consolidated financial statements on December 31, 2017 include the accounts of EGC and its wholly-owned subsidiaries and for the prior periods, the accompanying consolidated financial statements include the accounts of EXXI Ltd and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. The Predecessor’s consolidated financial statements for the prior periods include certain reclassifications, including a $ 6.7 million, $ 17.9 million and $1 3.6 million reclassification from lease operating expenses to gathering and transportation expenses and a $ 21.0 million, $40.7 million and $0.0 million reclassification from gathering and transportation expenses to pipeline facility fee expense for the six month period ended December 31, 2016 and for the years ended June 30, 2016 and 2015, respectively, to conform to the current presentation. Those reclassifications did not have any impact on the Predecessor’s previously reported consolidated result of operations or cash flows. For periods subsequent to filing the Bankruptcy Petitions until the Emergence Date, we have prepared the Predecessor’s consolidated financial statements in accordance with ASC 852. 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.
Fresh-start Accounting	Fresh-start Accounting. Upon emergence from bankruptcy, in accordance with ASC 852 related to fresh-start accounting, EGC became a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Convenience Date. The effects of the Plan and the application of fresh-start accounting were reflected in our consolidated balance sheet as of December 31, 2016 and the related adjustments thereto were recorded in the consolidated statement of operations of the Predecessor as reorganization items during the six month transition period ended December 31, 2016. Accordingly, EGC’s consolidated financial statements as of and subsequent to December 31, 2016 are not and will not be comparable to the Predecessor consolidated financial statements prior to the Convenience Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented as of December 31, 2017 and prior periods. Although our accounting policies are the same as that of our Predecessor’s, our financial results for future periods following the application of fresh-start accounting will be different from historical trends, and the differences may be material.
Use of Estimates	Use of Estimates. The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. The Predecessor’s proved reserves quantities of 86.6 MMBOE as of June 30, 2016 were estimated and compiled by its internal reservoir engineers and audited by Netherland, Sewell & Associates, Inc., independent oil and gas consultants (“NSAI”). As of December 31, 2016, proved reserves quantities of 121.9 MMBOE were independently estimated and compiled by our internal reservoir engineers. Pursuant to the terms of our Exit Facility, a third party engineer report is required annually, with the first report due by May 31, 2017 and we engaged NSAI to provide that report. The first NSAI report was delivered by us on May 23, 2017, and NSAI estimated our proved reserves quantities of 109.4 MMBOE as of March 31, 2017 in accordance with the guidelines established by the SEC. As of December 31, 2017, proved reserves quantities of 88.2 MMBOE were estimated by NSAI. The estimated proved reserve quantities discussed above are unaudited. Other items subject to estimates and assumptions include fair value estimates used in fresh start accounting; accounting for acquisitions and dispositions; carrying amounts of property, plant and equipment; asset retirement obligations; deferred income taxes; valuation of derivative financial instruments; reorganization items and liabilities subject to compromise, among others. Accordingly, our accounting estimates require the exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material.
Cash and Cash Equivalents	Cash and Cash Equivalents. We consider all highly liquid investments, with maturities of 90 days or less when purchased, to be cash and cash equivalents. As of December 31, 2017, cash and cash equivalents include $25.1 million in a money market account. The fair value estimate of money market funds was based on net asset value obtained from quoted prices in active markets and thus represents a Level 1 measurement.
Restricted Cash	Restricted Cash . We maintain restricted escrow funds in trusts as required by certain contractual arrangements and disposition transactions. Amounts on deposit in trust accounts are reflected in restricted cash on our consolidated balance sheets. As of December 31, 2017 and 2016, restricted cash includes $6 million in a money market account. The fair value estimate of money market funds was based on net asset value obtained from quoted prices in active markets and thus represents a Level 1 measurement.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are stated at historical carrying amount net of allowance for doubtful accounts. We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, primarily using the specific identification method. As of December 31, 2017, our allowance for doubtful accounts was $ 0.6 million. As of December 31, 2016, no allowance for doubtful accounts was necessary.
Oil and Natural Gas Properties	Oil and Natural Gas Properties . We use the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless accounting for the sale as a reduction of capitalized costs would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Costs excluded from depletion or amortization represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs associated with unevaluated properties, all of which were recorded as part of fresh start accounting, are transferred to evaluated properties either (i) ratably over a period of the related field’s life, or (ii) upon determination as to whether there are any proved reserves related to the unevaluated properties or the costs are impaired or capital costs associated with the development of these properties will not be available. We evaluate the impairment of our evaluated oil and natural gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4‑10. Estimated future production volumes from oil and natural gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and natural gas reserves could be subject to revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict. For the year ended December 31, 2017, we recorded an impairment to oil and natural gas properties of $185.9 million due to the decrease in proved reserves and PV‑10 value. On December 31, 2016, the Company, subsequent to its emergence from bankruptcy, recorded an impairment of its oil and natural gas properties of approximately $406.3 million due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4‑10. The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12‑month average oil and natural gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting. For the six-month period ended December 31, 2016 and for the years ended June 30, 2016 and 2015, the Predecessor recorded an impairment to its oil and natural gas properties of $77.8 million, $2,814.0 million and $2,421.9 million, respectively. Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE (unaudited) at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million (unaudited). As of December 31, 2017, we have 22 MMBOE (unaudited) in proved undeveloped reserves. Future development costs associated with our proved undeveloped reserves at December 31, 2017 totaled approximately $356.1 million (unaudited). As scheduled in our long range plan, all of our proved undeveloped locations are expected to be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report.
Depreciation, Depletion and Amortization	Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, amortization and impairment, estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves.
Other Property and Equipment	Other Property and Equipment. Other property and equipment include buildings, data processing and telecommunications equipment, office furniture and equipment, vehicle and leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, which ranges from three to five years. Repairs and maintenance costs are expensed in the period incurred.
Goodwill	Goodwill. Goodwill has an indefinite useful life and is not amortized, but rather is tested for impairment at least annually during the third quarter, unless events occur or circumstances change between annual tests that would more likely than not reduce the fair value of a related reporting unit below its carrying value. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. Goodwill arose in the year ended June 30, 2014 in connection with the acquisition of EPL and was recorded to our oil and gas reporting unit. At December 31, 2014, we conducted a qualitative goodwill impairment assessment and after assessing the relevant events and circumstances, we determined that performing a quantitative goodwill impairment test was necessary. Therefore, we performed steps one and two of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. See Note 6 – “Goodwill” for more information.
Derivative Instruments	Derivative Instruments . We have historically used various derivative instruments including crude oil and natural gas put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Any premiums paid or financed on derivative financial instruments are recorded as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or financed. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statements of operations.
Debt Issuance Costs	Debt Issuance Costs. Costs incurred in connection with the issuance of long-term debt are presented in the consolidated balance sheet as a direct deduction from the carrying amount of that debt liability and are amortized to interest expense generally over the scheduled maturity of the debt utilizing the interest method. Costs incurred in connection with line-of-credit agreements are presented as an asset and subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings under the line-of-credit arrangement.
Asset Retirement Obligations	Asset Retirement Obligations . Our investment in oil and natural gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. The present value of the future costs are added to the capitalized cost of our oil and natural gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and natural gas properties that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in abandonment timing, regulatory requirements, technological advances and other factors which may be difficult to predict.
Revenue Recognition	Revenue Recognition. We recognize oil and natural gas revenue when the product is delivered at the contracted sales price, title is transferred and collectability is reasonably assured. The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. The amounts of imbalances were not material at December 31, 2017 and 2016.
General and Administrative Expense	General and Administrative Expense . Under the full cost method of accounting, the portion of our general and administrative expense that is directly identified with our exploration and development activities is capitalized as part of our oil and natural gas properties. These capitalized costs include salaries, employee benefits, costs of consulting services, and other direct costs incurred to support those employees directly involved in exploration and development activities. The capitalized costs do not include costs related to production operations, general corporate overhead or similar activities. Our capitalized general and administrative expense directly related to our exploration and development activities for the year ended December 31, 2017, for the six month transition period ended December 31, 2016 and for the years ended June 30, 2016 and 2015 was $ 16.4 million $7.8 million, $17.0 million and $49.2 million, respectively.
Share-Based Compensation	Share-Based Compensation. Compensation cost for equity awards is based on the fair value of the equity instrument which equals the market value of the underlying stock on the date of grant and is recognized over the period during which an independent director or employee is required to provide service in exchange for the award. Compensation cost for liability awards is based on the fair value of the vested award at the end of each reporting period.
Income Taxes	Income Taxes . Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties and derivative instruments for financial reporting purposes and income tax purposes. For periods ending up through and including the year ended December 31, 2017 we used the then-current U.S. Federal statutory rate of 35% for measuring these deferred tax assets and liabilities, as adjusted for any applicable state taxes. As a result of the Tax Cuts and Jobs Act of 2017, we re-measured these temporary differences at the new U.S. Federal corporate income tax rate of 21% at December 31, 2017. This resulted in a decrease to our tax-effected deferred tax assets of $204 million, and a corresponding reduction of our valuation allowance of $ 204 million. There was no net effect on income tax expense or benefit recorded for the year ended December 31, 2017 as a result of the Tax Cuts and Jobs Act of 2017. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through Depreciation, Depletion and Amortization (“DD&A”). However, due to changes contained in the Tax Cuts and Jobs Act of 2017, we are now afforded an annual election for equipment purchases after September 27, 2017 through December 31, 2022 that allows us to immediately claim tax deductions for 100% the cost of this property. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Tax Code that allow capitalization or expensing of intangible drilling and tangible property costs where management deems appropriate. On the Emergence Date, the Predecessor Company engaged in several internal restructuring transactions that: (i) assigned all of Predecessor’s assets (directly or indirectly) to EGC, and (ii) separated EXXI Ltd, Energy XXI (US Holdings) Limited (Bermuda), Energy XXI, Inc., and Energy XXI USA from EGC. This had the effect, among other things, of isolating the original parent-level equity ownership and certain intercompany loans (the “Intercompany Loans”) from EGC. Then, pursuant to the Plan, the prepetition notes other than the 4.14% promissory note of $5.5 million, the Prepetition Revolving Credit Facility and 100% of the EGC stock owned by Energy XXI USA, Inc., were cancelled. Additionally, new EGC shares and warrants were issued to former creditors as set out in the Plan. 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 Internal Revenue Code of 1986, as amended (the “Tax Code”) provides that a debtor in a bankruptcy case (such as the Chapter 11 Cases) 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 Plan (the “Tax Attribute Reduction Rules”). 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. As a result of fresh start accounting, significant historic deferred tax assets and liabilities were reduced, including the liability for accrued outbound 30% withholding tax on the Intercompany Loans from the Predecessor’s Bermuda parent, as these obligations were extinguished in the Plan and are not obligations of the Successor entities. With the NOL carryover being reduced by the Tax Attribute Reduction Rules, the principal deferred tax assets and liabilities of the Successor after fresh-start accounting relate to our oil and gas properties. The remaining tax bases of our oil and natural gas properties are greater than their respective book carrying values as determined in fresh-start accounting and after reflecting 2017 activity such that we have recorded a deferred tax asset for those properties. These adjustments reflect the change in estimate from prior filings resulting from recently filed pre-emergence income tax returns for the Predecessor. We have recorded a deferred tax asset for the asset retirement obligation (which has no tax basis and will be tax deductible or result in additional tax basis in assets when settled) and other items that exceed the deferred tax liability for oil and natural gas properties. As such, we recorded an after-tax valuation allowance of $168 million at December 31, 2016, which results in no net deferred tax asset or liability appearing on our statement of financial position. This increase in net tax basis reflects the change in estimate from prior filings resulting from recently filed pre-emergence income tax returns for the Predecessor. We recorded this valuation allowance at this date after an evaluation of all available evidence (including our recent history of Predecessor losses) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, these deferred tax assets were unrecoverable. After filing of our initial Form 10-K for the year ended December 31, 2016, tax returns for the Predecessor reflecting the effect of the Tax Attribute Reduction rules were filed resulting in total additional tax basis of $633 million. This amount is made up of an increase in the amount of $663 million related to the change in total CODI excluded (as detailed in the table below), less $30 million related to other changes in estimates of tax attributes resulting from the filings of these tax returns that is unrelated to the Tax Attribute Reduction Rules. These changes were primarily due to: changes in estimate of the amount of the CODI realized and excluded from taxable income and an additional NOL being generated by the Predecessor (including entities not a part of the Successor tax group) that absorbed the CODI exclusion net of other adjustments unrelated to the change in estimate of the CODI exclusion. This change in estimate of the effects of CODI coupled with a decrease in tax return-to-provision adjustment in those tax returns resulted in us increasing our valuation allowance by $224 million (after-tax) in the year ended December 31, 2017. The changes in our tax attributes resulting from the excluded CODI as a result of the tax attribute reduction rules is set out in the following table. Successor After Return to Provision As Filed Adjustment (in thousands) Pre-tax reductions in: Net operating loss carryovers $ 486 $ 681 Oil and natural gas properties 1,485 915 EPL stock basis 543 304 Other 67 18 CODI excluded requiring attribute reduction $ 2,581 $ 1,918 When recording income tax expense, certain estimates are required to be made by management due to timing and to the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate any tax asset, NOL and other carryforwards to determine whether a gross tax asset, as well as a valuation allowance, should be recognized or adjusted in our consolidated financial statements. We have not recorded any reserves for uncertain income tax positions. Recognizing the late enactment of the Tax Cuts and Jobs Act of 2017 and complexity of accurately accounting for its impact, the SEC in SAB 118 provided guidance that allows registrants to provide a reasonable estimate of the impact of the Tax Cuts and Jobs Act of 2017 in their financial statements and adjust the reported impact in a measurement period not to exceed one year. While we believe we have recorded the predominate effects of the Tax Cuts and Jobs Act of 2017 in our provisional accounting the fourth quarter of 2017 (related to the corporate tax rate decrease from 35% to 21%), we continue to assess the impact of the Tax Cuts and Jobs Act of 2017 on our business in order to complete our analysis. Any adjustment to our provisional amounts recorded during the year ended December 31, 2017 will be reported in the reporting period in which any such adjustments are determined in the period in which the adjustments are made. See Note 18 “Income Taxes” for more information.
Earnings per Share	Earnings per Share . Basic earnings (loss) per share (“EPS”) amounts have been calculated based on the weighted average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution using the treasury stock method. Except when the effect would be anti-dilutive, the diluted EPS calculation includes the impact of the assumed conversion of our Predecessor convertible preferred stock and other potential shares of common stock.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014‑09, Revenue from Contracts with Customers (“ASU 2014‑09”), as a new Accounting Standards Codification (ASC) Topic, ASC 606. ASU 2014‑09 is effective for us beginning in the first quarter of 2018. In May 2016, the FASB issued ASU 2016-11, which rescinds certain SEC guidance in the related ASC, including guidance related to the use of the “entitlements” method of revenue recognition used by EGC. Based on our assessment of revenue contracts with customers against the requirements of the standard, we have not identified any changes to the timing of revenue recognition based on the requirements of ASC 606 that would have a material impact on our consolidated financial statements. We adopted the new standard effective January 1, 2018 utilizing the modified retrospective method. The cumulative-effect adjustment to retained earnings upon adoption is not material. In February 2016, the FASB issued ASU No. 2016‑02, Leases ( “ ASU 2016‑02”), 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. To meet that objective, the FASB amended the FASB Accounting Standards Codification and created Topic 842, Leases . The guidance in this ASU supersedes Topic 840, Leases. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new standard is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In the normal course of business, we enter into lease agreements to support our operations. We are in the initial stages of evaluating the provisions of ASU 2016‑02 to determine the quantitative effects it will have on our consolidated financial statements and related disclosures. We believe the adoption and implementation of this ASU will have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. In March 2016, the FASB issued ASU No. 2016‑09 (“ASU 2016‑09”), Compensation - Stock Compensation , to reduce complexity and enhance several aspects of accounting and disclosure for share-based payment transactions, including the accounting for income taxes, award forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU 2016‑09 was effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. Our adoption of ASU 2016‑09 on January 1, 2017 had no effect on our consolidated financial position, results of operations or cash flows. In June 2016, the FASB issued ASU No. 2016‑13, Credit Losses, Measurement of Credit Losses on Financial Instruments (“ASU 2016‑13”). ASU 2016‑13 significantly changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace today’s incurred loss approach with an expected loss model for instruments measured at amortized cost. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. This ASU is effective for public entities for annual and interim periods beginning after December 15, 2019. Early adoption is permitted for all entities for annual periods beginning after December 15, 2018, and interim periods therein. We have not yet determined the effect of this standard on our consolidated financial position, results of operations or cash flows. In August 2016, the FASB issued ASU No. 2016‑15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016‑15”). ASU 2016‑15 provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The Company will adopt this update effective January 1, 2018 using the retrospective transition method. We do not expect the adoption of ASU 2016‑15 will have a material impact on our consolidated statement of cash flows and related disclosures other than presentation. In November 2016, the FASB issued ASU No. 2016‑18 , Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016‑18). ASU 2016‑18 requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. The Company will adopt this update retrospectively effective January 1, 2018. We do not expect the adoption of ASU 2016‑18 will have a material impact on our statement of cash flows and related disclosures other than presentation.

Revision of Prior Period Fina34

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements (Tables)	12 Months Ended
	Dec. 31, 2017
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements
Schedule of quantifying prior year misstatements corrected in current year financial statements	These adjustments impacted the consolidated balance sheet as of December 31, 2016 as follows (in thousands): Successor As of December 31, 2016 As reported Adjustments As Revised ASSETS Current Assets Cash and cash equivalents $ 165,368 $ — $ 165,368 Accounts receivable, net Oil and natural gas sales 68,143 1,601 69,744 Joint interest billings 5,600 429 6,029 Other 17,944 — 17,944 Prepaid expenses and other current assets 25,957 (7,977) 17,980 Restricted cash 32,337 — 32,337 Total Current Assets 315,349 (5,947) 309,402 Property and Equipment Oil and natural gas properties, net 1,097,479 (8) 1,097,471 Other property and equipment, net 18,807 1,200 20,007 Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment 1,116,286 1,192 1,117,478 Other Assets Restricted cash 25,583 — 25,583 Other assets and debt issuance costs, net of accumulated amortization 28,244 — 28,244 Total Other Assets 53,827 — 53,827 Total Assets $ 1,485,462 $ (4,755) $ 1,480,707 LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) Current Liabilities Accounts payable $ 101,117 $ — $ 101,117 Accrued liabilities 63,660 (7,985) 55,675 Asset retirement obligations 56,601 — 56,601 Current maturities of long-term debt 4,268 — 4,268 Total Current Liabilities 225,646 (7,985) 217,661 Long-term debt, less current maturities 74,229 — 74,229 Asset retirement obligations 696,763 (16,256) 680,507 Other liabilities 14,481 (1,886) 12,595 Total Liabilities 1,011,119 (26,127) 984,992 Stockholders’ Equity Preferred stock — — — Common stock 332 — 332 Additional paid-in capital 880,286 21,372 901,658 Accumulated deficit (406,275) — (406,275) Total Stockholders’ Equity 474,343 21,372 495,715 Total Liabilities and Stockholders’ Equity $ 1,485,462 $ (4,755) $ 1,480,707 These adjustments impacted the consolidated statement of operations for the six months ended December 31, 2016 as follows (in thousands): Predecessor Six Months Ended December 31, 2016 As reported Adjustments As Revised Revenues Oil sales $ 255,040 $ 1,010 $ 256,050 Natural gas liquids sales 3,533 — 3,533 Natural gas sales 37,103 — 37,103 Total Revenues 295,676 1,010 296,686 Costs and Expenses Lease operating 137,007 (429) 136,578 Production taxes 482 — 482 Gathering and transportation 5,910 — 5,910 Pipeline facility fee 20,330 — 20,330 Depreciation, depletion and amortization 60,626 (424) 60,202 Accretion of asset retirement obligations 38,973 (593) 38,380 Impairment of oil and natural gas properties 86,820 (9,039) 77,781 General and administrative expense 27,557 — 27,557 Total Costs and Expenses 377,705 (10,485) 367,220 Operating Loss (82,029) 11,495 (70,534) Other Income (Expense) Other income, net 117 — 117 Interest expense (12,580) — (12,580) Total Other Expense, net (12,463) — (12,463) Loss Before Reorganization Items and Income Taxes (94,492) 11,495 (82,997) Reorganization items 2,748,395 (14,787) 2,733,608 Loss Before Income Taxes 2,653,903 (3,292) 2,650,611 Income Tax Expense — — — Net Income $ 2,653,903 $ (3,292) $ 2,650,611 Earnings per Share Basic $ 26.99 $ (0.04) $ 26.95 Diluted $ 25.33 $ (0.03) $ 25.30 Weighted Average Number of Common Shares Outstanding Basic 98,337 98,337 98,337 Diluted 104,787 104,787 104,787 These adjustments impacted the consolidated statement of cash flows for the six months ended December 31, 2016 as follows (in thousands): Predecessor Six Months Ended December 31, 2016 As reported Adjustments As Revised Cash Flows From Operating Activities Net income $ 2,653,903 $ (3,292) $ 2,650,611 Adjustments to reconcile net income to net cash used in operating activities: Depreciation, depletion and amortization 60,626 (424) 60,202 Impairment of oil and natural gas properties 86,820 (9,039) 77,781 Accretion of asset retirement obligations 38,973 (593) 38,380 Reorganization items (2,838,963) 14,787 (2,824,176) Amortization and write-off of debt issuance costs, payment of interest in kind and other 5,025 — 5,025 Deferred rent 3,355 — 3,355 Stock-based compensation 183 — 183 Changes in operating assets and liabilities Accounts receivable (16,545) (1,010) (17,555) Prepaid expenses and other assets (7,425) — (7,425) Change in restricted cash (25,157) — (25,157) Settlement of asset retirement obligations (18,852) — (18,852) Accounts payable and accrued liabilities 40,584 (429) 40,155 Net Cash Used in Operating Activities (17,473) — (17,473) Cash Flows from Investing Activities Capital expenditures (20,237) — (20,237) Change in restricted cash 31,748 — 31,748 Other 195 — 195 Net Cash Provided by Investing Activities 11,706 — 11,706 Cash Flows from Financing Activities Payments on long-term debt (32,088) — (32,088) Other (35) — (35) Net Cash Used in Financing Activities (32,123) — (32,123) Net Decrease in Cash and Cash Equivalents (37,890) — (37,890) Cash and Cash Equivalents, beginning of period 203,258 203,258 Cash and Cash Equivalents, end of period $ 165,368 $ $ — $ 165,368 These adjustments impacted the consolidated statement of operations for the year ended June 30, 2016 as follows (in thousands): Predecessor Year Ended June 30, 2016 As reported Adjustments As Revised Revenues Oil sales $ 531,914 $ 591 $ 532,505 Natural gas liquids sales 14,852 — 14,852 Natural gas sales 69,255 — 69,255 Gain on derivative financial instruments 90,506 — 90,506 Total Revenues 706,527 591 707,118 Costs and Expenses Lease operating 328,183 — 328,183 Production taxes 1,442 — 1,442 Gathering and transportation 33,156 — 33,156 Pipeline facility fee 40,659 — 40,659 Depreciation, depletion and amortization 339,516 23 339,539 Accretion of asset retirement obligations 64,690 18 64,708 Impairment of oil and natural gas properties 2,813,570 458 2,814,028 General and administrative expense 102,736 — 102,736 Total Costs and Expenses 3,723,952 499 3,724,451 Operating Loss (3,017,425) 92 (3,017,333) Other (Expense) Income Loss from equity method investees (10,746) — (10,746) Other income, net 3,596 — 3,596 Gain on early extinguishment of debt 1,525,596 — 1,525,596 Interest expense (405,658) — (405,658) Total Other Income, net 1,112,788 — 1,112,788 Loss Before Reorganization Items and Income Taxes (1,904,637) 92 (1,904,545) Reorganization items (14,201) — (14,201) Loss Before Income Taxes (1,918,838) 92 (1,918,746) Income Tax Benefit (87) — (87) Net Loss (1,918,751) 92 (1,918,659) Preferred Stock Dividends 8,394 (3,200) 5,194 Net Loss Attributable to Common Stockholders $ (1,927,145) $ 3,292 $ (1,923,853) Loss per Share Basic and Diluted $ (20.11) $ 0.03 $ (20.08) Weighted Average Number of Common Shares Outstanding Basic and Diluted 95,822 95,822 95,822 These adjustments impacted the consolidated statement of cash flows for the year ended June 30, 2016 as follows (in thousands): Predecessor Year Ended June 30, 2016 As reported Adjustments As Revised Cash Flows From Operating Activities Net loss $ (1,918,751) $ 92 $ (1,918,659) Adjustments to reconcile net loss to net cash (used in) provided by operating activities: Depreciation, depletion and amortization 339,516 23 339,539 Impairment of oil and natural gas properties 2,813,570 458 2,814,028 Change in fair value of derivative financial instruments 19,163 — 19,163 Accretion of asset retirement obligations 64,690 18 64,708 Loss from equity method investees 10,746 — 10,746 Gain on early extinguishment of debt (1,525,596) — (1,525,596) Amortization and write-off of debt issuance costs, payment of interest in kind and other 138,473 — 138,473 Deferred rent 9,154 — 9,154 Provision for loss on accounts receivable 3,200 — 3,200 Stock-based compensation 1,336 — 1,336 Changes in operating assets and liabilities Accounts receivable 42,742 (591) 42,151 Prepaid expenses and other assets (24,438) — (24,438) Change in restricted cash — — — Settlement of asset retirement obligations (78,273) — (78,273) Accounts payable and accrued liabilities (62,187) — (62,187) Net Cash Used in Operating Activities (166,655) — (166,655) Cash Flows from Investing Activities Acquisitions, net of cash (2,797) — (2,797) Capital expenditures (111,884) — (111,884) Insurance payments received 8,251 — 8,251 Change in restricted cash (22,136) — (22,136) Proceeds from the sale of properties 5,693 — 5,693 Other (40) — (40) Net Cash Used in Investing Activities (122,913) — (122,913) Cash Flows from Financing Activities Proceeds from the issuance of common and preferred stock, net of offering costs 334 — 334 Dividends to shareholders – preferred (5,673) — (5,673) Proceeds from long-term debt 1,121 — 1,121 Payments on long-term debt (227,884) — (227,884) Payment of debt assumed in acquisition (25,187) — (25,187) Fees related to debt extinguishment (3,526) — (3,526) Debt issuance costs (2,163) — (2,163) Other (1,044) — (1,044) Net Cash Used in Financing Activities (264,022) — (264,022) Net Decrease in Cash and Cash Equivalents (553,590) — (553,590) Cash and Cash Equivalents, beginning of period 756,848 756,848 Cash and Cash Equivalents, end of period $ 203,258 $ $ — $ 203,258
Schedule of Cancellation of Indebtedness Income [Table Text Block]	Successor After Return to Provision As Filed Adjustment (in thousands) Pre-tax reductions in: Net operating loss carryovers $ 486 $ 681 Oil and natural gas properties 1,485 915 EPL stock basis 543 304 Other 67 18 CODI excluded requiring attribute reduction $ 2,581 $ 1,918

Fresh Start Accounting (Tables)

Fresh Start Accounting (Tables)	12 Months Ended
	Dec. 31, 2017
Fresh Start Accounting
Schedule of reconciliation of the enterprise value to the estimated fair value of the Successor company's common stock as of the Convenience Date	The following table reconciles the enterprise value to the estimated fair value of the Successor Company’s common stock as of the Convenience Date ( in thousands ): December 31, 2016 Enterprise Value $ 815,119 Add: Cash and cash equivalents 165,368 Less: Fair value of debt (78,497) Fair Value of Successor common stock and warrants 901,990 Less: Fair value of warrants (8,056) Fair Value of Successor common stock $ 893,934
Schedule of reconciliation of enterprise value to estimated reorganization value as of the Emergence Date	The following table reconciles the enterprise value to the estimated reorganization value as of the Emergence Date ( in thousands ): December 31, 2016 Enterprise Value $ 815,119 Add: Cash and cash equivalents 165,368 Add: Other working capital liabilities 156,792 Add: Other long-term liabilities 12,595 Add: Asset retirement obligation 737,108 Reorganization value of Successor assets $ 1,886,982
Schedule of reorganization and application of ASC 852 and the Convenience Date ceiling test impairment on consolidated balance sheet	The following table reflects the reorganization and application of ASC 852 and the Convenience Date ceiling test impairment on our consolidated balance sheet as of December 31, 2016 after making adjustments to correct immaterial misstatements. For a detailed explanation of these adjustments, p lease see Note 2 “—Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements” ( in thousands ): As of December 31, 2016 Predecessor Reorganization Fresh-Start Successor Impairment Successor ASSETS Current Assets Cash and cash equivalents $ 164,817 $ 551 (1) $ — $ 165,368 $ — $ 165,368 Accounts receivable, net — — Oil and natural gas sales 69,744 — — 69,744 — 69,744 Joint interest billings 6,029 — — 6,029 — 6,029 Other 18,909 (965) (3) — 17,944 — 17,944 Prepaid expenses and other current assets 46,123 (26,260) (2) (1,883) (10) 17,980 — 17,980 Restricted cash 32,888 (551) (1) — 32,337 — 32,337 Total Current Assets 338,510 (27,225) (1,883) 309,402 — 309,402 Property and Equipment Oil and natural gas properties, net 491,521 — 1,012,225 (11) 1,503,746 (406,275) 1,097,471 Other property and equipment, net 15,049 — 4,958 (12) 20,007 — 20,007 Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment 506,570 — 1,017,183 1,523,753 (406,275) 1,117,478 Other Assets Restricted cash 25,583 — — 25,583 — 25,583 Other assets 30,174 — (1,930) (13) 28,244 — 28,244 Total Other Assets 55,757 — (1,930) 53,827 — 53,827 Total Assets $ 900,837 $ (27,225) $ 1,013,370 $ 1,886,982 $ (406,275) $ 1,480,707 LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) Current Liabilities Accounts payable $ 67,876 $ 33,241 (3) $ — $ 101,117 $ — $ 101,117 Accrued liabilities 40,517 15,158 (3)(4) — 55,675 — 55,675 Asset retirement obligations 58,537 — (1,936) (14) 56,601 — 56,601 Current maturities of long-term debt 74,046 (69,778) (5) — 4,268 — 4,268 Total Current Liabilities 240,976 (21,379) (1,936) 217,661 — 217,661 Long-term debt, less current maturities — 74,229 (5) — 74,229 — 74,229 Asset retirement obligations 492,931 — 187,576 (14) 680,507 — 680,507 Other liabilities 22,776 2,345 (3) (12,526) (15) 12,595 — 12,595 Total Liabilities Not Subject to Compromise 756,683 55,195 173,114 984,992 — 984,992 Liabilities subject to compromise 2,931,419 (2,931,419) (6) — — — — Total Liabilities 3,688,102 (2,876,224) 173,114 984,992 — 984,992 Stockholders’ Equity (Deficit) Preferred stock (Predecessor) 7.25% Convertible perpetual preferred stock (Predecessor) — — — — — — 5.625% Convertible perpetual preferred stock (Predecessor) — — — — — — Common stock (Predecessor) 504 (504) (7) — — — — Common stock (Successor) — 332 (8) — 332 — 332 Additional paid-in capital (Predecessor) 1,845,851 (1,845,851) (7) — — — — Additional paid-in capital (Successor) — 901,658 (8) — 901,658 — 901,658 Accumulated deficit (4,633,620) 3,793,364 (9) 840,256 (16) — (406,275) (406,275) Total Stockholders’ (Deficit) Equity (2,787,265) 2,848,999 840,256 901,990 (406,275) 495,715 Total Liabilities and Stockholders’ (Deficit) Equity $ 900,837 $ (27,225) $ 1,013,370 $ 1,886,982 $ (406,275) $ 1,480,707 Reorganization Adjustments (1) (2) (3) (4) (5) (6) in thousands ): On December 31, 2016 Predecessor Debt 11.0% Senior Secured Second Lien Notes due 2020 $ 1,450,000 8.25% Senior Notes due 2018 213,677 6.875% Senior Notes due 2024 143,993 3.0% Senior Convertible Notes due 2018 363,018 7.5% Senior Notes due 2021 238,071 7.75% Senior Notes due 2019 101,077 9.25% Senior Notes due 2017 249,452 4.14% Promissory Note due 2017 4,001 Capital lease obligations 450 Total debt 2,763,739 Accounts payable 37,424 Accrued liabilities 130,256 Total liabilities subject to compromise 2,931,419 Fair value of equity and warrants issued per the Plan (901,990) Fair value of reinstated accounts payable and accrued liabilities to be settled in cash (43,509) Cash payment for 3.0% Senior Convertible Notes (2,000) Gain on settlement of liabilities subject to compromise $ 1,983,920 (7) (8) (9) in thousands ): December 31, 2016 Gain on settlement of liabilities subject to compromise $ 1,983,920 Cancellation of EXXI Ltd equity 1,846,355 Accrual of success fee (12,651) Payments made of plan support parties (24,260) Net impact to accumulated deficit $ 3,793,364 Fresh Start Adjustments (10) (11) (12) (13) (14) 37.1 million. (15) (16)
Schedule of reorganization items	The following table summarizes reorganization items ( in thousands ): Predecessor Six Months Ended Year Ended December 31, June 30, 2016 2016 Gain on settlement of liabilities subject to compromise $ 1,983,920 $ — Fresh start adjustments 840,256 — Reorganization legal and professional fees and expenses (90,568) (14,201) Gain (loss) on reorganization items $ 2,733,608 $ (14,201)

Acquisitions and Dispositions (

Acquisitions and Dispositions (Tables)	12 Months Ended
	Dec. 31, 2017
Acquisitions and Dispositions
Schedule of the final purchase price allocation of assets acquired and liabilities assumed	The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their estimated fair values on August 11, 2015 ( in thousands ): Oil and natural gas properties – evaluated $ 73,910 Oil and natural gas properties – unevaluated 39,278 Asset retirement obligations (66,700) Net working capital * (21,301) Fair value of debt assumed (25,187) Cash paid $ — *

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property and Equipment
Schedule of property and equipment	Property and equipment consists of the following ( in thousands ): Successor December 31, December 31, 2017 2016 Oil and gas properties Proved properties $ 1,307,009 $ 1,127,608 Less: accumulated depreciation, depletion, amortization and impairment (742,286) (406,275) Proved properties, net 564,723 721,333 Unevaluated properties 200,199 376,138 Oil and gas properties, net 764,922 1,097,471 Other property and equipment 13,780 20,007 Less: accumulated depreciation (3,660) — Other property and equipment, net 10,120 20,007 Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment $ 775,042 $ 1,117,478

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Long-Term Debt
Schedule of long-term debt	Long-term debt consists of the following ( in thousands ): Successor December 31, December 31, 2017 2016 Exit Facility $ 73,996 $ 73,996 4.14% Promissory Note due 2017 — 4,001 Capital lease obligations 21 500 Total debt 74,017 78,497 Less: debt issue costs 44 — Less: current maturities 21 4,268 Total long-term debt $ 73,952 $ 74,229
Schedule of maturities of long-term debt	Maturities of long-term debt as of December 31, 2017 are as follows (in thousands ) Twelve Months Ending December 31, 2018 $ 21 2019 73,996 2020 — 2021 — 2022 — Thereafter — $ 74,017
Schedule of cancelled obligations under debt instruments	Issue Date Face value Maturity Date 11.0% Senior Secured Second Lien Notes 3/12/2015 1,450,000 3/15/2020 8.25% Senior Notes (1) 6/3/2014 510,000 2/15/2018 6.875% Senior Notes 5/27/2014 650,000 3/15/2024 3.0% Senior Convertible Notes 11/18/2013 400,000 12/15/2018 7.5% Senior Notes 9/26/2013 500,000 12/15/2021 7.75% Senior Notes 2/25/2011 250,000 6/15/2019 9.25% Senior Notes 12/17/2010 750,000 12/15/2017 (1) 8.25% Senior Notes was assumed in the EPL Acquisition.
Schedule of interest expense	Interest expense consisted of the following ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Exit Term Loan $ 4,050 $ — $ — $ — Exit Revolving Facility 10,127 — — — Prepetition Revolving Credit Facility — 11,670 15,703 25,506 11.0% Second Lien Notes due 2020 — — 125,852 48,505 8.25% Senior Notes due 2018 — — 27,899 42,075 6.875% Senior Notes due 2024 — — 18,033 44,701 3.0% Senior Convertible Notes due 2018 — — 9,340 12,000 7.50% Senior Notes due 2021 — — 17,414 37,500 7.75% Senior Notes due 2019 — — 8,200 19,375 9.25% Senior Notes due 2017 — — 44,944 69,375 4.14% Promissory Note due 2017 134 — 130 192 Amortization of debt issue cost - Prepetition Revolving Credit Facility — 725 5,185 12,491 Accretion of original debt issue discount, 11.0% Second Lien Notes due 2020 — — 6,249 2,358 Accretion of original debt issue discount, 11.0% Second Lien Notes due 2020 - accelerated — — 44,855 — Amortization of debt issue cost – 11.0% Second Lien Notes due 2020 — — 5,047 1,887 Amortization of debt issue cost – 11.0% Second Lien Notes due 2020 - accelerated — — 36,243 — Amortization of fair value premium – 8.25% Senior Notes due 2018 — — (8,818) (11,108) Amortization of fair value premium – 8.25% Senior Notes due 2018 - accelerated — — (7,961) — Amortization of debt issue cost – 6.875% Senior Notes due 2024 — — 457 1,127 Amortization of debt issue cost – 6.875% Senior Notes due 2024 - accelerated — — 1,946 — Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 — — 8,917 11,232 Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 - accelerated — — 33,370 — Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 — — 1,142 1,439 Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 - accelerated — — 4,271 — Amortization of debt issue cost – 7.50% Senior Notes due 2021 — — 478 1,051 Amortization of debt issue cost – 7.50% Senior Notes due 2021 - accelerated — — 2,822 — Amortization of debt issue cost – 7.75% Senior Notes due 2019 — — 168 388 Amortization of debt issue cost – 7.75% Senior Notes due 2019 - accelerated — — 491 — Amortization of debt issue cost – 9.25% Senior Notes due 2017 — — 1,902 2,358 Amortization of debt issue cost – 9.25% Senior Notes due 2017 - accelerated — — 913 — Derivative instruments financing and other 525 185 466 856 $ 14,836 $ 12,580 $ 405,658 $ 323,308

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligations
Schedule of changes in asset retirement obligations	The following table describes the changes in our asset retirement obligations ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, 2017 2016 Beginning of period total $ 737,108 $ 537,637 Liabilities incurred 11,353 13,880 Liabilities settled (55,820) (18,852) Revisions* (70,570) (19,577) Accretion expense 42,780 38,380 End of period total 551,468 Fair value fresh start adjustments 185,640 End of period total 664,851 737,108 Less: End of period, current portion 51,398 56,601 End of period, noncurrent portion $ 613,453 $ 680,507 * , resulting from updated estimates as to when the associated wells would cease to be economic, and the downward revision for the six months ended December 31, 2016 was primarily due to declining service costs resulting from the decline in commodity prices and decrease in demand for oil field services due to excess capacity.

Derivative Financial Instrume40

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Financial Instruments
Schedule of derivative positions	As of December 31, 2017, we had the following open crude oil derivative positions: Weighted Average Type of Volumes Contract Price Remaining Contract Term Contract Index (MBbls) Swaps January 2018 - December 2018 Swaps NYMEX-WTI $ 50.68 January 2018 - June 2018 Swaps Argus-LLS $ 55.45 January 2018 - June 2018 Swaps ICE Brent $ 56.59
Schedule of fair value of our derivative instruments	Weighted Average Type of Volumes Contract Price Remaining Contract Term Contract Index (MBbls) Swaps January 2018 - December 2018 Swaps NYMEX-WTI $ 50.68 January 2018 - June 2018 Swaps Argus-LLS $ 55.45 January 2018 - June 2018 Swaps ICE Brent $ 56.59 The fair value of our derivative instruments in our consolidated balance sheets were as follows ( in thousands ) Successor Asset Derivative Instruments Liability Derivative Instruments December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Balance Fair Value Balance Fair Value Balance Fair Value Balance Fair Value Derivative financial instruments Current $ — Current $ — Current $ 32,567 Current $ — Non-Current — Non-Current — Non-Current — Non-Current — Total Gross Commodity Derivative Instruments subject to enforceable master netting agreement — — 32,567 — Derivative financial instruments Current — Current — Current — Current — Non-Current — Non-Current — Non-Current — Non-Current — Total gross amounts offset in Balance Sheets — — — — Net amounts presented in Balance Sheets Current — Current — Current 32,567 Current — Non-Current — Non-Current — Non-Current — Non-Current — $ — $ — $ 32,567 $ —
Schedule of the components of the gain (loss) on derivative instruments	The following table presents information about the components of the gain (loss) on derivative instruments ( in thousands ). Year Ended Six Months December 31, Ended Year Ended June 30, Gain (loss) on derivative financial instruments 2017 2016 2016 2015 Cash Settlements $ (58) $ — $ 59,081 $ 81,049 Proceeds from monetizations — — 50,588 102,354 Change in fair value (32,567) — (19,163) 52,036 Total gain (loss) on derivative financial instruments $ (32,625) $ — $ 90,506 $ 235,439

Supplemental Cash Flow Inform41

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Information
Schedule of supplemental cash flow information	The following table presents our supplemental cash flow information ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Cash paid for interest $ 14,867 $ 7,493 $ 229,569 $ 243,238 Cash paid for income taxes — — 150 933
Schedule of non-cash investing and financing activities	The following table presents our non-cash investing and financing activities ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Derivative instruments premium financing $ — $ — $ — $ 12,025 Changes in capital expenditures accrued in accounts payable (1,944) 10,242 (37,151) (168,569) Acquisition of property against joint interest billings receivable (1,500) — — Inventory transferred to oil and natural gas properties — — 7,081 — Changes in asset retirement obligations (59,217) (5,697) (2,583) 49,495 Changes in other property and equipment (327) Monetization of derivative instruments applied to Revolving Credit Facility — — 50,588 —

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Employee Benefit Plans
Schedule of stock option activity	Weighted Weighted Average Average Remaining Exercise Price Contractual Options Per Share Terms (in years) Outstanding as of December 31, 2016 - $ — — Granted 372,597 28.92 Exercised - - Forfeited (72,448) 28.97 Outstanding as of December 31, 2017 300,149 $ 28.91 9.3 Exercisable on December 31, 2017 — $ —
Schedule of restricted stock units activity	Restricted Average Stock Grant Date Units Fair Value Outstanding as of December 31, 2016 - $ — Granted 775,344 24.22 Vested (68,814) 24.21 Forfeited (93,730) 24.48 Outstanding as of December 31, 2017 612,800 $ 24.19
Schedule of stock-based compensation expense	The following table sets forth stock-based compensation expense ( in thousands ): Successor Year Ended December 31, 2017 Stock Options $ 1,453 Restricted Stock Units 8,033 Total compensation expense recognized $ 9,486
Schedule of contributions under plans	The contributions under these plans were as follows ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2017 2016 2016 2015 Profit Sharing Plan $ — $ — $ — $ — $ (768) 401(k) Plan 1,702 — 638 2,852 3,192 Total contributions $ 1,702 $ — $ 638 $ 2,852 $ 2,424

Earnings (Loss) per Share (Tabl

Earnings (Loss) per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings (Loss) per Share
Schedule of basic and diluted earnings (loss) per share	The following table sets forth the calculation of basic and diluted (loss) earnings per share (“EPS”) ( in thousands, except per share data ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 Net (loss) income $ (341,010) $ (406,275) $ 2,650,611 $ (1,918,659) $ (2,433,838) Preferred stock dividends — — — 5,194 11,468 Net (loss) income attributable to common stockholders $ (341,010) $ (406,275) $ 2,650,611 $ (1,923,853) $ (2,445,306) Weighted average shares outstanding for basic EPS 33,239 33,212 98,337 95,822 94,167 Add dilutive securities — — 6,450 — — Weighted average shares outstanding for diluted EPS 33,239 33,212 104,787 95,822 94,167 (Loss) earnings per share Basic $ (10.26) $ (12.23) $ 26.95 $ (20.08) $ (25.97) Diluted $ (10.26) $ (12.23) $ 25.30 $ (20.08) $ (25.97)

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies
Schedule of future minimum lease commitments under operating leases	As of December 31, 2017, future minimum lease commitments under our operating leases are as follows ( in thousands ): Year Ending December 31, Successor 2018 $ 36,035 2019 36,509 2020 43,545 2021 49,598 2022 48,575 Thereafter 152,176 Total $ 366,438

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Taxes
Schedule of Cancellation of Indebtedness Income	Successor After Return to Provision As Filed Adjustment (in thousands) Pre-tax reductions in: Net operating loss carryovers $ 486 $ 681 Oil and natural gas properties 1,485 915 EPL stock basis 543 304 Other 67 18 CODI excluded requiring attribute reduction $ 2,581 $ 1,918
Schedule of income (loss) before income taxes	Our (loss) income before income taxes attributable to U.S. and non-U.S. operations are as follows ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 U.S. (loss) income $ (341,010) $ (406,275) $ 2,650,611 $ (1,913,626) $ (3,050,659) Non-U.S. (loss) income — — — (5,120) 3,471 (Loss) income before income taxes $ (341,010) $ (406,275) $ 2,650,611 $ (1,918,746) $ (3,047,188)
Schedule of the components of income tax expense (benefit)	The components of our income tax benefit are as follows ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 Current U.S. $ — $ — $ — $ — $ 933 Non U.S. — — — — — State — — — (87) 99 Total current — — — (87) 1,032 Deferred U.S. — — — — (564,569) State — — — — (49,813) Total deferred — — — — (614,382) Total income tax benefit $ — $ — $ — $ (87) $ (613,350)
Schedule of the reconciliation of statutory income tax expense to the income tax provision (benefit)	The following is a reconciliation of statutory income tax expense to our income tax benefit ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 (Loss) income before income taxes $ (341,010) $ (406,275) $ 2,650,611 $ (1,918,746) $ (3,047,188) Statutory rate 35 % 35 % 35 % 35 % 35 % Income tax (benefit) expense computed at statutory rate (119,354) (142,196) 927,714 (671,561) (1,066,516) Reconciling items Federal withholding obligation — — — 8,161 10,331 Nontaxable foreign income — — — 1,791 91 Change in valuation allowance 138,561 142,196 (1,029,335) 650,011 356,798 State income taxes (benefit), net of federal tax benefit — — — (87) (32,314) Non-deductible transaction and restructuring costs 894 — 36,874 — 440 Return to provision adjustments (224,339) — — — — Tax Cuts and Jobs Act of 2017 204,137 — — — — Tax basis in shortfall on partnership dissolution — — — 6,501 — Fresh start adjustments to deferred tax balances: Asset retirement obligation — — 190,715 — — Net operating loss — — 163,027 — — Accrued interest expense — — 115,560 — — Oil and natural gas properties and other property and equipment — — 611,834 — — Deferred state income taxes — — 54,793 — — Withholding taxes — — (81,635) — — Cancellation of stockholders deficit — — (290,665) — — Cancellation of indebtedness income — — (702,972) — — Other fresh start deferred income taxes, net — — 3,284 — — Goodwill impairment — — — — 115,253 Other – Net 101 — 806 5,097 2,567 Income tax benefit $ — $ — $ — $ (87) $ (613,350)
Schedule of the components of deferred taxes	The components of deferred taxes are detailed in the table below ( in thousands ): Successor December 31, 2017 2016 Deferred tax assets – non current Oil, natural gas properties and other property and equipment $ 66,297 $ — Asset retirement obligation 139,619 257,988 Tax loss carryforwards on U.S. operations 71,268 — Employee benefit plans 1,698 — Tax partnership activity 676 — Derivative instruments and other 6,839 — Other 19,809 11,120 Total deferred tax assets – non current 306,206 269,108 Deferred tax liabilities Oil, natural gas properties and other property and equipment — (101,463) Total deferred tax liabilities – non current — (101,463) Valuation allowance (306,206) (167,645) Net deferred tax $ — $ —

Fair Value (Tables)

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value
Schedule of the fair value of Level 1 and Level 2 financial instruments	The following table presents the fair value of our Level 2 financial instruments ( in thousands ): Successor Level 2 As of As of December 31, December 31, 2017 2016 Assets: Oil and natural gas derivatives $ — $ — Liabilities: Oil and natural gas derivatives $ 32,567 $ —
Schedule of details of Level 2 financial instruments	The following table sets forth the carrying values and estimated fair values of our long-term debt instruments which are classified as Level 2 financial instruments ( in thousands ): Successor December 31, 2017 2016 Carrying Value Estimated Carrying Value Estimated Exit Facility $ 73,996 $ 73,996 $ 73,996 $ 73,996 Total $ 73,996 $ 73,996 $ 73,996 $ 73,996 (1) In accordance with the Plan, on the Emergence Date, all outstanding obligations under these notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled.
Schedule of changes in Level 3 financial instruments	The following table sets forth our Level 3 financial instruments ( in thousands ): Predecessor Six Months Ended Year Ended Year Ended December 31, June 30, June 30, 2016 2016 2015 Liabilities: Performance-based performance units Balance at beginning of period $ — $ 33 $ 6,910 Vested — (775) — Grants charged to general and administrative expense — 760 (6,877) Balance at end of period $ — $ 18 $ 33

Prepayments and Accrued Liabi47

Prepayments and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Prepayments and Accrued Liabilities
Schedule of prepayments and accrued liabilities	Prepayments and accrued liabilities consist of the following ( in thousands ): Successor December 31, 2017 2016 Prepaid expenses and other current assets Advances to joint interest partners $ 1,381 $ 650 Insurance 5,949 9,600 Inventory 394 470 Royalty deposit 1,021 1,273 Other 12,857 5,987 Total prepaid expenses and other current assets $ 21,602 $ 17,980 Accrued liabilities Advances from joint interest partners 81 374 Employee benefits and payroll 6,791 4,491 Interest payable 185 233 Accrued hedge payable 2,491 — Undistributed oil and gas proceeds 20,079 22,715 Severance taxes payable 558 628 Escrowed reorganization expenses — 25,987 Other 15,309 1,247 Total accrued liabilities $ 45,494 $ 55,675

Comparative Period Information

Comparative Period Information (Tables)	12 Months Ended
	Dec. 31, 2017
Comparative Period Information
Schedule of transition and comparative period financial information	Predecessor Six Months Ended December 31, 2016 (1) 2015 (2) (Unaudited) (In thousands) Total Revenues $ 296,686 $ 442,438 Operating loss (70,534) (2,431,348) Income (loss) before income taxes 2,650,611 (1,883,924) Income tax expense (benefit) — 51 Net Income (loss) $ 2,650,611 $ (1,883,975) Preferred stock dividends — 5,664 Net Income (Loss) Attributable to Common Stockholders $ 2,650,611 $ (1,889,639) Earnings (Loss) per Share Basic $ 26.95 $ (19.91) Diluted $ 25.30 $ (19.91) Weighted Average Number of Common Shares Outstanding Basic 98,337 94,926 Diluted 104,787 94,926 Predecessor Six Months Ended December 31, 2016 (1) 2015 (2) (Unaudited) (In thousands) Net cash used in operating activities $ (17,473) $ (89,924) Net cash provided by (used in) investing activities 11,706 (82,872) Net cash used in financing activities (32,123) (258,162) Net decrease in cash and cash equivalents $ (37,890) $ (430,958) (1) Included in Operating income (loss) is impairment of oil and natural gas properties of $86.8 million and also included in Net income (loss) are reorganization items being gain on settlement of liabilities subject to compromise of $ 1.983.9 million, fair value adjustment of $8 40.3 and reorganization expenses of $90.6 million. (2) Included in Operating income (loss) is impairment of oil and natural gas properties of $2,330.5 million and also included in Net income (loss) is gain on early extinguishment of debt of $748.6 million.

Selected Quarterly Financial 49

Selected Quarterly Financial Data – Unaudited (Tables)	12 Months Ended
	Dec. 31, 2017
Selected Quarterly Financial Data – Unaudited
Schedule of selected quarterly financial data (unaudited)	Unaudited quarterly financial data are as follows ( in thousands, except per share amounts ): Successor Quarter Ended December 31, (2) September 30, June 30, March 31, (3) 2017 2017 2017 2017 Revenues $ 93,838 $ 115,701 $ 144,019 $ 158,086 Operating loss (211,462) (31,556) (22,675) (60,735) Net loss $ (215,069) $ (35,157) $ (26,237) $ (64,547) Net loss per share (1) Basic and Diluted $ (6.47) $ (1.06) $ (0.79) $ (1.94) (1) The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income (loss) for that quarter and the weighted average number of shares outstanding during that quarter. (2) Included in Operating loss is impairment of oil and natural gas properties of $1 45.1 million. (3) Included in Operating loss is impairment of oil and natural gas properties of $40.8 million. We made adjustments to correct immaterial misstatements within our previously reported quarterly financial statements. These immaterial misstatements affected certain line items within the cash flow from operations section and did not change the total amount of previously reported cash flows. For a detailed explanation of these adjustments, please see Note 2 “—Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements.” Predecessor Quarter Ended December 31, (7) September 30, (6) June 30, (2) March 31, (3) December 31, (4) September 30, (5) 2016 2016 2016 2016 2015 2015 Revenues $ 153,723 $ 142,963 $ 148,395 $ 116,285 $ 184,615 $ 257,823 Operating income (loss) 12,795 (83,329) (168,119) (417,866) (1,513,148) (918,200) Net income (loss) $ 2,771,349 $ (120,738) $ (195,460) $ 160,776 $ (1,310,583) $ (573,392) Preferred stock dividends — — (2,848) 2,378 2,810 2,854 Net income (loss) attributable to common stockholders $ 2,771,349 $ (120,738) $ (192,612) $ 158,398 $ (1,313,393) $ (576,246) Net income (loss) per share attributable to common stockholders (1) Basic $ 28.04 $ (1.23) $ (1.97) $ 1.65 $ (13.81) $ (6.08) Diluted 26.45 (1.23) (1.97) 1.55 (13.81) (6.08) (1) The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. (2) Included in Operating loss is impairment of oil and natural gas properties of $143.1 million. (3) Included in Operating loss is impairment of oil and natural gas properties of $340.5 million and also included in Net loss is gain on early extinguishment of debt of $777.0 million. (4) Included in Operating loss is impairment of oil and natural gas properties of $1,425.8 million and also included in Net loss is gain on early extinguishment of debt of $290.3 million. (5) Included in Operating loss is impairment of oil and natural gas properties of $904.7 million and also included in Net loss is gain on early extinguishment of debt of $458.3 million. (6) Included in Operating loss is impairment of oil and natural gas properties of $77.6 million and also included in Net loss is reorganization expenses of $32.6 million. (7) Included in Net income are gain on settlement of liabilities subject to compromise of $ 1,983.9 million, fair value adjustment gain of $840.3 million and reorganization expenses of $58.0 million.
Schedule for the effect of prior period errors in our consolidated quarterly income statements	Successor Successor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 As reported Adjustments As Revised As reported Adjustments As Revised Revenues Oil sales $ 114,991 $ (1,294) $ 113,697 $ 366,792 $ (818) $ 365,974 Natural gas liquids sales 2,209 — 2,209 6,806 — 6,806 Natural gas sales 12,261 — 12,261 44,382 — 44,382 Gain on derivative financial instruments (12,466) — (12,466) 644 — 644 Total Revenues 116,995 (1,294) 115,701 418,624 (818) 417,806 Costs and Expenses Lease operating 77,822 — 77,822 238,315 429 238,744 Production taxes 471 — 471 1,192 — 1,192 Gathering and transportation (2,441) — (2,441) 11,459 — 11,459 Pipeline facility fee 10,495 — 10,495 31,483 — 31,483 Depreciation, depletion and amortization 36,066 65 36,131 116,733 (21) 116,712 Accretion of asset retirement obligations 9,892 (139) 9,753 32,339 479 32,818 Impairment of oil and natural gas properties (2,357) 2,357 — 40,849 (75) 40,774 General and administrative expense 15,026 — 15,026 57,346 — 57,346 Reorganization items — — — (1,529) 3,773 2,244 Total Costs and Expenses 144,974 2,283 147,257 528,187 4,585 532,772 Operating Loss (27,979) (3,577) (31,556) (109,563) (5,403) (114,966) Other Income (Expense) Other income, net 52 — 52 154 — 154 Interest expense (3,653) — (3,653) (11,129) — (11,129) Total Other Expense , net (3,601) — (3,601) (10,975) — (10,975) Loss Before Income Taxes (31,580) (3,577) (35,157) (120,538) (5,403) (125,941) Income Tax Expense — — — — — — Net Loss $ (31,580) $ (3,577) $ (35,157) $ (120,538) $ (5,403) $ (125,941) Loss per Share Basic and Diluted $ (0.95) $ (0.11) $ (1.06) $ (3.63) $ (0.16) $ (3.79) Weighted Average Number of Common Shares Outstanding Basic and Diluted 33,241 33,241 33,241 33,236 33,236 33,236 Successor Successor Three Months Ended June 30, 2017 Six Months Ended June 30, 2017 As reported Adjustments As Revised As reported Adjustments As Revised Revenues Oil sales $ 118,180 $ 304 $ 118,484 $ 251,801 $ 476 $ 252,277 Natural gas liquids sales 2,370 — 2,370 4,597 — 4,597 Natural gas sales 13,753 — 13,753 32,121 — 32,121 Gain on derivative financial instruments 9,412 — 9,412 13,110 — 13,110 Total Revenues 143,715 304 144,019 301,629 476 302,105 Costs and Expenses Lease operating 85,336 (1,681) 83,655 160,493 429 160,922 Production taxes 482 — 482 721 — 721 Gathering and transportation 2,678 — 2,678 13,900 — 13,900 Pipeline facility fee 10,494 — 10,494 20,988 — 20,988 Depreciation, depletion and amortization 38,661 24 38,685 80,667 (86) 80,581 Accretion of asset retirement obligations 10,050 (66) 9,984 22,447 618 23,065 Impairment of oil and natural gas properties (848) 848 — 43,206 (2,432) 40,774 General and administrative expense 20,716 — 20,716 42,320 — 42,320 Reorganization items (3,773) 3,773 — (1,529) 3,773 2,244 Total Costs and Expenses 163,796 2,898 166,694 383,213 2,302 385,515 Operating Loss (20,081) (2,594) (22,675) (81,584) (1,826) (83,410) Other Income (Expense) Other income, net 80 — 80 102 — 102 Interest expense (3,642) — (3,642) (7,476) — (7,476) Total Other Expense , net (3,562) — (3,562) (7,374) — (7,374) Loss Before Income Taxes (23,643) (2,594) (26,237) (88,958) (1,826) (90,784) Income Tax Expense — — — — — — Net Loss $ (23,643) $ (2,594) $ (26,237) $ (88,958) $ (1,826) $ (90,784) Loss per Share Basic and Diluted $ (0.71) $ (0.08) $ (0.79) $ (2.68) $ (0.05) $ (2.73) Weighted Average Number of Common Shares Outstanding Basic and Diluted 33,237 33,237 33,237 33,234 33,234 33,234 Successor Three Months Ended March 31, 2017 As reported Adjustments As Revised Revenues Oil sales $ 133,621 $ 172 $ 133,793 Natural gas liquids sales 2,227 — 2,227 Natural gas sales 18,368 — 18,368 Gain on derivative financial instruments 3,698 — 3,698 Total Revenues 157,914 172 158,086 Costs and Expenses Lease operating 75,157 2,110 77,267 Production taxes 239 — 239 Gathering and transportation 11,222 — 11,222 Pipeline facility fee 10,494 — 10,494 Depreciation, depletion and amortization 42,006 (110) 41,896 Accretion of asset retirement obligations 12,397 684 13,081 Impairment of oil and natural gas properties 44,054 (3,280) 40,774 General and administrative expense 23,848 — 23,848 Total Costs and Expenses 219,417 (596) 218,821 Operating Loss (61,503) 768 (60,735) Other Income (Expense) Other income, net 22 — 22 Interest expense (3,834) — (3,834) Total Other Expense , net (3,812) — (3,812) Loss Before Income Taxes (65,315) 768 (64,547) Income Tax Expense — — — Net Loss $ (65,315) $ 768 $ (64,547) Loss per Share Basic and Diluted $ (1.97) $ 0.02 $ (1.94) Weighted Average Number of Common Shares Outstanding Basic and Diluted 33,228 33,228 33,228 Predecessor Three Months Ended December 31, 2016 As reported Adjustments As Revised Revenues $ 153,065 $ 658 $ 153,723 Operating income 11,708 1,087 12,795 Net income $ 2,785,049 (13,700) $ 2,771,349 Income per Share Basic $ 28.17 $ (0.14) $ 28.04 Diluted $ 26.58 $ (0.13) $ 26.45 Weighted Average Number of Common Shares Outstanding Basic 98,850 98,850 98,850 Diluted 104,787 104,787 104,787 Predecessor Three Months Ended September 30, 2016 As reported Adjustments As Revised Revenues Oil sales $ 122,732 $ 352 $ 123,084 Natural gas liquids sales 2,144 — 2,144 Natural gas sales 17,735 — 17,735 Gain on derivative financial instruments — — — Total Revenues 142,611 352 142,963 Costs and Expenses Lease operating 65,170 — 65,170 Production taxes 214 — 214 Gathering and transportation 7,534 — 7,534 Pipeline facility fee 10,165 — 10,165 Depreciation, depletion and amortization 31,573 (432) 31,141 Accretion of asset retirement obligations 19,437 (362) 19,075 Impairment of oil and natural gas properties 86,820 (9,262) 77,558 General and administrative expense 15,435 — 15,435 Total Costs and Expenses 236,348 (10,056) 226,292 Operating Loss (93,737) 10,408 (83,329) Other Income (Expense) Other income, net 62 — 62 Interest expense (4,838) — (4,838) Total Other Expense , net (4,776) — (4,776) Loss Before Reorganization Items and Income Taxes (98,513) 10,408 (88,105) Reorganization items (32,633) — (32,633) Loss Before Income Taxes (131,146) 10,408 (120,738) Income Tax Expense — — — Net Loss $ (131,146) $ 10,408 $ (120,738) Loss per Share Basic and Diluted $ (1.34) $ 0.11 $ (1.23) Weighted Average Number of Common Shares Outstanding Basic and Diluted 97,824 97,824 97,824

Supplementary Oil and Gas Inf50

Supplementary Oil and Gas Information – Unaudited (Tables)	12 Months Ended
	Dec. 31, 2017
Supplementary Oil and Gas Information – Unaudited
Schedule of costs incurred for oil and natural gas property acquisition, exploration and development activities	Costs incurred for oil and natural gas property acquisition, exploration and development activities are as follows ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Property acquisitions Proved $ 96 $ 1,500 $ 26,400 $ — Unevaluated — — — 2,304 Exploration costs 669 — 1,400 38,183 Development costs 62,283 22,300 57,400 608,605
Schedule of estimated quantities of proved and undeveloped domestic oil and natural gas reserves	Natural Gas Oil Liquids Natural Gas Total (MBbls) (MBbls) (MMcf) (MBOE) Proved reserves at June 30, 2014 (Predecessor) 175,816 9,573 364,856 246,198 Production (14,272) (987) (37,472) (21,504) Extensions, discoveries and other additions 10,056 517 40,330 17,295 Revisions of previous estimates (32,115) (1,615) (75,617) (46,333) Sales of reserves (9,889) (12) (13,554) (12,160) Proved reserves at June 30, 2015 (Predecessor) 129,596 7,476 278,543 183,496 Production (12,624) (923) (33,973) (19,209) Extensions, discoveries and other additions 1,370 46 1,729 1,704 Revisions of previous estimates (61,347) (3,237) (158,681) (91,031) Purchases of reserves 5,145 871 33,529 11,604 Proved reserves at June 30, 2016 (Predecessor) 62,140 4,233 121,147 86,564 Production (5,482) (167) (13,485) (7,897) Extensions, discoveries and other additions 31,846 375 27,788 36,852 Revisions of previous estimates 6,746 (1,293) 5,788 6,418 Proved reserves at December 31, 2016 (Successor) 95,250 3,148 141,238 121,937 Production (9,324) (288) (17,282) (12,493) Extensions, discoveries and other additions 5,691 217 7,030 7,082 Revisions of previous estimates (17,261) (1,397) (58,001) (28,327) Proved reserves at December 31, 2017 (Successor) 74,356 1,680 72,985 88,199 Proved developed reserves June 30, 2014 (Predecessor) 106,900 5,889 222,916 149,942 June 30, 2015 (Predecessor) 88,607 5,406 187,993 125,345 June 30, 2016 (Predecessor) 62,140 4,233 121,147 86,564 December 31, 2016 (Successor) 63,728 2,777 113,603 85,439 December 31, 2017 (Successor) 55,005 1,335 58,918 66,160 Proved undeveloped reserves June 30, 2014 (Predecessor) 68,916 3,684 141,940 96,256 June 30, 2015 (Predecessor) 40,989 2,070 90,550 58,151 June 30, 2016 (Predecessor) — — — — December 31, 2016 (Successor) 31,522 371 27,635 36,498 December 31, 2017 (Successor) 19,351 345 14,067 22,039
Schedule of the standardized measure of discounted future net cash flows related to proved oil and natural gas reserves	The standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves follows ( in thousands ): Successor Predecessor As of As of As of December 31, December 31, June 30, 2017 2016 2016 2015 Future cash inflows $ 4,044,208 $ 4,344,985 $ 2,966,317 $ 10,641,151 Less related future Production costs 2,714,819 2,648,363 2,223,645 4,131,526 Development and abandonment costs 1,425,847 1,571,271 1,033,717 1,970,526 Income taxes — — — 168,655 Future net cash flows (96,458) 125,351 (291,045) 4,370,444 Less: Ten percent annual discount for estimated timing of cash flows (111,594) (23,494) (349,398) 1,613,034 Standardized measure of discounted future net cash flows (Predecessor) $ 58,353 $ 2,757,410 Standardized measure of discounted future net cash flows (Successor) $ 15,136 $ 148,845
Schedule of the summary of changes in the standardized measure of discounted future cash flows applicable to proved oil and natural gas reserves	A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves follows ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Beginning of period (Predecessor) $ 148,845 $ 58,353 $ 2,757,410 $ 5,947,525 Revisions of previous estimates Changes in prices and costs 252,357 (104,993) (3,287,459) (2,959,883) Changes in quantities (198,211) 53,585 (214,631) (2,390,099) Additions to proved reserves resulting from extensions, discoveries, other additions and improved recovery, less related costs 8,908 325,892 26,911 201,234 Purchases (sales) of reserves in place — — 212,961 (244,507) Accretion of discount 14,885 (893) 215,297 760,175 Sales, net of production and gathering and transportation costs (224,976) (131,947) (212,581) (676,949) Net change in income taxes — — 77,025 1,576,954 Changes in rate of production and other (22,862) (2,704) 4,189 (191,668) Development costs incurred 3,878 11,283 10,493 237,173 Changes in estimated future development and abandonment costs 32,312 (59,731) 468,738 497,455 Net change (133,709) 90,492 (2,699,057) (3,190,115) End of period (Predecessor) $ 58,353 $ 2,757,410 End of period (Successor) $ 15,136 $ 148,845

Organization (Details)

Organization (Details)	12 Months Ended
	Dec. 31, 2017ft
Maximum
Oil and natural gas properties
Off shore oil and gas properties, Depth of water (in feet)	1,000

Revision of Prior Period Fina52

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Revision of Prior Period Financial Statements (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2017	Dec. 31, 2017	Jun. 30, 2016
Revision of Prior Period Financial Statements
Net income (loss)	$ (406,275)	$ (215,069)	$ (35,157)	$ (26,237)	$ (64,547)			$ (90,784)	$ (406,275)	$ (125,941)	$ (341,010)
Asset retirement obligations	680,507	613,453				$ 680,507			680,507		613,453
Additional paid-in capital	901,658	$ 911,144				901,658			901,658		$ 911,144
Adjustment
Revision of Prior Period Financial Statements
Net income (loss)			$ (3,577)	$ (2,594)	$ 768			$ (1,826)		$ (5,403)
Asset retirement obligations	(16,256)					(16,256)			(16,256)
Additional paid-in capital	$ 21,372					21,372			21,372
Predecessor
Revision of Prior Period Financial Statements
Net income (loss)						2,771,349	$ (120,738)		2,650,611			$ (1,918,659)
Predecessor | Adjustment
Revision of Prior Period Financial Statements
Net income (loss)						$ (13,700)	$ 10,408		$ (3,292)			$ 92

Revision of Prior Period Fina53

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Revision of Prior Period Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	$ 151,729	$ 165,368
Accounts receivable, net
Oil and natural gas sales	55,598	69,744
Joint interest billings	6,336	6,029
Other	15,726	17,944
Prepaid expenses and other current assets	21,602	17,980
Restricted cash	6,392	32,337
Total Current Assets	257,383	309,402
Property and Equipment
Oil and natural gas properties, net	764,922	1,097,471
Other property and equipment, net	10,120	20,007
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	775,042	1,117,478
Other Assets
Restricted cash	25,712	25,583
Other assets and debt issuance costs, net of accumulated amortization	18,845	28,244
Total Other Assets	44,557	53,827
Total Assets	1,076,982	1,480,707
Current Liabilities
Accounts payable	85,122	101,117
Accrued liabilities	45,494	55,675
Asset retirement obligations	51,398	56,601
Current maturities of long-term debt	21	4,268
Total Current Liabilities	214,602	217,661
Long-term debt, less current maturities	73,952	74,229
Asset retirement obligations	613,453	680,507
Other liabilities	10,783	12,595
Total Liabilities	912,790	984,992
Stockholders' Equity
Common stock, $0.01 par value, 100,000,000 shares authorized and 33,254,963 and 33,211,594 shares issued and outstanding at December 31, 2017 and December 31, 2016, respectively	333	332
Additional paid-in capital	911,144	901,658
Accumulated deficit	(747,285)	(406,275)
Total Stockholders' Equity	164,192	495,715
Total Liabilities and Stockholders' Equity	$ 1,076,982	1,480,707
As reported
Current Assets
Cash and cash equivalents		165,368
Accounts receivable, net
Oil and natural gas sales		68,143
Joint interest billings		5,600
Other		17,944
Prepaid expenses and other current assets		25,957
Restricted cash		32,337
Total Current Assets		315,349
Property and Equipment
Oil and natural gas properties, net		1,097,479
Other property and equipment, net		18,807
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		1,116,286
Other Assets
Restricted cash		25,583
Other assets and debt issuance costs, net of accumulated amortization		28,244
Total Other Assets		53,827
Total Assets		1,485,462
Current Liabilities
Accounts payable		101,117
Accrued liabilities		63,660
Asset retirement obligations		56,601
Current maturities of long-term debt		4,268
Total Current Liabilities		225,646
Long-term debt, less current maturities		74,229
Asset retirement obligations		696,763
Other liabilities		14,481
Total Liabilities		1,011,119
Stockholders' Equity
Common stock, $0.01 par value, 100,000,000 shares authorized and 33,254,963 and 33,211,594 shares issued and outstanding at December 31, 2017 and December 31, 2016, respectively		332
Additional paid-in capital		880,286
Accumulated deficit		(406,275)
Total Stockholders' Equity		474,343
Total Liabilities and Stockholders' Equity		1,485,462
Adjustment
Accounts receivable, net
Oil and natural gas sales		1,601
Joint interest billings		429
Prepaid expenses and other current assets		(7,977)
Total Current Assets		(5,947)
Property and Equipment
Oil and natural gas properties, net		(8)
Other property and equipment, net		1,200
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		1,192
Other Assets
Total Assets		(4,755)
Current Liabilities
Accrued liabilities		(7,985)
Total Current Liabilities		(7,985)
Asset retirement obligations		(16,256)
Other liabilities		(1,886)
Total Liabilities		(26,127)
Stockholders' Equity
Additional paid-in capital		21,372
Total Stockholders' Equity		21,372
Total Liabilities and Stockholders' Equity		$ (4,755)

Revision of Prior Period Fina54

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Revision of Prior Period Income Statement (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Dec. 31, 2016	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016
Revenues
Oil sales			$ 113,697	$ 118,484	$ 133,793			$ 252,277		$ 365,974	$ 481,922
Natural gas liquids sales			2,209	2,370	2,227			4,597		6,806	8,542
Natural gas sales			12,261	13,753	18,368			32,121		44,382	53,805
Gain on derivative financial instruments			(12,466)	9,412	3,698			13,110		644	(32,625)
Total Revenues			115,701	144,019	158,086			302,105		417,806	511,644
Costs and Expenses
Lease operating			77,822	83,655	77,267			160,922		238,744	319,671
Production taxes			471	482	239			721		1,192	1,355
Gathering and transportation			(2,441)	2,678	11,222			13,900		11,459	21,666
Pipeline facility fee			10,495	10,494	10,494			20,988		31,483	41,977
Depreciation, depletion and amortization			36,131	38,685	41,896			80,581		116,712	150,151
Accretion of asset retirement obligations			9,753	9,984	13,081			23,065		32,818	42,780
Impairment of oil and natural gas properties	$ 406,275	$ 145,100			40,774			40,774		40,774	185,860	$ 406,300
General and administrative expense			15,026	20,716	23,848			42,320		57,346	72,057
Total Costs and Expenses	406,275		147,257	166,694	218,821			385,515		532,772	838,072
Operating Loss	(406,275)	(211,462)	(31,556)	(22,675)	(60,735)			(83,410)		(114,966)	(326,428)
Other (Expense) Income
Other income, net			52	80	22			102		154	254
Interest expense			(3,653)	(3,642)	(3,834)			(7,476)		(11,129)	(14,836)
Total Other (Expense) Income, net			(3,601)	(3,562)	(3,812)			(7,374)		(10,975)	(14,582)
Loss Before Reorganization Items and Income Taxes	(406,275)										(341,010)
(Loss) Income Before Income Taxes	(406,275)		(35,157)	(26,237)	(64,547)			(90,784)		(125,941)	(341,010)
Income Tax Benefit											0
Net (Loss) Income	(406,275)	$ (215,069)	$ (35,157)	$ (26,237)	$ (64,547)			$ (90,784)	$ (406,275)	$ (125,941)	(341,010)
Net (Loss) Income Attributable to Common Stockholders	$ (406,275)										$ (341,010)
(Loss) Earnings per Share
Basic (in dollars per share)	$ (12.23)										$ (10.26)
Diluted (in dollars per share)	$ (12.23)										$ (10.26)
Basic and Diluted (in dollars per share)		$ (6.47)	$ (1.06)	$ (0.79)	$ (1.94)			$ (2.73)		$ (3.79)
Weighted Average Number of Common Shares Outstanding
Basic (in shares)	33,212										33,239
Diluted (in shares)	33,212										33,239
Basic and Diluted (in shares)			33,241	33,237	33,228			33,234		33,236
Predecessor
Revenues
Oil sales							$ 123,084		256,050				$ 532,505
Natural gas liquids sales							2,144		3,533				14,852
Natural gas sales							17,735		37,103				69,255
Gain on derivative financial instruments													90,506
Total Revenues						$ 153,723	142,963		296,686				707,118
Costs and Expenses
Lease operating							65,170		136,578				328,183
Production taxes							214		482				1,442
Gathering and transportation							7,534		5,910				33,156
Pipeline facility fee							10,165		20,330				40,659
Depreciation, depletion and amortization							31,141		60,202				339,539
Accretion of asset retirement obligations							19,075		38,380				64,708
Impairment of oil and natural gas properties							77,558		77,781				2,814,028
General and administrative expense							15,435		27,557				102,736
Total Costs and Expenses							226,292		367,220				3,724,451
Operating Loss						12,795	(83,329)		(70,534)				(3,017,333)
Other (Expense) Income
Loss from equity method investees													(10,746)
Other income, net							62		117				3,596
Gains (Losses) on Extinguishment of Debt													1,525,596
Interest expense							(4,838)		(12,580)				(405,658)
Total Other (Expense) Income, net							(4,776)		(12,463)				1,112,788
Loss Before Reorganization Items and Income Taxes							(88,105)		(82,997)				(1,904,545)
Reorganization items							(32,633)		2,733,608				(14,201)
(Loss) Income Before Income Taxes							(120,738)		2,650,611				(1,918,746)
Income Tax Benefit													(87)
Net (Loss) Income						$ 2,771,349	$ (120,738)		$ 2,650,611				(1,918,659)
Preferred Stock Dividends													5,194
Net (Loss) Income Attributable to Common Stockholders													$ (1,923,853)
(Loss) Earnings per Share
Basic (in dollars per share)						$ 28.04			$ 26.95
Diluted (in dollars per share)						$ 26.45			$ 25.30
Basic and Diluted (in dollars per share)							$ (1.23)						$ (20.08)
Weighted Average Number of Common Shares Outstanding
Basic (in shares)						98,850			98,337
Diluted (in shares)						104,787			104,787
Basic and Diluted (in shares)							97,824						95,822
As reported
Revenues
Oil sales			$ 114,991	$ 118,180	$ 133,621			$ 251,801		$ 366,792
Natural gas liquids sales			2,209	2,370	2,227			4,597		6,806
Natural gas sales			12,261	13,753	18,368			32,121		44,382
Gain on derivative financial instruments			(12,466)	9,412	3,698			13,110		644
Total Revenues			116,995	143,715	157,914			301,629		418,624
Costs and Expenses
Lease operating			77,822	85,336	75,157			160,493		238,315
Production taxes			471	482	239			721		1,192
Gathering and transportation			(2,441)	2,678	11,222			13,900		11,459
Pipeline facility fee			10,495	10,494	10,494			20,988		31,483
Depreciation, depletion and amortization			36,066	38,661	42,006			80,667		116,733
Accretion of asset retirement obligations			9,892	10,050	12,397			22,447		32,339
Impairment of oil and natural gas properties			(2,357)	(848)	44,054			43,206		40,849
General and administrative expense			15,026	20,716	23,848			42,320		57,346
Total Costs and Expenses			144,974	163,796	219,417			383,213		528,187
Operating Loss			(27,979)	(20,081)	(61,503)			(81,584)		(109,563)
Other (Expense) Income
Other income, net			52	80	22			102		154
Interest expense			(3,653)	(3,642)	(3,834)			(7,476)		(11,129)
Total Other (Expense) Income, net			(3,601)	(3,562)	(3,812)			(7,374)		(10,975)
(Loss) Income Before Income Taxes			(31,580)	(23,643)	(65,315)			(88,958)		(120,538)
Net (Loss) Income			$ (31,580)	$ (23,643)	$ (65,315)			$ (88,958)		$ (120,538)
(Loss) Earnings per Share
Basic and Diluted (in dollars per share)			$ (0.95)	$ (0.71)	$ (1.97)			$ (2.68)		$ (3.63)
Weighted Average Number of Common Shares Outstanding
Basic and Diluted (in shares)			33,241	33,237	33,228			33,234		33,236
As reported | Predecessor
Revenues
Oil sales							$ 122,732		$ 255,040				$ 531,914
Natural gas liquids sales							2,144		3,533				14,852
Natural gas sales							17,735		37,103				69,255
Gain on derivative financial instruments													90,506
Total Revenues						$ 153,065	142,611		295,676				706,527
Costs and Expenses
Lease operating							65,170		137,007				328,183
Production taxes							214		482				1,442
Gathering and transportation							7,534		5,910				33,156
Pipeline facility fee							10,165		20,330				40,659
Depreciation, depletion and amortization							31,573		60,626				339,516
Accretion of asset retirement obligations							19,437		38,973				64,690
Impairment of oil and natural gas properties							86,820		86,820				2,813,570
General and administrative expense							15,435		27,557				102,736
Total Costs and Expenses							236,348		377,705				3,723,952
Operating Loss						11,708	(93,737)		(82,029)				(3,017,425)
Other (Expense) Income
Loss from equity method investees													(10,746)
Other income, net							62		117				3,596
Gains (Losses) on Extinguishment of Debt													1,525,596
Interest expense							(4,838)		(12,580)				(405,658)
Total Other (Expense) Income, net							(4,776)		(12,463)				1,112,788
Loss Before Reorganization Items and Income Taxes							(98,513)		(94,492)				(1,904,637)
Reorganization items							(32,633)		2,748,395				(14,201)
(Loss) Income Before Income Taxes							(131,146)		2,653,903				(1,918,838)
Income Tax Benefit													(87)
Net (Loss) Income						$ 2,785,049	$ (131,146)		$ 2,653,903				(1,918,751)
Preferred Stock Dividends													8,394
Net (Loss) Income Attributable to Common Stockholders													$ (1,927,145)
(Loss) Earnings per Share
Basic (in dollars per share)						$ 28.17			$ 26.99
Diluted (in dollars per share)						$ 26.58			$ 25.33
Basic and Diluted (in dollars per share)							$ (1.34)						$ (20.11)
Weighted Average Number of Common Shares Outstanding
Basic (in shares)						98,850			98,337
Diluted (in shares)						104,787			104,787
Basic and Diluted (in shares)							97,824						95,822
Adjustment
Revenues
Oil sales			$ (1,294)	$ 304	$ 172			$ 476		$ (818)
Total Revenues			(1,294)	304	172			476		(818)
Costs and Expenses
Lease operating				(1,681)	2,110			429		429
Depreciation, depletion and amortization			65	24	(110)			(86)		(21)
Accretion of asset retirement obligations			(139)	(66)	684			618		479
Impairment of oil and natural gas properties			2,357	848	(3,280)			(2,432)		(75)
Total Costs and Expenses			2,283	2,898	(596)			2,302		4,585
Operating Loss			(3,577)	(2,594)	768			(1,826)		(5,403)
Other (Expense) Income
(Loss) Income Before Income Taxes			(3,577)	(2,594)	768			(1,826)		(5,403)
Net (Loss) Income			$ (3,577)	$ (2,594)	$ 768			$ (1,826)		$ (5,403)
(Loss) Earnings per Share
Basic and Diluted (in dollars per share)			$ (0.11)	$ (0.08)	$ 0.02			$ (0.05)		$ (0.16)
Weighted Average Number of Common Shares Outstanding
Basic and Diluted (in shares)			33,241	33,237	33,228			33,234		33,236
Adjustment | Predecessor
Revenues
Oil sales							$ 352		$ 1,010				$ 591
Total Revenues						$ 658	352		1,010				591
Costs and Expenses
Lease operating									(429)
Depreciation, depletion and amortization							(432)		(424)				23
Accretion of asset retirement obligations							(362)		(593)				18
Impairment of oil and natural gas properties							(9,262)		(9,039)				458
Total Costs and Expenses							(10,056)		(10,485)				499
Operating Loss						1,087	10,408		11,495				92
Other (Expense) Income
Loss Before Reorganization Items and Income Taxes							10,408		11,495				92
Reorganization items									(14,787)
(Loss) Income Before Income Taxes							10,408		(3,292)				92
Net (Loss) Income						$ (13,700)	$ 10,408		$ (3,292)				92
Preferred Stock Dividends													(3,200)
Net (Loss) Income Attributable to Common Stockholders													$ 3,292
(Loss) Earnings per Share
Basic (in dollars per share)						$ (0.14)			$ (0.04)
Diluted (in dollars per share)						$ (0.13)			$ (0.03)
Basic and Diluted (in dollars per share)							$ 0.11						$ 0.03
Weighted Average Number of Common Shares Outstanding
Basic (in shares)						98,850			98,337
Diluted (in shares)						104,787			104,787
Basic and Diluted (in shares)							97,824						95,822

Revision of Prior Period Fina55

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Revision of Prior Period Cash Flow (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2016	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016
Cash Flows From Operating Activities
Net (loss) income	$ (406,275)									$ (341,010)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion and amortization			$ 36,131	$ 38,685	$ 41,896		$ 80,581		$ 116,712	150,151
Impairment of oil and natural gas properties	406,275	$ 145,100			40,774		40,774		40,774	185,860	$ 406,300
Change in fair value of derivative financial instruments										32,567
Accretion of asset retirement obligations			9,753	9,984	13,081		23,065		32,818	42,780
Amortization and write-off of debt issuance costs, payment of interest in kind and other										17
Deferred rent										7,891
Provision for loss on accounts receivable										600
Stock-based compensation										9,486
Changes in operating assets and liabilities
Accounts receivable										17,274
Prepaid expenses and other assets										5,167
Change in restricted cash										25,817
Settlement of asset retirement obligations										(55,820)
Accounts payable and accrued liabilities										(35,142)
Net Cash Provided by (Used in) Operating Activities										45,638
Cash Flows from Investing Activities
Capital expenditures										(59,223)
Insurance payments received										41
Proceeds from the sale of properties										4,119
Net Cash (Used in) Provided by Investing Activities										(55,063)
Cash Flows from Financing Activities
Payments on long-term debt										(4,153)
Debt issuance costs										(61)
Net Cash (Used in) Provided by Financing Activities										(4,214)
Net (Decrease) Increase in Cash and Cash Equivalents										(13,639)
Cash and Cash Equivalents, beginning of period					165,368		165,368		165,368	165,368
Cash and Cash Equivalents, end of period	165,368	$ 151,729						$ 165,368		151,729	165,368
As reported
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion and amortization			36,066	38,661	42,006		80,667		116,733
Impairment of oil and natural gas properties			(2,357)	(848)	44,054		43,206		40,849
Accretion of asset retirement obligations			9,892	10,050	12,397		22,447		32,339
Cash Flows from Financing Activities
Cash and Cash Equivalents, beginning of period					165,368		165,368		165,368	165,368
Cash and Cash Equivalents, end of period	165,368							165,368			165,368
Adjustment
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion and amortization			65	24	(110)		(86)		(21)
Impairment of oil and natural gas properties			2,357	848	(3,280)		(2,432)		(75)
Accretion of asset retirement obligations			$ (139)	$ (66)	684		618		479
Predecessor
Cash Flows From Operating Activities
Net (loss) income								2,650,611				$ (1,918,659)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion and amortization						$ 31,141		60,202				339,539
Impairment of oil and natural gas properties						77,558		77,781				2,814,028
Change in fair value of derivative financial instruments												19,163
Accretion of asset retirement obligations						19,075		38,380				64,708
Loss from equity method investees												10,746
Gain on early extinguishment of debt												(1,525,596)
Reorganization items								(2,824,176)
Amortization and write-off of debt issuance costs, payment of interest in kind and other								5,025				138,473
Deferred rent								3,355				9,154
Provision for loss on accounts receivable												3,200
Stock-based compensation								183				1,336
Changes in operating assets and liabilities
Accounts receivable								(17,555)				42,151
Prepaid expenses and other assets								(7,425)				(24,438)
Change in restricted cash								(25,157)
Settlement of asset retirement obligations								(18,852)				(78,273)
Accounts payable and accrued liabilities								40,155				(62,187)
Net Cash Provided by (Used in) Operating Activities								(17,473)				(166,655)
Cash Flows from Investing Activities
Acquisitions, net of cash												(2,797)
Capital expenditures								(20,237)				(111,884)
Insurance payments received												8,251
Change in restricted cash								31,748				(22,136)
Proceeds from the sale of properties												5,693
Other								195				(40)
Net Cash (Used in) Provided by Investing Activities								11,706				(122,913)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs												334
Dividends to shareholders - preferred												(5,673)
Proceeds from long-term debt												1,121
Payments on long-term debt								(32,088)				(227,884)
Payment of debt assumed in acquisition												(25,187)
Fees related to debt extinguishment												(3,526)
Debt issuance costs												(2,163)
Other								(35)				(1,044)
Net Cash (Used in) Provided by Financing Activities								(32,123)				(264,022)
Net (Decrease) Increase in Cash and Cash Equivalents								(37,890)				(553,590)
Cash and Cash Equivalents, beginning of period					165,368	203,258	165,368	203,258	165,368	165,368		756,848
Cash and Cash Equivalents, end of period	165,368							165,368			165,368	203,258
Predecessor | As reported
Cash Flows From Operating Activities
Net (loss) income								2,653,903				(1,918,751)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion and amortization						31,573		60,626				339,516
Impairment of oil and natural gas properties						86,820		86,820				2,813,570
Change in fair value of derivative financial instruments												19,163
Accretion of asset retirement obligations						19,437		38,973				64,690
Loss from equity method investees												10,746
Gain on early extinguishment of debt												(1,525,596)
Reorganization items								(2,838,963)
Amortization and write-off of debt issuance costs, payment of interest in kind and other								5,025				138,473
Deferred rent								3,355				9,154
Provision for loss on accounts receivable												3,200
Stock-based compensation								183				1,336
Changes in operating assets and liabilities
Accounts receivable								(16,545)				42,742
Prepaid expenses and other assets								(7,425)				(24,438)
Change in restricted cash								(25,157)
Settlement of asset retirement obligations								(18,852)				(78,273)
Accounts payable and accrued liabilities								40,584				(62,187)
Net Cash Provided by (Used in) Operating Activities								(17,473)				(166,655)
Cash Flows from Investing Activities
Acquisitions, net of cash												(2,797)
Capital expenditures								(20,237)				(111,884)
Insurance payments received												8,251
Change in restricted cash								31,748				(22,136)
Proceeds from the sale of properties												5,693
Other								195				(40)
Net Cash (Used in) Provided by Investing Activities								11,706				(122,913)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs												334
Dividends to shareholders - preferred												(5,673)
Proceeds from long-term debt												1,121
Payments on long-term debt								(32,088)				(227,884)
Payment of debt assumed in acquisition												(25,187)
Fees related to debt extinguishment												(3,526)
Debt issuance costs												(2,163)
Other								(35)				(1,044)
Net Cash (Used in) Provided by Financing Activities								(32,123)				(264,022)
Net (Decrease) Increase in Cash and Cash Equivalents								(37,890)				(553,590)
Cash and Cash Equivalents, beginning of period					$ 165,368	203,258	$ 165,368	203,258	$ 165,368	$ 165,368		756,848
Cash and Cash Equivalents, end of period	$ 165,368							165,368			$ 165,368	203,258
Predecessor | Adjustment
Cash Flows From Operating Activities
Net (loss) income								(3,292)				92
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion and amortization						(432)		(424)				23
Impairment of oil and natural gas properties						(9,262)		(9,039)				458
Accretion of asset retirement obligations						$ (362)		(593)				18
Reorganization items								14,787
Changes in operating assets and liabilities
Accounts receivable								(1,010)				$ (591)
Accounts payable and accrued liabilities								$ (429)

Revision of Prior Period Fina56

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Principles of Consolidation and Reporting (Details) - Predecessor - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015
Reclassifications
Reclassification from lease operating expense	$ 6.7	$ 17.9	$ 13.6
Reclassification into gathering and transportation expenses	6.7	17.9	13.6
Reclassification from gathering and transportation expenses	21	40.7	0
Reclassification into pipeline facility fee expense	$ 21	$ 40.7	$ 0

Revision of Prior Period Fina57

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Use of Estimates (Details) - MMBoe	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Use of Estimates
Proved reserves (Energy)	88,199	109.4	121,937
Predecessor
Use of Estimates
Proved reserves (Energy)				86,564	183,496	246,198

Revision of Prior Period Fina58

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Cash and Cash Equivalents (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Cash and Cash Equivalents
Cash and cash equivalents	$ 151,729	$ 165,368
Money market account
Cash and Cash Equivalents
Cash and cash equivalents	$ 25,100

Revision of Prior Period Fina59

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Money market account
Restricted Cash
Restricted cash	$ 6	$ 6

Revision of Prior Period Fina60

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Accounts Receivable and Allowance for Doubtful Accounts
Allowance for doubtful accounts	$ 0.6	$ 0

Revision of Prior Period Fina61

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Oil and Natural Gas Properties (Details) $ in Thousands	Dec. 31, 2016USD ($)MMBoe	Dec. 31, 2017USD ($)MMBoe	Mar. 31, 2017USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2016USD ($)MMBoe	Dec. 31, 2015USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)MMBoe	Dec. 31, 2016USD ($)MMBoe	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)MMBoe	Jun. 30, 2014MMBoe
Oil and gas properties
Impairment of oil and natural gas properties	$ 406,275	$ 145,100	$ 40,774						$ 40,774			$ 40,774	$ 185,860	$ 406,300
Proved undeveloped reserves (Energy) | MMBoe	36,498	22,039								36,498			22,039	36,498
Future development costs associated with proved undeveloped reserves	$ 443,200	$ 356,100								$ 443,200			$ 356,100	$ 443,200
Maximum expected period from properties first recognized as proved undeveloped to being developed													5 years
Predecessor
Oil and gas properties
Impairment of oil and natural gas properties				$ 77,600	$ 143,100	$ 340,500	$ 1,425,800	$ 904,700		$ 77,781	$ 2,330,500				$ 2,814,028	$ 2,421,884
Proved undeveloped reserves (Energy) | MMBoe																58,151	96,256

Revision of Prior Period Fina62

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Other Property and Equipment (Details) - Other Property and Equipment	12 Months Ended
	Dec. 31, 2017
Minimum
Other Property and Equipment
Useful life of properties	3 years
Maximum
Other Property and Equipment
Useful life of properties	5 years

Revision of Prior Period Fina63

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Goodwill (Details) - Predecessor - USD ($) $ in Thousands	Dec. 31, 2014	Jun. 30, 2015
Goodwill
Goodwill impairment	$ 329,300	$ 329,293
Goodwill	$ 0

Revision of Prior Period Fina64

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - G & A (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015
General and Administrative Expense
Capitalized general and administrative costs related to exploration and development activities	$ 16.4
Predecessor
General and Administrative Expense
Capitalized general and administrative costs related to exploration and development activities		$ 7.8	$ 17	$ 49.2

Revision of Prior Period Fina65

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Income Taxes
U.S. federal statutory income tax rate (as a percent)	35.00%		35.00%
Federal statutory tax rate used to calculate provisional effect of the Tax Reform Act in the period of enactment (as a percent)			21.00%
Decrease in tax-effected deferred tax assets due to 2017 Tax Reform			$ 204,000
Reduction in valuation allowance due to 2017 Tax Reform			204,000
Net effect on income tax expense or benefit due to 2017 Tax Reform			$ 0
Tax deduction for cost of property due to 2017 Tax Reform (as a percent)			100.00%
Net operating loss carryovers	$ 339,000		$ 339,000
Tax basis of asset retirement obligation			0
Valuation allowance	$ 167,645		306,206
Increase in valuation allowance			$ 224,000
Forecast
Income Taxes
U.S. federal statutory income tax rate (as a percent)		21.00%

Revision of Prior Period Fina66

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Income Taxes Emergence (Details) - USD ($) $ in Thousands	Dec. 30, 2016	Jun. 30, 2016	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2016	Sep. 30, 2012
Income Taxes
Valuation allowance			$ 306,206			$ 167,645
Tax basis of asset retirement obligation			0
Increase in valuation allowance			224,000
Predecessor
Income Taxes
Debt instrument, stated interest rate (as a percent)	4.14%
Face value	$ 5,500
Percentage of stock cancelled	100.00%
Withholding tax rate (as a percent)	30.00%	30.00%
Valuation allowance		$ 1,029,300		$ 1,029,300	$ 379,300
Additional tax basis	$ 633,000
Increase in amount related to the change in total CODI excluded	663,000
Change in estimates of tax attributes	$ 30,000
Increase in valuation allowance			$ 224,000	$ 650,000	$ 356,800
4.14% Promissory Note due 2017
Income Taxes
Debt instrument, stated interest rate (as a percent)	4.14%		4.14%			4.14%
4.14% Promissory Note due 2017 | Predecessor
Income Taxes
Debt instrument, stated interest rate (as a percent)	4.14%					4.14%
Face value	$ 5,500						$ 5,500

Revision of Prior Period Fina67

Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - CODI (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Cancellation of Debt Income
Pre-tax reductions in net operating loss carryovers	$ 681
Pre-tax reductions in oil and natural gas properties	915
Pre-tax reductions in EPL stock basis	304
Pre-tax reductions in others	18
CODI excluded requiring attribute reduction	$ 1,918
U.S. federal statutory income tax rate (as a percent)	35.00%		35.00%
Forecast
Cancellation of Debt Income
U.S. federal statutory income tax rate (as a percent)		21.00%
As reported
Cancellation of Debt Income
Pre-tax reductions in net operating loss carryovers	$ 486
Pre-tax reductions in oil and natural gas properties	1,485
Pre-tax reductions in EPL stock basis	543
Pre-tax reductions in others	67
CODI excluded requiring attribute reduction	$ 2,581

Chapter 11 Proceedings - Genera

Chapter 11 Proceedings - General (Details) - USD ($) $ / shares in Units, $ in Thousands	Dec. 31, 2016	Dec. 31, 2017	Mar. 31, 2017	Jun. 30, 2017	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Jan. 06, 2017	Dec. 30, 2016
Chapter 11 Proceedings
Maximum percentage of voting shares received							50.00%
Common stock, par value	$ 0.01	$ 0.01				$ 0.01	$ 0.01	$ 0.01	$ 0.01
Impairment of oil and natural gas properties	$ 406,275	$ 145,100	$ 40,774	$ 40,774	$ 40,774	$ 185,860	$ 406,300

Chapter 11 Proceedings - Prepet

Chapter 11 Proceedings - Prepetition Revolving Credit Facilty and Exit Facility (Details) $ in Thousands	Mar. 03, 2017	Dec. 30, 2016USD ($)item	Dec. 31, 2017USD ($)	Mar. 13, 2017USD ($)
Chapter 11 Proceedings
Long term debt			$ 74,017
Exit Facility
Chapter 11 Proceedings
Debt instrument term		3 years
Minimum percentage of total value of the entity's and subsidiary guarantors' proved reserves required to be covered by mortgages to secure debt	90.00%	90.00%
Number of facilities | item		2
Letters of credit outstanding			202,600
Exit Term Loan
Chapter 11 Proceedings
Long term debt		$ 74,000
Exit Revolving Facility
Chapter 11 Proceedings
Maximum borrowing capacity		227,800
Letters of credit outstanding		$ 225,000	$ 200,000	$ 200,000

Chapter 11 Proceedings - Equity

Chapter 11 Proceedings - Equity Interests and Warrant Agreement (Details) - USD ($) $ in Thousands	Dec. 30, 2016	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015
Chapter 11 Proceedings
Assets		$ 1,480,707	$ 1,076,982	$ 1,480,707
Shares issued (as a percent)		100.00%
Holders of EGC Unsecured Notes and EPL Unsecured Notes
Chapter 11 Proceedings
Number of warrants issued (in shares)	2,119,889	2,119,889
Holders of EGC Unsecured Notes
Chapter 11 Proceedings
Number of warrants issued (in shares)	1,271,933	1,271,933		1,271,933
Holders of EPL Unsecured Notes
Chapter 11 Proceedings
Number of warrants issued (in shares)	847,956	847,956
Predecessor
Chapter 11 Proceedings
Assets		$ 0		$ 0
Amount of payments made to shareholders		$ 0
Debt instrument, stated interest rate (as a percent)	4.14%
Predecessor | 8.25% Senior Notes due 2018
Chapter 11 Proceedings
Debt instrument, stated interest rate (as a percent)		8.25%		8.25%	8.25%	8.25%
Common Stock
Chapter 11 Proceedings
Number of shares issued		33,212,000	43,000
Common Stock | Holders of Second Lien Notes
Chapter 11 Proceedings
Number of shares issued	27,897,739	27,897,739
Common Stock | Holders of EGC Unsecured Notes
Chapter 11 Proceedings
Number of shares issued	3,985,391	3,985,391
Common Stock | Holders of EPL Unsecured Notes
Chapter 11 Proceedings
Number of shares issued	1,328,464	1,328,464
Common Stock | Predecessor
Chapter 11 Proceedings
Number of shares issued		3,146,000			3,181,000	923,000

Chapter 11 Proceedings - Amendm

Chapter 11 Proceedings - Amendments to Articles of Incorporation or Bylaws (Details) - $ / shares	Dec. 31, 2017	Jan. 06, 2017	Dec. 31, 2016	Dec. 30, 2016
Amendments to Articles of Incorporation or Bylaws
Capital stock, shares authorized	110,000,000			110,000,000
Common stock, shares authorized	100,000,000		100,000,000	100,000,000
Common stock, par value	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000		10,000,000	10,000,000
Preferred stock, par value	$ 0.01		$ 0.01	$ 0.01

Chapter 11 Proceedings - Intere

Chapter 11 Proceedings - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	9 Months Ended
	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2016
Predecessor
Chapter 11 Proceedings
Interest on liabilities subject to compromise	$ 52.8	$ 123.7	$ 176.5

Chapter 11 Proceedings - Potent

Chapter 11 Proceedings - Potential Claims (Details) - USD ($) $ in Millions	Dec. 31, 2017	Jun. 17, 2017
Litigation claim to be paid at pro rata share
Chapter 11 Proceedings
General unsecured claims, accrual	$ 1.5	$ 1.5

Fresh Start Accounting - Genera

Fresh Start Accounting - General (Details) - USD ($) $ in Thousands	Dec. 30, 2016	Dec. 31, 2016
Fresh Start Accounting
Maximum percentage of voting shares received		50.00%
Enterprise Value		$ 815,119
Proved location drilling period	5 years
Forward price period		4 years
Inflation adjustment period		4 years
Cost of capital (as a percent)		11.10%
Proved reserves		$ 1,127,600
Probable reserves		295,300
Possible reserves		$ 80,800
Minimum
Fresh Start Accounting
Enterprise Value	$ 600,000
Maximum
Fresh Start Accounting
Maximum percentage of voting shares received		50.00%
Enterprise Value	900,000
Weighted average
Fresh Start Accounting
Enterprise Value	$ 815,100
Cost of capital (as a percent)		11.10%

Fresh Start Accounting - Reconc

Fresh Start Accounting - Reconciliation of enterprise value to estimated fair value of Successor (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Reorganization
Enterprise Value		$ 815,119
Add: Cash and cash equivalents	$ 151,729	165,368
Less: Fair value of debt		(78,497)
Fair Value of Successor common stock and warrants		901,990
Less: Fair value of warrants		(8,056)
Fair Value of Successor common stock		893,934
Predecessor Company before Reorganization and Fresh-Start Adjustments
Reorganization
Add: Cash and cash equivalents		164,817
Predecessor
Reorganization
Add: Cash and cash equivalents		165,368	$ 203,258	$ 756,848	$ 145,806
Fair Value of Successor common stock and warrants		$ 901,990

Fresh Start Accounting - Exit F

Fresh Start Accounting - Exit Facility and Warrants (Details) $ / shares in Units, $ in Thousands	Mar. 03, 2017	Dec. 30, 2016USD ($)item$ / sharesshares	Dec. 31, 2016shares	Dec. 31, 2017USD ($)
Credit facility
Long term debt | $				$ 74,017
Exit Facility
Credit facility
Debt instrument term		3 years
Minimum percentage of total value of the entity's and subsidiary guarantors' proved reserves required to be covered by mortgages to secure debt	90.00%	90.00%
Number of facilities | item		2
Exit Term Loan
Credit facility
Long term debt | $		$ 74,000
Holders of EGC Unsecured Notes and EPL Unsecured Notes
Warrants
Number of warrants issued (in shares) | shares		2,119,889	2,119,889
Number of shares issued upon exercise of each warrant | shares		1
Exercise price of warrant (in dollars per share) | $ / shares		$ 43.66
Minimum percentage increase or decrease in the exercise price resulting from cumulative adjustments to the applicable exercise price		1.00%
Fair value of warrant (in dollars per warrant) | $ / shares		$ 3.80

Fresh Start Accounting - Reco77

Fresh Start Accounting - Reconciliation of enterprise value to estimated reorganization of Successor (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Reorganization
Enterprise Value		$ 815,119
Add: Cash and cash equivalents	$ 151,729	165,368
Add: Other working capital liabilities		156,792
Add: Other long-term liabilities	10,783	12,595
Add: Asset retirement obligation	$ 664,851	737,108
Reorganization value of Successor assets		1,886,982
Predecessor Company before Reorganization and Fresh-Start Adjustments
Reorganization
Add: Cash and cash equivalents		164,817
Add: Other long-term liabilities		22,776
Predecessor
Reorganization
Add: Cash and cash equivalents		165,368	$ 203,258	$ 756,848	$ 145,806
Add: Asset retirement obligation		$ 551,468	$ 537,637

Fresh Start Accounting - Reorga

Fresh Start Accounting - Reorganization and Application of ASC 852 and Impairment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 30, 2016	Dec. 31, 2017	Mar. 31, 2017	Sep. 30, 2016	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015
Reorganization
Impairment of oil and natural gas properties	$ 406,275		$ 145,100	$ 40,774		$ 40,774		$ 40,774	$ 185,860	$ 406,300
Current Assets
Cash and cash equivalents	165,368		151,729				$ 165,368		151,729	165,368
Accounts receivable, net
Oil and natural gas sales	69,744		55,598				69,744		55,598	69,744
Joint interest billings	6,029		6,336				6,029		6,336	6,029
Other Receivables, Net, Current	17,944		15,726				17,944		15,726	17,944
Prepaid expenses and other current assets	17,980		21,602				17,980		21,602	17,980
Restricted cash	32,337		6,392				32,337		6,392	32,337
Total Current Assets	309,402		257,383				309,402		257,383	309,402
Property and Equipment
Oil and natural gas properties, net	1,097,471		764,922				1,097,471		764,922	1,097,471
Other property and equipment, net	20,007		10,120				20,007		10,120	20,007
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	1,117,478		775,042				1,117,478		775,042	1,117,478
Other Assets
Restricted Cash and Cash Equivalents, Noncurrent	25,583		25,712				25,583		25,712	25,583
Other Assets, Miscellaneous, Noncurrent	28,244		18,845				28,244		18,845	28,244
Total Other Assets	53,827		44,557				53,827		44,557	53,827
Total Assets	1,480,707		1,076,982				1,480,707		1,076,982	1,480,707
Current Liabilities
Accounts payable	101,117		85,122				101,117		85,122	101,117
Accrued liabilities	55,675		45,494				55,675		45,494	55,675
Asset retirement obligations	56,601		51,398				56,601		51,398	56,601
Less: current maturities	4,268		21				4,268		21	4,268
Total Current Liabilities	217,661		214,602				217,661		214,602	217,661
Long-term debt, less current maturities	74,229		73,952				74,229		73,952	74,229
Asset retirement obligations	680,507		613,453				680,507		613,453	680,507
Other liabilities	12,595		10,783				12,595		10,783	12,595
Liabilities Not Subject to Compromise	984,992						984,992			984,992
Total Liabilities	984,992		912,790				984,992		912,790	984,992
Stockholders' Equity
Common stock	332		333				332		333	332
Additional paid-in capital	901,658		911,144				901,658		911,144	901,658
Accumulated deficit	(406,275)		(747,285)				(406,275)		(747,285)	(406,275)
Total Stockholders' Equity	495,715		164,192				495,715		164,192	495,715
Total Liabilities and Stockholders' Equity	1,480,707		$ 1,076,982				1,480,707		$ 1,076,982	1,480,707
Predecessor
Reorganization
Impairment of oil and natural gas properties					$ 77,558		77,781				$ 2,814,028
Current Assets
Cash and cash equivalents	165,368						165,368			165,368	$ 203,258	$ 756,848
Successor Company before Impairment
Current Assets
Cash and cash equivalents	165,368						165,368			165,368
Accounts receivable, net
Oil and natural gas sales	69,744						69,744			69,744
Joint interest billings	6,029						6,029			6,029
Other Receivables, Net, Current	17,944						17,944			17,944
Prepaid expenses and other current assets	17,980						17,980			17,980
Restricted cash	32,337						32,337			32,337
Total Current Assets	309,402						309,402			309,402
Property and Equipment
Oil and natural gas properties, net	1,503,746						1,503,746			1,503,746
Other property and equipment, net	20,007						20,007			20,007
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	1,523,753						1,523,753			1,523,753
Other Assets
Restricted Cash and Cash Equivalents, Noncurrent	25,583						25,583			25,583
Other Assets, Miscellaneous, Noncurrent	28,244						28,244			28,244
Total Other Assets	53,827						53,827			53,827
Total Assets	1,886,982						1,886,982			1,886,982
Current Liabilities
Accounts payable	101,117						101,117			101,117
Accrued liabilities	55,675						55,675			55,675
Asset retirement obligations	56,601						56,601			56,601
Less: current maturities	4,268						4,268			4,268
Total Current Liabilities	217,661						217,661			217,661
Long-term debt, less current maturities	74,229						74,229			74,229
Asset retirement obligations	680,507						680,507			680,507
Other liabilities	12,595						12,595			12,595
Liabilities Not Subject to Compromise	984,992						984,992			984,992
Total Liabilities	984,992						984,992			984,992
Stockholders' Equity
Common stock	332						332			332
Additional paid-in capital	901,658						901,658			901,658
Total Stockholders' Equity	901,990						901,990			901,990
Total Liabilities and Stockholders' Equity	1,886,982						1,886,982			1,886,982
Predecessor Company before Reorganization and Fresh-Start Adjustments
Current Assets
Cash and cash equivalents	164,817						164,817			164,817
Accounts receivable, net
Oil and natural gas sales	69,744						69,744			69,744
Joint interest billings	6,029						6,029			6,029
Other Receivables, Net, Current	18,909						18,909			18,909
Prepaid expenses and other current assets	46,123						46,123			46,123
Restricted cash	32,888						32,888			32,888
Total Current Assets	338,510						338,510			338,510
Property and Equipment
Oil and natural gas properties, net	491,521						491,521			491,521
Other property and equipment, net	15,049						15,049			15,049
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	506,570						506,570			506,570
Other Assets
Restricted Cash and Cash Equivalents, Noncurrent	25,583						25,583			25,583
Other Assets, Miscellaneous, Noncurrent	30,174						30,174			30,174
Total Other Assets	55,757						55,757			55,757
Total Assets	900,837						900,837			900,837
Current Liabilities
Accounts payable	67,876						67,876			67,876
Accrued liabilities	40,517						40,517			40,517
Asset retirement obligations	58,537						58,537			58,537
Less: current maturities	74,046						74,046			74,046
Total Current Liabilities	240,976						240,976			240,976
Asset retirement obligations	492,931						492,931			492,931
Other liabilities	22,776						22,776			22,776
Liabilities Not Subject to Compromise	756,683						756,683			756,683
Liabilities subject to compromise	2,931,419						2,931,419			2,931,419
Total Liabilities	3,688,102						3,688,102			3,688,102
Stockholders' Equity
Accumulated deficit	(4,633,620)						(4,633,620)			(4,633,620)
Total Stockholders' Equity	(2,787,265)						(2,787,265)			(2,787,265)
Total Liabilities and Stockholders' Equity	900,837						900,837			900,837
Predecessor Company before Reorganization and Fresh-Start Adjustments | Predecessor
Stockholders' Equity
Common stock	504						504			504
Additional paid-in capital	1,845,851						1,845,851			1,845,851
Reorganization Adjustments
Reorganization
Impairment of oil and natural gas properties		$ 406,300
Average oil and gas price period		12 months
Current Assets
Cash and cash equivalents	551						551			551
Accounts receivable, net
Other Receivables, Net, Current	(965)						(965)			(965)
Prepaid expenses and other current assets	(26,260)						(26,260)			(26,260)
Restricted cash	(551)						(551)			(551)
Total Current Assets	(27,225)						(27,225)			(27,225)
Other Assets
Total Assets	(27,225)						(27,225)			(27,225)
Current Liabilities
Accounts payable	33,241						33,241			33,241
Accrued liabilities	15,158						15,158			15,158
Less: current maturities	(69,778)						(69,778)			(69,778)
Total Current Liabilities	(21,379)						(21,379)			(21,379)
Long-term debt, less current maturities	74,229						74,229			74,229
Other liabilities	2,345						2,345			2,345
Liabilities Not Subject to Compromise	55,195						55,195			55,195
Liabilities subject to compromise	(2,931,419)						(2,931,419)			(2,931,419)
Total Liabilities	(2,876,224)						(2,876,224)			(2,876,224)
Stockholders' Equity
Common stock	332						332			332
Additional paid-in capital	901,658						901,658			901,658
Accumulated deficit	3,793,364						3,793,364			3,793,364
Total Stockholders' Equity	2,848,999						2,848,999			2,848,999
Total Liabilities and Stockholders' Equity	(27,225)						(27,225)			(27,225)
Reorganization Adjustments | Predecessor
Stockholders' Equity
Common stock	(504)						(504)			(504)
Additional paid-in capital	(1,845,851)						(1,845,851)			(1,845,851)
Fresh-Start Adjustments
Accounts receivable, net
Prepaid expenses and other current assets	(1,883)						(1,883)			(1,883)
Total Current Assets	(1,883)						(1,883)			(1,883)
Property and Equipment
Oil and natural gas properties, net	1,012,225						1,012,225			1,012,225
Other property and equipment, net	4,958						4,958			4,958
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	1,017,183						1,017,183			1,017,183
Other Assets
Other Assets, Miscellaneous, Noncurrent	(1,930)						(1,930)			(1,930)
Total Other Assets	(1,930)						(1,930)			(1,930)
Total Assets	1,013,370						1,013,370			1,013,370
Current Liabilities
Asset retirement obligations	(1,936)						(1,936)			(1,936)
Total Current Liabilities	(1,936)						(1,936)			(1,936)
Asset retirement obligations	187,576						187,576			187,576
Other liabilities	(12,526)						(12,526)			(12,526)
Liabilities Not Subject to Compromise	173,114						173,114			173,114
Total Liabilities	173,114						173,114			173,114
Stockholders' Equity
Accumulated deficit	840,256						840,256			840,256
Total Stockholders' Equity	840,256						840,256			840,256
Total Liabilities and Stockholders' Equity	1,013,370						1,013,370			1,013,370
Impairment Adjustment
Property and Equipment
Oil and natural gas properties, net	(406,275)						(406,275)			(406,275)
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	(406,275)						(406,275)			(406,275)
Other Assets
Total Assets	(406,275)						(406,275)			(406,275)
Stockholders' Equity
Accumulated deficit	(406,275)						(406,275)			(406,275)
Total Stockholders' Equity	(406,275)						(406,275)			(406,275)
Total Liabilities and Stockholders' Equity	$ (406,275)						$ (406,275)			$ (406,275)

Fresh Start Accounting - Reor79

Fresh Start Accounting - Reorganization Adjustments - Payments and accruals (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 30, 2016
Accounts receivable, net
Other Receivables, Net, Current	$ 15,726	$ 17,944
Prepaid expenses and other current assets	21,602	17,980
Current Liabilities
Accrued liabilities	$ 45,494	55,675
Successor Company before Impairment
Accounts receivable, net
Other Receivables, Net, Current		17,944
Prepaid expenses and other current assets		17,980
Current Liabilities
Accrued liabilities		55,675
Reorganization Adjustments
Accounts receivable, net
Other Receivables, Net, Current		(965)
Prepaid expenses and other current assets		(26,260)
Current Liabilities
Accrued liabilities		15,158
Liabilities subject to compromise		(2,931,419)
Reorganization Adjustments, Reinstated claims reclassified
Accounts receivable, net
Other Receivables, Net, Current		(1,000)
Current Liabilities
Accrued liabilities		2,400
Liabilities subject to compromise		(3,400)
Support parties of EGC abd EPL Unsecured Noteholders | Reorganization Adjustments, Professional fees
Current Liabilities
Accrued liabilities		1,700
Support parties of EGC Unsecured Noteholders | Reorganization Adjustments, Professional fees
Accounts receivable, net
Prepaid expenses and other current assets		(11,200)
Support parties of EPL Unsecured Noteholders | Reorganization Adjustments, Professional fees
Accounts receivable, net
Prepaid expenses and other current assets		(9,600)
EXXI Ltd's 3.0% Senior Convertible Notes Trustee | Reorganization Adjustments, Professional fees
Accounts receivable, net
Prepaid expenses and other current assets		(2,000)
EXXI Ltd's restructuring advisors | Reorganization Adjustments, Professional fees
Current Liabilities
Accrued liabilities		11,000
EXXI Ltd's restructuring advisors | Reorganization Adjustments, Success fees
Accounts receivable, net
Prepaid expenses and other current assets		$ (3,500)
4.14% Promissory Note due 2017
Current Liabilities
Debt instrument, stated interest rate (as a percent)	4.14%	4.14%	4.14%

Fresh Start Accounting - Reor80

Fresh Start Accounting - Reorganization Adjustments - Liabilities subject to compromise (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2017	Dec. 30, 2016	Jun. 30, 2016	Jun. 30, 2015
Liabilities Subject to Compromise
Fair value of common stocks and warrants issued per the Plan	$ (901,990)	$ (901,990)	$ (901,990)
4.14% Promissory Note due 2017
Liabilities Subject to Compromise
Rate of interest on notes payable	4.14%	4.14%	4.14%	4.14%	4.14%
Reorganization Adjustments
Liabilities Subject to Compromise
Total liabilities subject to compromise	$ (2,931,419)	$ (2,931,419)	$ (2,931,419)
Gain on settlement of liabilities subject to compromise			1,983,920
Predecessor
Liabilities Subject to Compromise
Rate of interest on notes payable					4.14%
Total debt	2,763,739	2,763,739	2,763,739
Accounts payable	37,424	37,424	37,424
Accrued liabilities	130,256	130,256	130,256
Total liabilities subject to compromise	2,931,419	2,931,419	2,931,419
Fair value of common stocks and warrants issued per the Plan	(901,990)	(901,990)	(901,990)
Fair value of reinstated accounts payable and accrued liabilities to be settled in cash	(43,509)	(43,509)	(43,509)
Cash payment for 3.0% Senior Convertible Notes	(2,000)
Gain on settlement of liabilities subject to compromise	$ 1,983,920	$ 1,983,900	$ 1,983,920
Predecessor | 11.0% Senior Secured Second Lien Notes due 2020
Liabilities Subject to Compromise
Rate of interest on notes payable	11.00%	11.00%	11.00%			11.00%	11.00%
Total debt	$ 1,450,000	$ 1,450,000	$ 1,450,000
Predecessor | 8.25% Senior Notes due 2018
Liabilities Subject to Compromise
Rate of interest on notes payable	8.25%	8.25%	8.25%			8.25%	8.25%
Total debt	$ 213,677	$ 213,677	$ 213,677
Predecessor | 6.875% Senior Notes due 2024
Liabilities Subject to Compromise
Rate of interest on notes payable	6.875%	6.875%	6.875%			6.875%	6.875%
Total debt	$ 143,993	$ 143,993	$ 143,993
Predecessor | 3.0% Senior Convertible Notes due 2018
Liabilities Subject to Compromise
Rate of interest on notes payable	3.00%	3.00%	3.00%			3.00%	3.00%
Total debt	$ 363,018	$ 363,018	$ 363,018
Predecessor | 7.50% Senior Notes due 2021
Liabilities Subject to Compromise
Rate of interest on notes payable	7.50%	7.50%	7.50%			7.50%	7.50%
Total debt	$ 238,071	$ 238,071	$ 238,071
Predecessor | 7.75% Senior Notes due 2019
Liabilities Subject to Compromise
Rate of interest on notes payable	7.75%	7.75%	7.75%			7.75%	7.75%
Total debt	$ 101,077	$ 101,077	$ 101,077
Predecessor | 9.25 Percent Senior Notes due 2017
Liabilities Subject to Compromise
Rate of interest on notes payable	9.25%	9.25%	9.25%			9.25%	9.25%
Total debt	$ 249,452	$ 249,452	$ 249,452
Predecessor | 4.14% Promissory Note due 2017
Liabilities Subject to Compromise
Rate of interest on notes payable	4.14%	4.14%	4.14%		4.14%
Total debt	$ 4,001	$ 4,001	$ 4,001
Predecessor | Capital lease obligations
Liabilities Subject to Compromise
Total debt	$ 450	$ 450	$ 450

Fresh Start Accounting - Reor81

Fresh Start Accounting - Reorganization Adjustments - Equity issuance (Details) - USD ($) $ / shares in Units, $ in Thousands	Dec. 30, 2016	Dec. 31, 2016	Dec. 31, 2016
Stockholders' Equity
Fair value of warrants		$ 8,056	$ 8,056
Reorganization Adjustments
Stockholders' Equity
Number of shares issued			33,211,594
Holders of EGC Unsecured Notes and EPL Unsecured Notes
Stockholders' Equity
Number of warrants issued (in shares)	2,119,889	2,119,889
Exercise price of warrant (in dollars per share)	$ 43.66
Fair value of warrants (in dollars per share)		$ 3.80	$ 3.80
Fair value of warrants		$ 8,100	$ 8,100
Holders of Second Lien Notes | Reorganization Adjustments
Stockholders' Equity
Number of shares issued			27,897,739
Holders of EGC Unsecured Notes
Stockholders' Equity
Number of warrants issued (in shares)	1,271,933	1,271,933	1,271,933
Holders of EGC Unsecured Notes | Reorganization Adjustments
Stockholders' Equity
Number of shares issued			3,985,391
Number of warrants issued (in shares)			847,956
Holders of EPL Unsecured Notes
Stockholders' Equity
Number of warrants issued (in shares)	847,956	847,956
Holders of EPL Unsecured Notes | Reorganization Adjustments
Stockholders' Equity
Number of shares issued			1,328,464
Number of shares issued upon exercise		2,119,889	2,119,889
Exercise price of warrant (in dollars per share)		$ 43.66	$ 43.66

Fresh Start Accounting - Reor82

Fresh Start Accounting - Reorganization Adjustments - Cumulative impact (Details) - Reorganization Adjustments $ in Thousands	6 Months Ended
	Dec. 31, 2016USD ($)
Reorganization
Gain on settlement of liabilities subject to compromise	$ 1,983,920
Cancellation of EXXI Ltd equity	1,846,355
Accrual of success fee	(12,651)
Payments made of plan support parties	(24,260)
Net impact to accumulated deficit	$ 3,793,364

Fresh Start Accounting - Fresh

Fresh Start Accounting - Fresh Start Adjustments (Details) $ in Millions	Dec. 30, 2016	Dec. 31, 2016USD ($)$ / MMBTU$ / bbl
Fresh Start Adjustments
Cost of capital (as a percent)		11.10%
Proved location drilling period	5 years
Inflation escalation factor (as a percent)		2.00%
Credit adjusted risk free rate (as a percent)		6.50%
Asset retirement obligation, fair value | $		$ 737.1
Weighted average
Fresh Start Adjustments
Cost of capital (as a percent)		11.10%
Oil Reserves | Weighted average
Fresh Start Adjustments
Weighted average commodity prices utilized in the determination of fair value		60.37
Natural Gas Reserves | Weighted average
Fresh Start Adjustments
Weighted average commodity prices utilized in the determination of fair value | $ / MMBTU		3.02
Natural Gas Liquids | Weighted average
Fresh Start Adjustments
Weighted average commodity prices utilized in the determination of fair value		25.36

Fresh Start Accounting - Reor84

Fresh Start Accounting - Reorganization Items (Details) - Predecessor - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2016	Jun. 30, 2016
Reorganization
Gain on settlement of liabilities subject to compromise	$ 1,983,920	$ 1,983,900		$ 1,983,920
Fresh start adjustments		840,300		840,256
Reorganization legal and professional fees and expenses		$ (58,000)	$ (32,600)	(90,568)	$ (14,201)
Gain (loss) on reorganization items				$ 2,733,608	$ (14,201)

Acquisitions and Dispositions -

Acquisitions and Dispositions - M21K Acquisition (Details) - Predecessor $ in Thousands	Aug. 11, 2015USD ($)$ / MMBTU$ / bbl
M21K
Acquisitions
Royalty interest, production proceeds threshold (in dollars per Bbl) | $ / bbl	65
Royalty interest, production proceeds threshold (in dollars per MMBTU) | $ / MMBTU	3.50
Royalty interest, production proceeds period	4 years
Royalty interest, production proceeds aggregate amount	$ 20,000
Additional payment due (as a percent)	20.00%
Asset retirement obligations	$ (66,700)
Net working capital	(21,301)
Fair value of debt assumed	(25,187)
Cash acquired in acquisition included in net working capital	1,000
M21K | Oil and natural gas properties - evaluated
Acquisitions
Oil and natural gas properties	73,910
M21K | Oil and natural gas properties - unevaluated
Acquisitions
Oil and natural gas properties	$ 39,278
EXXI M21K
Acquisitions
Percentage of investments under the equity method	20.00%

Acquisitions and Dispositions86

Acquisitions and Dispositions - Grand Isle Disposition (Details) - Predecessor - Grand Isle Gathering System - Disposal Group, Not Discontinued Operations $ in Millions	Jun. 30, 2015USD ($)
Dispositions
Cash consideration	$ 245
Gain (loss) on disposal	0
Reduction to cost pool related to divestiture	$ 248.9

Acquisitions and Dispositions87

Acquisitions and Dispositions - East Bay Field Disposition (Details) $ in Thousands	Jun. 30, 2015USD ($)item	Dec. 31, 2017USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)	Jul. 01, 2015USD ($)
Dispositions
Proceeds from the sale of properties		$ 4,119
Predecessor
Dispositions
Proceeds from the sale of properties			$ 5,693	$ 261,931
Predecessor | East Bay Field | Disposal Group, Not Discontinued Operations
Dispositions
Cash consideration	$ 21,000			21,000	$ 20,300
Amount of asset retirement obligation assumed by acquirer	$ 55,100
Number of installments | item	2
Proceeds from the sale of properties	$ 5,000
Percentage of overriding royalty interest retained	5.00%
Minimum average monthly WTI	$ 65,000
Maximum period for retained overriding royalty interest	5 years
Maximum receivable amount for overriding royalty interest	$ 7,000			$ 7,000	$ 6,400
Percentage of deep rights retained	50.00%
Gain (loss) on disposal	$ 0
Reduction to cost pool related to divestiture	$ 68,900

Goodwill (Details)

Goodwill (Details) $ in Thousands	Dec. 31, 2014USD ($)	Dec. 31, 2017item	Jun. 30, 2015USD ($)	Dec. 31, 2016USD ($)	Jun. 30, 2016USD ($)
Goodwill
Number of reporting units | item		1
Predecessor
Goodwill
Goodwill impairment	$ 329,300		$ 329,293
Goodwill.	0
Goodwill tax basis	0
Income tax benefit from goodwill impairment	$ 0
Predecessor | Catering Business
Goodwill
Goodwill.				$ 0	$ 800

Property and Equipment - Schedu

Property and Equipment - Schedule (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Oil and gas properties
Proved properties	$ 1,307,009	$ 1,127,608
Less: accumulated depreciation, depletion, amortization and impairment	(742,286)	(406,275)
Proved properties, net	564,723	721,333
Unevaluated properties	200,199	376,138
Oil and gas properties, net	764,922	1,097,471
Other property and equipment	13,780	20,007
Less: accumulated depreciation	(3,660)
Other property and equipment, net	10,120	20,007
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment	$ 775,042	$ 1,117,478

Property and Equipment - Additi

Property and Equipment - Additional information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MMBoe	Dec. 31, 2016USD ($)MMBoe
Property and Equipment
Proved undeveloped reserves (Energy) | MMBoe	22,039	36,498
Future development costs associated with proved undeveloped reserves	$ 356.1	$ 443.2
Maximum expected period from properties first recognized as proved undeveloped to being developed	5 years
Reduction in unevaluated properties	$ 175.9
Unevaluated properties costs transferred to evaluated properties	121.8
Amortization to evaluated properties	$ 54.1

Property and Equipment - Impair

Property and Equipment - Impairment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2017	Mar. 31, 2017	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015
Impairment
Impairment of oil and natural gas properties	$ 406,275	$ 145,100	$ 40,774						$ 40,774			$ 40,774	$ 185,860	$ 406,300
Predecessor
Impairment
Impairment of oil and natural gas properties				$ 77,600	$ 143,100	$ 340,500	$ 1,425,800	$ 904,700		$ 77,781	$ 2,330,500				$ 2,814,028	$ 2,421,884

Equity Method Investments (Deta

Equity Method Investments (Details) - USD ($) $ in Thousands	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Aug. 11, 2015
M21K
Equity Method Investments
Maximum borrowing capacity			$ 100,000
Current borrowing base			$ 40,000
Debt outstanding		$ 28,000
Letters of credit outstanding		1,200
Predecessor
Equity Method Investments
Equity (loss) income	$ (10,746)	(17,165)
Predecessor | EXXI M21K
Equity Method Investments
Percentage of investments under the equity method			20.00%
Equity (loss) income	$ 10,700	17,400
Other-than-temporary investment related to investment		$ 11,800

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 30, 2016
Long-Term Debt
Total debt	$ 74,017	$ 78,497
Less: debt issue costs	44
Less: current maturities	21	4,268
Total long-term debt	73,952	74,229
Exit Facility
Long-Term Debt
Total debt	$ 73,996	$ 73,996	$ 74,000
4.14% Promissory Note due 2017
Long-Term Debt
Debt instrument, stated interest rate (as a percent)	4.14%	4.14%	4.14%
Total debt		$ 4,001
Capital lease obligations
Long-Term Debt
Total debt	$ 21	$ 500

Long-Term Debt - Maturities of

Long-Term Debt - Maturities of Long-Term Debt (Details) $ in Thousands	Dec. 31, 2017USD ($)
Twelve Months Ending December 31,
2,018	$ 21
2,019	73,996
Total debt	$ 74,017

Long-Term Debt - Exit Facility

Long-Term Debt - Exit Facility (Details) $ in Thousands	Mar. 13, 2017USD ($)	Mar. 03, 2017	Dec. 30, 2016USD ($)item	Jun. 30, 2018USD ($)	Mar. 31, 2018item	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Long-Term Debt
Debt						$ 74,017	$ 78,497
Exit Facility
Long-Term Debt
Minimum percentage of total value of the entity's and subsidiary guarantors' proved reserves required to be covered by mortgages to secure debt		90.00%	90.00%
Number of facilities | item			2
Debt			$ 74,000			73,996	$ 73,996
Letters of credit						202,600
Minimum percentage of revised net present value of the entity's and subsidiary guarantors' proved reserves required to be covered by mortgages		90.00%
Exit Facility | Plan
Long-Term Debt
Minimum Current ratio					1
Maximum Leverage ratio					4
Leverage ratio, Number of trailing quarters | item					4
Exit Term Loan | Forecast
Long-Term Debt
Contingent prepayment of debt during the fiscal quarter ending June 30, 2018				$ 5,550
Exit Term Loan | Plan
Long-Term Debt
Asset coverage ratio threshold to make mandatory payment on exit term loan					1.50
Percentage of aggregate outstanding principal amount to be prepaid if asset coverage ratio is less than threshold					7.50%
Exit Revolving Facility
Long-Term Debt
Maximum credit capacity			227,800
Letters of credit	$ 200,000		$ 225,000			200,000
Reduction in borrowing capacity as a percentage of reduction in letters of credit	50.00%
Reduction in borrowing capacity	$ 12,500
Amount available for borrowing						12,500
Maximum available for revolving loans						$ 25,000
Letter of credit, rate of fees accrual			4.50%
Letter of credit, rate of issuance fee per annum			0.25%
Commitment fee (as a percent)			0.50%
Letter of Credit | Exit Revolving Facility
Long-Term Debt
Reduction in letter of credit	$ 25,000
Base Rate | Exit Term Loan
Long-Term Debt
Percentage points added to reference rate (as a percent)			3.50%
Base Rate | Exit Revolving Facility
Long-Term Debt
Percentage points added to reference rate (as a percent)			3.50%
LIBO Rate | Exit Term Loan
Long-Term Debt
Percentage points added to reference rate (as a percent)			4.50%
LIBO Rate | Exit Revolving Facility
Long-Term Debt
Percentage points added to reference rate (as a percent)			4.50%

Long-Term Debt - Prepetition Fa

Long-Term Debt - Prepetition Facility Terms (Details) - USD ($) $ in Thousands	Oct. 25, 2016	Dec. 31, 2016	Dec. 31, 2017	May 31, 2011
Long-Term Debt
Debt outstanding			$ 74,017
Predecessor | Prepetition Revolving Credit Facility
Long-Term Debt
Maximum borrowing capacity	$ 297,100			$ 327,200
Percentage of additional payment of interest in kind		2.00%
Payment of interest in-kind		$ 4,700
Repayment of credit facility	30,100
Debt outstanding	$ 69,300
Predecessor | Prepetition Revolving Sub-Facility for EPL
Long-Term Debt
Maximum borrowing capacity				$ 99,400

Long-Term Debt - Prepetition 97

Long-Term Debt - Prepetition Facility Notes Cancelled (Details) - Predecessor - USD ($) $ in Thousands	Dec. 30, 2016	Dec. 31, 2016	Dec. 29, 2016	Jun. 30, 2016	Jun. 30, 2015
Long-Term Debt
Debt instrument, stated interest rate (as a percent)	4.14%
Face value	$ 5,500
11.0% Senior Secured Second Lien Notes due 2020
Long-Term Debt
Debt instrument, stated interest rate (as a percent)		11.00%		11.00%	11.00%
Face value			$ 1,450,000
Amount of notes cancelled	1,450,000
8.25% Senior Notes due 2018
Long-Term Debt
Debt instrument, stated interest rate (as a percent)		8.25%		8.25%	8.25%
Face value			510,000
Amount of notes cancelled	510,000
6.875% Senior Notes due 2024
Long-Term Debt
Debt instrument, stated interest rate (as a percent)		6.875%		6.875%	6.875%
Face value			650,000
Amount of notes cancelled	650,000
3.0% Senior Convertible Notes due 2018
Long-Term Debt
Debt instrument, stated interest rate (as a percent)		3.00%		3.00%	3.00%
Face value			400,000
Amount of notes cancelled	400,000
7.50% Senior Notes due 2021
Long-Term Debt
Debt instrument, stated interest rate (as a percent)		7.50%		7.50%	7.50%
Face value			500,000
Amount of notes cancelled	500,000
7.75% Senior Notes due 2019
Long-Term Debt
Debt instrument, stated interest rate (as a percent)		7.75%		7.75%	7.75%
Face value			250,000
Amount of notes cancelled	250,000
9.25 Percent Senior Notes due 2017
Long-Term Debt
Debt instrument, stated interest rate (as a percent)		9.25%		9.25%	9.25%
Face value			$ 750,000
Amount of notes cancelled	$ 750,000

Long-Term Debt - Prepetition 98

Long-Term Debt - Prepetition Facility Repurchases (Details) - Predecessor - USD ($) $ in Thousands	1 Months Ended	3 Months Ended				6 Months Ended		9 Months Ended	12 Months Ended
	Mar. 31, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Jun. 30, 2016	Dec. 30, 2016	Feb. 29, 2016	Jun. 30, 2015
Repurchases
Debt instrument, stated interest rate (as a percent)										4.14%
Total cost of notes repurchased		$ 215,900							$ 215,900
Gain on repurchase of notes									1,492,400
Gain on early extinguishment of debt			$ 777,000	$ 290,300	$ 458,300		$ 748,600		1,525,596
Interest on liabilities subject to compromise		52,800				$ 123,700		$ 176,500
6.875% Senior Notes due 2024
Repurchases
Principal amount of notes repurchased		$ 506,000							$ 506,000
Debt instrument, stated interest rate (as a percent)		6.875%				6.875%		6.875%	6.875%			6.875%
7.50% Senior Notes due 2021
Repurchases
Principal amount of notes repurchased		$ 261,900							$ 261,900
Debt instrument, stated interest rate (as a percent)		7.50%				7.50%		7.50%	7.50%			7.50%
7.75% Senior Notes due 2019
Repurchases
Principal amount of notes repurchased		$ 148,900							$ 148,900
Debt instrument, stated interest rate (as a percent)		7.75%				7.75%		7.75%	7.75%			7.75%
8.25% Senior Notes due 2018
Repurchases
Principal amount of notes repurchased		$ 296,300							$ 296,300
Debt instrument, stated interest rate (as a percent)		8.25%				8.25%		8.25%	8.25%			8.25%
Amount repurchased but not yet cancelled											$ 266,600
9.25 Percent Senior Notes due 2017
Repurchases
Principal amount of notes repurchased		$ 500,600							$ 500,600
Debt instrument, stated interest rate (as a percent)		9.25%				9.25%		9.25%	9.25%			9.25%
Amount repurchased but not yet cancelled											$ 471,100
3.0% Senior Convertible Notes due 2018
Repurchases
Debt instrument, stated interest rate (as a percent)		3.00%				3.00%		3.00%	3.00%			3.00%
Shares issued in conversion (in dollars)	$ 37,000
Gain on early extinguishment of debt	$ 33,200

Long-Term Debt - 4.14% Promisso

Long-Term Debt - 4.14% Promissory Note (Details)	Dec. 30, 2016USD ($)payment	Dec. 31, 2017	Dec. 31, 2016	Sep. 30, 2012USD ($)
4.14% Promissory Note due 2017
Long-Term Debt
Monthly payment amount	$ 52,000
Number of lump-sum payments | payment	1
Lump-sum payment at maturity	$ 3,300,000
Debt instrument, stated interest rate (as a percent)	4.14%	4.14%	4.14%
Predecessor
Long-Term Debt
Face value of notes	$ 5,500,000
Debt instrument, stated interest rate (as a percent)	4.14%
Predecessor | 4.14% Promissory Note due 2017
Long-Term Debt
Face value of notes	$ 5,500,000			$ 5,500,000
Debt instrument, stated interest rate (as a percent)	4.14%		4.14%

Long-Term Debt - Derivative Ins

Long-Term Debt - Derivative Instruments Premium Financing (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2017
Long-Term Debt
Long term debt				$ 74,017
Predecessor | Derivative Instruments Premium Financing
Long-Term Debt
Interest rate (as a percent)	2.50%	2.50%	2.50%
Long term debt	$ 0	$ 0	$ 10,600

Long-Term Debt - Interest Expen

Long-Term Debt - Interest Expense (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2016	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2017	Dec. 31, 2016	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015	Dec. 30, 2016
Long-Term Debt
Amortization of debt issue cost									$ 17
Interest expense	$ 3,653	$ 3,642	$ 3,834		$ 7,476		$ 11,129		$ 14,836
Predecessor
Long-Term Debt
Interest on liabilities subject to compromise				$ 52,800		$ 123,700		$ 176,500
Debt instrument, stated interest rate (as a percent)												4.14%
Amortization of debt issue cost						5,025				$ 138,473	$ 23,247
Interest expense						12,580				405,658	323,308
Prepetition Revolving Credit Facility
Long-Term Debt
Interest on liabilities subject to compromise						123,700		$ 176,500
Prepetition Revolving Credit Facility | Predecessor
Long-Term Debt
Interest expense						11,670				15,703	25,506
Amortization of debt issue cost						$ 725				$ 5,185	$ 12,491
11.0% Senior Secured Second Lien Notes due 2020 | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				11.00%		11.00%		11.00%		11.00%	11.00%
Interest expense										$ 125,852	$ 48,505
Accretion of original debt issue discount/Amortization of fair value premium										6,249	2,358
Amortization of debt issue cost										$ 5,047	$ 1,887
11.0% Senior Secured Second Lien Notes due 2020-Accelerated | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				11.00%						11.00%
Accretion of original debt issue discount/Amortization of fair value premium										$ 44,855
Amortization of debt issue cost										$ 36,243
8.25% Senior Notes due 2018 | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				8.25%		8.25%		8.25%		8.25%	8.25%
Interest expense										$ 27,899	$ 42,075
Accretion of original debt issue discount/Amortization of fair value premium										$ (8,818)	$ (11,108)
8.25% Senior Notes due 2018-Accelerated | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				8.25%						8.25%
Accretion of original debt issue discount/Amortization of fair value premium										$ (7,961)
6.875% Senior Notes due 2024 | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				6.875%		6.875%		6.875%		6.875%	6.875%
Interest expense										$ 18,033	$ 44,701
Amortization of debt issue cost										$ 457	$ 1,127
6.875% Senior Notes due 2024-Accelerated | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				6.875%						6.875%
Amortization of debt issue cost										$ 1,946
3.0% Senior Convertible Notes due 2018 | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				3.00%		3.00%		3.00%		3.00%	3.00%
Interest expense										$ 9,340	$ 12,000
Accretion of original debt issue discount/Amortization of fair value premium										8,917	11,232
Amortization of debt issue cost										$ 1,142	$ 1,439
3.0% Senior Convertible Notes due 2018-Accelerated | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				3.00%						3.00%
Accretion of original debt issue discount/Amortization of fair value premium										$ 33,370
Amortization of debt issue cost										$ 4,271
7.50% Senior Notes due 2021 | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				7.50%		7.50%		7.50%		7.50%	7.50%
Interest expense										$ 17,414	$ 37,500
Amortization of debt issue cost										$ 478	$ 1,051
7.50% Senior Notes due 2021-Accelerated | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				7.50%						7.50%
Amortization of debt issue cost										$ 2,822
7.75% Senior Notes due 2019 | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				7.75%		7.75%		7.75%		7.75%	7.75%
Interest expense										$ 8,200	$ 19,375
Amortization of debt issue cost										$ 168	$ 388
7.75% Senior Notes due 2019-Accelerated | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				7.75%						7.75%
Amortization of debt issue cost										$ 491
9.25 Percent Senior Notes due 2017 | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				9.25%		9.25%		9.25%		9.25%	9.25%
Interest expense										$ 44,944	$ 69,375
Amortization of debt issue cost										$ 1,902	2,358
9.25% Senior Notes due 2017-Accelerated | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)				9.25%						9.25%
Amortization of debt issue cost										$ 913
4.14% Promissory Note due 2017
Long-Term Debt
Debt instrument, stated interest rate (as a percent)						4.14%		4.14%	4.14%			4.14%
Interest expense									$ 134
4.14% Promissory Note due 2017 | Predecessor
Long-Term Debt
Debt instrument, stated interest rate (as a percent)						4.14%		4.14%				4.14%
Interest expense										130	192
Derivative instruments financing and other
Long-Term Debt
Interest expense									525
Derivative instruments financing and other | Predecessor
Long-Term Debt
Interest expense						$ 185				$ 466	$ 856
Exit Term Loan
Long-Term Debt
Interest expense									4,050
Exit Revolving Facility
Long-Term Debt
Interest expense									$ 10,127

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017
Beginning of period total		$ 737,108
Liabilities incurred and true-up to liabilities settled		11,353
Liabilities settled		(55,820)
Revisions		(70,570)
Accretion expense		42,780
Fair value fresh start adjustment	$ 185,640
End of period total	737,108	664,851
Less: End of period, current portion	56,601	51,398
End of period, noncurrent portion	680,507	613,453
Predecessor
Beginning of period total	537,637	$ 551,468
Liabilities incurred and true-up to liabilities settled	13,880
Liabilities settled	(18,852)
Revisions	(19,577)
Accretion expense	38,380
End of period total	$ 551,468

Derivative Financial Instrum103

Derivative Financial Instruments - Positions (Details) $ in Millions	Dec. 31, 2017$ / MBblsMBbls	Mar. 15, 2016USD ($)	Dec. 31, 2016contract
Derivative Financial Instruments
Outstanding derivative contracts | contract			0
Swap, Remaining contract term January 2018 to December 2018, NYMEX-WTI
Net open crude oil derivative positions
Volumes (MBbls) | MBbls	2,920
Weighted average contract price, Swaps | $ / MBbls	50.68
Swap, Remaining contract term January 2018 to June 2018, Argus-LLS
Net open crude oil derivative positions
Volumes (MBbls) | MBbls	362
Weighted average contract price, Swaps | $ / MBbls	55.45
Swap, Remaining contract term January 2018 to June 2018, ICE Brent
Net open crude oil derivative positions
Volumes (MBbls) | MBbls	452.5
Weighted average contract price, Swaps | $ / MBbls	56.59
Predecessor
Derivative Financial Instruments
Proceeds from monetization of outstanding crude oil and natural gas | $		$ 50.6

Derivative Financial Instrum104

Derivative Financial Instruments - Fair Values (Details) $ in Thousands	Dec. 31, 2017USD ($)
Liability Derivative Instruments
Gross Commodity Derivative Instruments subject to enforceable master netting agreement	$ 32,567
Net amounts presented in Balance Sheets	32,567
Current Liabilities
Liability Derivative Instruments
Gross Commodity Derivative Instruments subject to enforceable master netting agreement	32,567
Net amounts presented in Balance Sheets	$ 32,567

Derivative Financial Instrum105

Derivative Financial Instruments - Gain (loss) (Details) - USD ($) $ in Thousands	3 Months Ended			6 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2017	Sep. 30, 2017	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015
(Loss) gain on derivative instruments
Cash settlements						$ (58)
Change in fair value						(32,567)
Total (loss) gain on derivative financial instruments	$ (12,466)	$ 9,412	$ 3,698	$ 13,110	$ 644	$ (32,625)
Deposits for collateral with counterparties	$ 0				$ 0
Predecessor
(Loss) gain on derivative instruments
Cash settlements							$ 59,081	$ 81,049
Proceeds from monetization							50,588	102,354
Change in fair value							(19,163)	52,036
Total (loss) gain on derivative financial instruments							$ 90,506	$ 235,439

Stockholders' Equity - Successo

Stockholders' Equity - Successor Common and Preferred Stock (Details)	Dec. 31, 2017item$ / sharesshares	Jan. 06, 2017$ / shares	Dec. 31, 2016$ / sharesshares	Dec. 30, 2016$ / sharesshares
Amendments to Articles of Incorporation or Bylaws
Capital stock, shares authorized	110,000,000			110,000,000
Common stock, shares authorized	100,000,000		100,000,000	100,000,000
Common stock, par value | $ / shares	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000		10,000,000	10,000,000
Preferred stock, par value | $ / shares	$ 0.01		$ 0.01	$ 0.01
Number of positions that my be held by same person | item	2

Stockholders' Equity - Registra

Stockholders' Equity - Registration Rights Agreement (Details) - Registration Rights Agreement, February 28, 2017 - shares	Dec. 30, 2016	Feb. 28, 2017
Stockholders' Equity
Ownership threshold (as a percent)	10.00%
Period from Emergence Date	6 months
Shares offered for sale		9,272,285
Number of shares owned that may be sold		9,049,929
Shares of common stock on exercise of warrants		222,356

Stockholders' Equity - Warrant

Stockholders' Equity - Warrant Agreement and Shares Issued (Details) - $ / shares	Dec. 30, 2016	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016
Stockholders' Equity
Common stock, shares outstanding		33,211,594	33,254,963	33,211,594
Warrants outstanding (in shares)			2,119,889
Holders of EGC Unsecured Notes and EPL Unsecured Notes
Stockholders' Equity
Number of warrants issued (in shares)	2,119,889	2,119,889
Number of shares issued upon exercise of each warrant	1
Exercise price of warrant (in dollars per share)	$ 43.66
Minimum percentage increase or decrease in the exercise price resulting from cumulative adjustments to the applicable exercise price	1.00%
Holders of EGC Unsecured Notes
Stockholders' Equity
Number of warrants issued (in shares)	1,271,933	1,271,933		1,271,933
Holders of EPL Unsecured Notes
Stockholders' Equity
Number of warrants issued (in shares)	847,956	847,956
Common Stock
Stockholders' Equity
Number of shares issued		33,212,000	43,000
Common stock, shares outstanding		33,212,000	33,255,000	33,212,000
Common Stock | Holders of EGC Unsecured Notes
Stockholders' Equity
Number of shares issued	3,985,391	3,985,391
Common Stock | Holders of EPL Unsecured Notes
Stockholders' Equity
Number of shares issued	1,328,464	1,328,464
Common Stock | Holders of Second Lien Notes
Stockholders' Equity
Number of shares issued	27,897,739	27,897,739

Stockholders' Equity - Predeces

Stockholders' Equity - Predecessor Common Stock (Details)	May 19, 2016Vote$ / sharesshares	Feb. 24, 2016$ / shares	Dec. 31, 2017$ / sharesshares	Jan. 06, 2017$ / shares	Dec. 31, 2016item$ / sharesshares	Dec. 30, 2016$ / sharesshares
Stockholders' Equity
Common stock, shares authorized | shares			100,000,000		100,000,000	100,000,000
Common stock, par value			$ 0.01	$ 0.01	$ 0.01	$ 0.01
Predecessor
Stockholders' Equity
Number of votes per share owned | Vote	1
Common stock, shares authorized | shares	200,000,000
Common stock, par value	$ 0.005
Minimum per share requirement under NASDAQ Listing Rule (in dollars per share)		$ 1
Number of consecutive days		30 days
Number of rights exercised as of balance sheet date | item					0

Stockholders' Equity - Prede110

Stockholders' Equity - Predecessor Preferred Stock (Details) - USD ($) $ in Thousands	6 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2017	Dec. 30, 2016
Stockholders' Equity
Preferred stock, shares authorized	10,000,000	10,000,000				10,000,000	10,000,000
Assets	$ 1,480,707	$ 1,480,707				$ 1,076,982
Predecessor
Stockholders' Equity
Preferred stock, shares authorized			7,500,000
Dividends that would have been accrued (in dollars)		5,700
Assets	$ 0	0
Dividend payments		$ 0
Preferred Stock | 5.625% Convertible Perpetual Preferred Stock | Predecessor
Stockholders' Equity
Preferred stock dividend rate (as a percent)	5.625%		5.625%	5.625%	5.625%
Preferred Stock | 7.25% Convertible Perpetual Preferred Stock | Predecessor
Stockholders' Equity
Preferred stock dividend rate (as a percent)			7.25%	7.25%	7.25%

Stockholders' Equity - Conversi

Stockholders' Equity - Conversion of Preferred Stock (Details) - Predecessor - shares	6 Months Ended	12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
5.625% Convertible Perpetual Preferred Stock
Stockholders' Equity
Preferred shares converted (in shares)	300,248	150,787	1
Common stock shares issued upon conversion of preferred stock (in shares)	3,145,549	1,579,522	11
Conversion rate (in shares)	10.4765	10.4765	10.2409
7.25% Convertible Perpetual Preferred Stock
Stockholders' Equity
Preferred shares converted (in shares)			5,000
Common stock shares issued upon conversion of preferred stock (in shares)			46,472
Conversion rate (in shares)			9.2940
Preferred Stock | 5.625% Convertible Perpetual Preferred Stock
Stockholders' Equity
Preferred stock dividend rate (as a percent)	5.625%	5.625%	5.625%	5.625%
Preferred Stock | 7.25% Convertible Perpetual Preferred Stock
Stockholders' Equity
Preferred stock dividend rate (as a percent)		7.25%	7.25%	7.25%

Supplemental Cash Flow Infor112

Supplemental Cash Flow Information - Supplemental (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015
Supplemental Cash Flow Information
Cash paid for interest		$ 14,867
Cash paid for income taxes		$ 0
Predecessor
Supplemental Cash Flow Information
Cash paid for interest	$ 7,493		$ 229,569	$ 243,238
Cash paid for income taxes			$ 150	$ 933

Supplemental Cash Flow Infor113

Supplemental Cash Flow Information - Non-cash Investing and Financing Activities (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015
Non-cash investing and financing activities
Changes in capital expenditures accrued in accounts payable		$ (1,944)
Changes in asset retirement obligations		(59,217)
Changes in other property and equipment		$ (327)
Predecessor
Non-cash investing and financing activities
Derivative instruments premium financing				$ 12,025
Changes in capital expenditures accrued in accounts payable	$ 10,242		$ (37,151)	(168,569)
Acquisition of property against joint interest billings receivable	(1,500)
Inventory transferred to oil and natural gas properties			7,081
Changes in asset retirement obligations	$ (5,697)		(2,583)	$ 49,495
Monetization of derivative instruments applied to Revolving Credit Facility			$ 50,588

Employee Benefit Plans - Plan (

Employee Benefit Plans - Plan (Details) - 2016 Long Term Incentive Plan - shares	Apr. 29, 2017	Dec. 30, 2016
Employee Benefit Plans
Number of shares reserved under plan		1,859,552
Percentage of equity reserved under plan		5.00%
Percentage of total new equity that must be allocated		3.00%
Maximum period in which percentage of total new equity must be allocated		120 days
Percentage of total new equity allocated	3.00%

Employee Benefit Plans - Stock

Employee Benefit Plans - Stock options (Details) - Stock Options - 2016 Long Term Incentive Plan	12 Months Ended
	Dec. 31, 2017$ / sharesshares
Employee Benefit Plans
Share-based award, expiration period	10 years
Share-based award, vesting period	3 years
Options
Granted (in shares) | shares	372,597
Forfeited (in shares) | shares	(72,448)
Outstanding at end of period (in shares) | shares	300,149
Options - Weighted Average Exercise Price Per Share
Granted (in dollars per share) | $ / shares	$ 28.92
Forfeited (in dollars per share) | $ / shares	28.97
Outstanding at end of period (in dollars per share) | $ / shares	$ 28.91
Options - Additional information
Weighted Average Remaining Contractual Term, Outstanding	9 years 3 months 18 days

Employee Benefit Plans - Sto116

Employee Benefit Plans - Stock option valuation assumptions (Details) - Stock Options - 2016 Long Term Incentive Plan $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)shares
Black-Scholes option pricing model assumptions:
Dividend yield (as a percent)	0.00%
Unvested stock options (in shares) | shares	300,149
Unrecognized compensation expense (in dollars) | $	$ 1.7
Unrecognized cost recognition period	1 year 3 months 18 days

Employee Benefit Plans - Restri

Employee Benefit Plans - Restricted stock units (Details) - Restricted Stock Units - 2016 Long Term Incentive Plan $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares
Employee Benefit Plans
Share-based award, vesting period	3 years
Number of shares for which each unit provides right to receive	1
Restricted Stock Units
Granted (in shares)	775,344
Vested (in shares)	(68,814)
Forfeited (in shares)	(93,730)
Outstanding at end of period (in shares)	612,800
Average Grant Date Fair Value
Granted (in dollars per share) | $ / shares	$ 24.22
Exercised (in dollars per share) | $ / shares	24.21
Forfeited (in dollars per share) | $ / shares	24.48
Outstanding at end of period (in dollars per share) | $ / shares	$ 24.19
Unrecognized compensation expense | $	$ 8.5
Unrecognized cost recognition period	1 year 3 months 18 days

Employee Benefit Plans - Expens

Employee Benefit Plans - Expense (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Employee Benefit Plans
Stock-based compensation expense	$ 9,486
Stock Options
Employee Benefit Plans
Stock-based compensation expense	1,453
Restricted Stock Units
Employee Benefit Plans
Stock-based compensation expense	$ 8,033

Employee Benefit Plans - Predec

Employee Benefit Plans - Predecessor Long Term Incentive Plan (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 29, 2016	Jun. 30, 2016	Jun. 30, 2015
Employee Benefit Plans
Stock-based compensation expense		$ 9,486
Assets	$ 1,480,707	1,076,982	$ 1,480,707
Predecessor
Employee Benefit Plans
Stock-based compensation expense	(50)				$ (2,583,000)	$ 3,939,000
Assets	$ 0		0
Payments with respect to common shares			$ 0
Predecessor | Employee Stock Purchase Plan
Employee Benefit Plans
Purchase price (as a percent)				15.00%
Restricted Stock Units
Employee Benefit Plans
Stock-based compensation expense		$ 8,033
Restricted Stock Units | Predecessor | 2006 Long-Term Incentive Plan
Employee Benefit Plans
Share-based award, vesting period				3 years
Time-Based Performance Units | Predecessor | 2006 Long-Term Incentive Plan
Employee Benefit Plans
Share-based award, vesting period				3 years
Total Shareholder Return (TSR) Performance-Based Units | Predecessor | 2006 Long-Term Incentive Plan
Employee Benefit Plans
Share-based award, vesting period				3 years

Employee Benefit Plans - Define

Employee Benefit Plans - Defined Contribution Plans (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015
Defined Contribution Plans
Total contributions		$ 1,702
Predecessor
Defined Contribution Plans
Total contributions	$ 638		$ 2,852	$ 2,424
Profit Sharing Plan | Predecessor
Defined Contribution Plans
Total contributions				(768)
401 (k) Plan
Defined Contribution Plans
Total contributions		$ 1,702
401 (k) Plan | Predecessor
Defined Contribution Plans
Total contributions	$ 638		$ 2,852	$ 3,192

Related Party Transactions - Su

Related Party Transactions - Successor (Details) - USD ($)	Sep. 01, 2017	Aug. 24, 2017	Apr. 03, 2017	Feb. 15, 2017	Feb. 02, 2017	Dec. 30, 2016	Feb. 06, 2018
Related Party Transactions
Registration rights agreement, Minimum percentage of common stock outstanding						10.00%
Former Chief Executive Officer, John D. Schiller, Jr.
Related Party Transactions
Amount of severance payment						$ 2,000,000
Severance payment made during the period			$ 2,000,000
Former Chief Executive Officer, John D. Schiller, Jr. | Maximum
Related Party Transactions
Period of payment for health benefits						18 months
Former Chief Financial Officer, Bruce W. Busmire
Related Party Transactions
Severance payment made during the period				$ 750,000
Period of severance payments				18 months
Former Chief Operating Officer, Andoni de Pinho
Related Party Transactions
Severance payment made during the period				$ 750,000
Period of severance payments				18 months
Former Executive VP, CAO and Interim CFO, Hugh A. Menown
Related Party Transactions
Amount of severance payment		$ 580,000
Period of payment for health benefits		12 months
Severance payment made during the period	$ 580,000
Former Chief Executive Officer, John D. Schiller, Jr. | Consulting Agreement
Related Party Transactions
Monthly consulting fee					$ 50,000
Former Chief Executive Officer, John D. Schiller, Jr. | Maximum | Consulting Agreement
Related Party Transactions
Term of agreement					6 months
Former Executive VP, CAO and Interim CFO, Hugh A. Menown | Consulting Agreement
Related Party Transactions
Monthly consulting fee							$ 28,333.33
Former Executive VP, CAO and Interim CFO, Hugh A. Menown | Maximum | Consulting Agreement
Related Party Transactions
Term of agreement		6 months

Related Party Transactions - Pr

Related Party Transactions - Predecessor - M21K Transactions (Details) - EXXI M21K - Predecessor $ in Millions	Aug. 01, 2015$ / shares	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)	Aug. 11, 2015
Related Party Transactions
Percentage of investments under the equity method				20.00%
Equity Method Investee
Related Party Transactions
Management fee received (in dollars per BOE) | $ / shares	0.98
Revenue from related party		$ 0.2	$ 3.3
Equity Method Investee | Guaranteed payment of asset retirement obligation
Related Party Transactions
Payment period		3 years
Payments received related to guarantees		$ 0.3	$ 3.7
Equity Method Investee | EP Energy Property | Guaranteed payment of asset retirement obligation
Related Party Transactions
Amount of asset retirement obligation of related party for which entity has guaranteed payment		65
Amount of other liabilities of related party for which entity has guaranteed payment		1.8
Due from related party		6.3
Equity Method Investee | LLOG Exploration | Guaranteed payment of asset retirement obligation
Related Party Transactions
Amount of asset retirement obligation of related party for which entity has guaranteed payment		36.7
Due from related party		3.3
Equity Method Investee | Eugene Island 330 and South Marsh Island 128 | Guaranteed payment of asset retirement obligation
Related Party Transactions
Amount of asset retirement obligation of related party for which entity has guaranteed payment		18.6
Due from related party		$ 1.7

Related Party Transactions -123

Related Party Transactions - Predecessor - Consulting Agreements (Details) - Predecessor - USD ($)	Mar. 12, 2016	Oct. 15, 2015	Mar. 12, 2015	Jan. 15, 2015	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015
Restricted Stock Units
Related Party Transactions
Stock repurchased, number of shares | shares	1,876,219
Stock repurchased, value	$ 1,182,018
Stock repurchased, weighted average price per share	$ 0.63
Director, James LaChance, Interim Chief Strategic Officer
Related Party Transactions
Minimum capital to be provided by the related party to be eligible for success fee						$ 1,000,000,000
Director, James LaChance, Interim Chief Strategic Officer | Consulting Agreement, Success fee payable upon Board's discretion
Related Party Transactions
Related party transaction, amount of transaction		$ 1,000,000
Director, James LaChance, Interim Chief Strategic Officer | Restricted Stock Units
Related Party Transactions
Percentage of incentive compensation		50.00%
Restricted stock units awarded (in shares)		231,482
Restricted stock units, weighted average price per share		$ 2.16
Director, James LaChance, Interim Chief Strategic Officer | Restricted Stock Units | Consulting Agreement, Success fee
Related Party Transactions
Restricted stock units awarded (in shares)			1,644,737
Restricted stock units, weighted average price per share			$ 3.04
Director, James LaChance, Interim Chief Strategic Officer | Cash
Related Party Transactions
Percentage of incentive compensation		50.00%
James LaChance [Member] | Consulting Agreement
Related Party Transactions
Monthly consulting fee				$ 200,000
Related party expense					$ 100,000		$ 1,100,000
Maximum | Director, James LaChance, Interim Chief Strategic Officer | Consulting Agreement, Success fee
Related Party Transactions
Incentive compensation to related party						6,000,000
Maximum | Director, James LaChance, Interim Chief Strategic Officer | Consulting Agreement, Success fee payable upon achievement of objective criteria
Related Party Transactions
Incentive compensation to related party						5,000,000
Related party transaction, amount of transaction			$ 5,000,000
Maximum | Director, James LaChance, Interim Chief Strategic Officer | Consulting Agreement, Success fee payable upon Board's discretion
Related Party Transactions
Incentive compensation to related party						$ 1,000,000

Related Party Transactions -124

Related Party Transactions - Predecessor - Former CEO (Details) $ in Millions	6 Months Ended		12 Months Ended
	Dec. 31, 2016USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)	Dec. 31, 2014director	Oct. 09, 2015individual
Predecessor
Related Party Transactions
The number of different individuals required for the positions of Chief Executive Officer and Chairman of the Board | individual								2
Former CEO's personal acquaintances or their affiliates | Services provided
Related Party Transactions
Related party transaction, amount of transaction			$ 10.6
Former CEO's personal acquaintances or their affiliates | Predecessor | Services provided
Related Party Transactions
Related party transaction, amount of transaction	$ 3.3				$ 35.9	$ 34.7
Managing Director of LP with ownership interest in entity | Predecessor
Related Party Transactions
Number of directors making personal loan to CEO | director							1
Percentage of company stock owned by related party							6.30%
Entities with which Predecessor Board member has ownership interest | Services provided
Related Party Transactions
Related party transaction, amount of transaction			$ 0
Entities with which Predecessor Board member has ownership interest | Predecessor | Services provided
Related Party Transactions
Related party transaction, amount of transaction	$ 0	$ 2		$ 5.6

Earnings (Loss) per Share - EPS

Earnings (Loss) per Share - EPS (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Dec. 31, 2016	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015
Basic and diluted earnings (loss) per share
Net income (loss)	$ (406,275)	$ (215,069)	$ (35,157)	$ (26,237)	$ (64,547)							$ (90,784)	$ (406,275)		$ (125,941)	$ (341,010)
Net (Loss) Income Attributable to Common Stockholders	(406,275)															(341,010)
Net income (loss) available to common stockholders, Diluted	$ (406,275)															$ (341,010)
Weighted average shares outstanding for basic EPS	33,212															33,239
Weighted average shares outstanding for diluted EPS	33,212															33,239
Basic (in dollars per share)	$ (12.23)															$ (10.26)
Diluted (in dollars per share)	$ (12.23)															$ (10.26)
Predecessor
Basic and diluted earnings (loss) per share
Net income (loss)						$ 2,771,349	$ (120,738)	$ (195,460)	$ 160,776	$ (1,310,583)	$ (573,392)		2,650,611	$ (1,883,975)			$ (1,918,659)	$ (2,433,838)
Preferred stock dividends														5,664			5,194	11,468
Net (Loss) Income Attributable to Common Stockholders						$ 2,771,349	$ (120,738)	$ (192,612)	$ 158,398	$ (1,313,393)	$ (576,246)		2,650,611	$ (1,889,639)			(1,923,853)	(2,445,306)
Net income (loss) available to common stockholders, Diluted													$ 2,650,611				$ (1,923,853)	$ (2,445,306)
Weighted average shares outstanding for basic EPS													98,337	94,926			95,822	94,167
Add dilutive securities (in shares)													6,450
Weighted average shares outstanding for diluted EPS													104,787	94,926			95,822	94,167
Basic (in dollars per share)						$ 28.04	$ (1.23)	$ (1.97)	$ 1.65	$ (13.81)	$ (6.08)		$ 26.95	$ (19.91)			$ (20.08)	$ (25.97)
Diluted (in dollars per share)						$ 26.45	$ (1.23)	$ (1.97)	$ 1.55	$ (13.81)	$ (6.08)		$ 25.30	$ (19.91)			$ (20.08)	$ (25.97)

Earnings (Loss) per Share - Oth

Earnings (Loss) per Share - Other (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015
Other disclosures
Net loss allocated to the participating securities	$ 0
Anti-dilutive securities (in shares)	3,132,729
Predecessor
Other disclosures
Anti-dilutive securities (in shares)		2,119,889	9,439,104	8,642,434

Commitments and Contingencies -

Commitments and Contingencies - Litigation (Details) - Litigation claim to be paid at pro rata share $ in Millions	Jun. 17, 2017USD ($)director	Dec. 31, 2017USD ($)
Litigation
Amount of claim filed	$ 3.9
Number of directors making personal loan to CEO | director	1
General unsecured claims, accrual	$ 1.5	$ 1.5

Commitments and Contingencie128

Commitments and Contingencies - Future Minimum Lease Commitments (Details) $ in Thousands	Dec. 31, 2017USD ($)
Commitments and Contingencies
Year ending December 31, 2018	$ 36,035
Year ending December 31, 2019	36,509
Year ending December 31, 2020	43,545
Year ending December 31, 2021	49,598
Year ending December 31, 2022	48,575
Thereafter	152,176
Total	$ 366,438

Commitments and Contingencie129

Commitments and Contingencies - Additional Lease Information (Details) $ in Millions	Jun. 30, 2015USD ($)item	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)item
Leases, Excluding GIGS Lease
Lease Commitments
Rent expense			$ 24.1
Predecessor | Leases, Excluding GIGS Lease
Lease Commitments
Rent expense		$ 11.9		$ 6	$ 6.4
Predecessor | GiGS Lease
Lease Commitments
Rent expense		$ 17
Primary term of the lease	11 years
Number of renewal options under the terms of the operating lease | item	1				1
Average annual lease payment over life of lease	$ 40.5				$ 40.5
Right of first refusal period after lease term	2 years
Predecessor | GiGS Lease | Maximum
Lease Commitments
Lease renewal term	9 years
Percentage of expected useful life of the property for renewal option	75.00%

Commitments and Contingencie130

Commitments and Contingencies - Letters of Credit and Performance Bonds (Details) - USD ($) $ in Millions	Dec. 31, 2017	Mar. 13, 2017	Dec. 30, 2016
Letters of Credit and Performance Bonds
Performance bonds outstanding	$ 334.1
Cash collateral	49.8
Exit Facility
Letters of Credit and Performance Bonds
Letters of credit	202.6
Exit Revolving Facility
Letters of Credit and Performance Bonds
Letters of credit	200	$ 200	$ 225
Performance Bond, Lease and area bonds
Letters of Credit and Performance Bonds
Performance bonds outstanding	182.4
Performance Bonds, Wells and facilities
Letters of Credit and Performance Bonds
Performance bonds outstanding	$ 151.7

Commitments and Contingencie131

Commitments and Contingencies - Drilling Rig Commitments (Details) - Drilling Rig Contracts $ in Millions	2 Months Ended	12 Months Ended
	Mar. 15, 2018	Dec. 31, 2017USD ($)contract
Drilling Rig Commitments
Drilling rig commitments		$ 0.6
Committed contracts with contract terms between 2 and 6 months		$ 14
Number of contracts | contract		2
Minimum
Drilling Rig Commitments
Term of contract	2 months
Maximum
Drilling Rig Commitments
Term of contract	6 months

Commitments and Contingencie132

Commitments and Contingencies - Other (Details) $ in Millions	Dec. 31, 2017USD ($)
Bonding requirements
Other
Restricted cash	$ 25.7
Future plugging, abandonment and other decommissioning costs
Other
Restricted cash	$ 6.1

Income Taxes - Successor Income

Income Taxes - Successor Income Taxes - Emergence (Details) - USD ($) $ in Thousands	Dec. 30, 2016	Jun. 30, 2016	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2016	Sep. 30, 2012
Income Taxes
Valuation allowance			$ 306,206			$ 167,645
Tax basis of asset retirement obligation			0
Increase in valuation allowance			224,000
Predecessor
Income Taxes
Debt instrument, stated interest rate (as a percent)	4.14%
Face value of notes	$ 5,500
Percentage of stock cancelled	100.00%
Withholding tax rate (as a percent)	30.00%	30.00%
Valuation allowance		$ 1,029,300		$ 1,029,300	$ 379,300
Additional tax basis	$ 633,000
Increase in amount related to the change in total CODI excluded	663,000
Change in estimates of tax attributes	$ 30,000
Increase in valuation allowance			$ 224,000	$ 650,000	$ 356,800
4.14% Promissory Note due 2017
Income Taxes
Debt instrument, stated interest rate (as a percent)	4.14%		4.14%			4.14%
4.14% Promissory Note due 2017 | Predecessor
Income Taxes
Debt instrument, stated interest rate (as a percent)	4.14%					4.14%
Face value of notes	$ 5,500						$ 5,500

Income Taxes - Successor Inc134

Income Taxes - Successor Income Taxes - CODI (Details) $ in Thousands	Dec. 31, 2016USD ($)
Cancellation of Debt Income
Pre-tax reductions in net operating loss carryovers	$ 681
Pre-tax reductions in oil and natural gas properties	915
Pre-tax reductions in EPL stock basis	304
Pre-tax reductions in others	18
CODI excluded requiring attribute reduction	1,918
As reported
Cancellation of Debt Income
Pre-tax reductions in net operating loss carryovers	486
Pre-tax reductions in oil and natural gas properties	1,485
Pre-tax reductions in EPL stock basis	543
Pre-tax reductions in others	67
CODI excluded requiring attribute reduction	$ 2,581

Income Taxes - Successor Inc135

Income Taxes - Successor Income Taxes - Additional information (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016
Valuation Allowance
Cash paid for income taxes		$ 0
Net operating loss carryovers		$ 339	$ 339
Fresh Start
Valuation Allowance
Effective income tax rate (benefit) (as a percent)	0.00%
Increase in stock ownership threshold (as a percent)		50.00%
Look-back period		3 years

Income Taxes - Predecessor Inco

Income Taxes - Predecessor Income taxes (Details) - USD ($) $ in Thousands	Dec. 30, 2016	Jun. 30, 2016	Dec. 30, 2016	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2016
Income Taxes
Withholding taxes paid			$ 0
Increase (decrease) in valuation allowance				$ 224,000
Valuation allowance				306,206			$ 167,645
Predecessor
Income Taxes
Withholding tax rate (as a percent)	30.00%	30.00%
Increase (decrease) in valuation allowance				$ 224,000	$ 650,000	$ 356,800
Valuation allowance		$ 1,029,300			$ 1,029,300	$ 379,300

Income Taxes - Income before in

Income Taxes - Income before income tax (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015
Income Taxes
U.S. (loss) income	$ (406,275)								$ (341,010)
(Loss) Income Before Income Taxes	$ (406,275)	$ (35,157)	$ (26,237)	$ (64,547)	$ (90,784)			$ (125,941)	$ (341,010)
Predecessor
Income Taxes
U.S. (loss) income						$ 2,650,611				$ (1,913,626)	$ (3,050,659)
Non-U.S. (loss) income										(5,120)	3,471
(Loss) Income Before Income Taxes						$ 2,650,611	$ (1,883,924)			$ (1,918,746)	$ (3,047,188)

Income Taxes - Components of in

Income Taxes - Components of income tax provision (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015
Deferred
Income tax benefit		$ 0
Predecessor
Current
U.S.				$ 933
State			$ (87)	99
Total current			(87)	1,032
Deferred
U.S.				(564,569)
State				(49,813)
Total deferred				(614,382)
Income tax benefit	$ 51		$ (87)	$ (613,350)

Income Taxes - Reconciliation (

Income Taxes - Reconciliation (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Dec. 31, 2018	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015
Income Taxes
(Loss) income before income taxes	$ (406,275)	$ (35,157)	$ (26,237)	$ (64,547)	$ (90,784)			$ (125,941)		$ (341,010)
Statutory rate (as a percent)	35.00%									35.00%
Income tax (benefit) expense computed at statutory rate	$ (142,196)									$ (119,354)
Reconciling items
Change in valuation allowance	$ 142,196									138,561
Non-deductible transaction and restructuring costs										894
Return to provision adjustments										(224,339)
Tax Cuts and Jobs Act of 2017										204,137
Fresh start adjustments to deferred tax balances:
Other - Net										101
Income tax benefit										$ 0
Predecessor
Income Taxes
(Loss) income before income taxes						$ 2,650,611	$ (1,883,924)				$ (1,918,746)	$ (3,047,188)
Statutory rate (as a percent)						35.00%					35.00%	35.00%
Income tax (benefit) expense computed at statutory rate						$ 927,714					$ (671,561)	$ (1,066,516)
Reconciling items
Federal withholding obligation											8,161	10,331
Nontaxable foreign income											1,791	91
Change in valuation allowance						(1,029,335)					650,011	356,798
State income taxes (benefit), net of federal tax benefit											(87)	(32,314)
Non-deductible transaction and restructuring costs						36,874						440
Tax basis in shortfall on partnership dissolution											6,501
Fresh start adjustments to deferred tax balances:
Asset retirement obligation						190,715
Net operating loss						163,027
Accrued interest expense						115,560
Oil and natural gas properties and other property and equipment						611,834
Deferred state income taxes						54,793
Withholding taxes						(81,635)
Cancellation of stockholders deficit						(290,665)
Cancellation of indebtedness income						(702,972)
Other fresh start deferred income taxes, net						3,284
Goodwill impairment												115,253
Other - Net						$ 806					5,097	2,567
Income tax benefit							$ 51				$ (87)	$ (613,350)
Forecast
Income Taxes
Statutory rate (as a percent)									21.00%

Income Taxes - Components of de

Income Taxes - Components of deferred taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015	Dec. 29, 2016
Deferred tax assets - non current
Oil, natural gas properties and other property and equipment				$ 66,297
Asset retirement obligation	$ 257,988	$ 257,988		139,619
Tax loss carryforwards on U.S. operations				71,268
Employee benefit plans				1,698
Tax partnership activity				676
Derivative instruments and other				6,839
Other	11,120	11,120		19,809
Total deferred tax assets	269,108	269,108		306,206
Deferred tax liabilities
Oil, natural gas properties and other property and equipment	(101,463)	(101,463)
Total deferred tax liabilities	(101,463)	(101,463)
Valuation allowance	(167,645)	(167,645)		(306,206)
Net operating loss carryovers	$ 339,000	$ 339,000		$ 339,000
Statutory rate (as a percent)	35.00%			35.00%
Forecast
Deferred tax liabilities
Statutory rate (as a percent)			21.00%
Predecessor
Deferred tax liabilities
Valuation allowance					$ (1,029,300)	$ (379,300)
Statutory rate (as a percent)		35.00%			35.00%	35.00%
U.S. | Predecessor
Deferred tax liabilities
Net operating loss carryovers							$ 681,000

Concentrations of Credit Risk (

Concentrations of Credit Risk (Details) - instrument	6 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015
Predecessor
Derivative, Number of Instruments Held
Derivative instruments outstanding	0		0
Chevron | Revenue [Member]
Concentration Risk [Line Items]
Percentage of total oil and natural gas revenues		26.00%
Chevron | Revenue [Member] | Predecessor
Concentration Risk [Line Items]
Percentage of total oil and natural gas revenues	26.00%		22.00%	24.00%
Shell | Revenue [Member]
Concentration Risk [Line Items]
Percentage of total oil and natural gas revenues		25.00%
Shell | Revenue [Member] | Predecessor
Concentration Risk [Line Items]
Percentage of total oil and natural gas revenues	26.00%		21.00%	29.00%
Plains | Revenue [Member]
Concentration Risk [Line Items]
Percentage of total oil and natural gas revenues		18.00%
Trafigura | Revenue [Member]
Concentration Risk [Line Items]
Percentage of total oil and natural gas revenues		12.00%
Trafigura | Revenue [Member] | Predecessor
Concentration Risk [Line Items]
Percentage of total oil and natural gas revenues	27.00%		22.00%
ExxonMobil | Revenue [Member] | Predecessor
Concentration Risk [Line Items]
Percentage of total oil and natural gas revenues				26.00%

Fair Value - General (Details)

Fair Value - General (Details) $ in Millions	Dec. 31, 2017USD ($)
Fair Value
Fair value adjustment related to property and equipment	$ 1,007.4
Fair value adjustment related to asset retirement obligation	185.6
Fair value adjustment related to common stock warrants	$ 8.1

Fair Value - Financial instrume

Fair Value - Financial instruments (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Jun. 30, 2016
Liabilities:
Oil and Natural Gas Derivatives, Liabilities		$ 32,567
Level 2
Liabilities:
Oil and Natural Gas Derivatives, Liabilities		32,567
Level 3
Fair value of financial instruments
Transfers into Level 3		0
Transfers out of Level 3		$ 0
Predecessor | Level 3
Fair value of financial instruments
Transfers into Level 3	$ 0		$ 0
Transfers out of Level 3	$ 0		$ 0

Fair Value - Long-term debt ins

Fair Value - Long-term debt instruments (Details) - Level 2 - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Carrying Value
Long-Term Debt
Long-term debt instruments	$ 73,996	$ 73,996
Estimated of Fair Value
Long-Term Debt
Long-term debt instruments	73,996	73,996
Exit Facility | Carrying Value
Long-Term Debt
Long-term debt instruments	73,996	73,996
Exit Facility | Estimated of Fair Value
Long-Term Debt
Long-term debt instruments	$ 73,996	$ 73,996

Fair Value - Changes to Level 3

Fair Value - Changes to Level 3 financial instruments (Details) - Predecessor - USD ($) $ in Thousands	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Level 3 financial instruments
Balance at beginning of period	$ 33	$ 6,910
Vested	(775)
Grants charged to general and administrative expense	760	(6,877)
Balance at end of period	$ 18	$ 33

Prepayments and Accrued Liab146

Prepayments and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Prepaid expenses and other current assets
Advances to joint interest partners	$ 1,381	$ 650
Insurance	5,949	9,600
Inventory	394	470
Royalty deposit	1,021	1,273
Other	12,857	5,987
Total prepaid expenses and other current assets	21,602	17,980
Accrued liabilities
Advances from joint interest partners	81	374
Employee benefits and payroll	6,791	4,491
Interest payable	185	233
Accrued hedge payable	2,491
Undistributed oil and gas proceeds	20,079	22,715
Severance taxes payable	558	628
Escrowed reorganization expenses		25,987
Other	15,309	1,247
Total accrued liabilities	$ 45,494	$ 55,675

Comparative Period Informati147

Comparative Period Information (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Dec. 31, 2016	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015
Total Revenues		$ 93,838	$ 115,701	$ 144,019	$ 158,086
Operating loss	$ (406,275)	(211,462)	(31,556)	(22,675)	(60,735)							$ (83,410)			$ (114,966)	$ (326,428)
(Loss) income before income taxes	(406,275)		(35,157)	(26,237)	(64,547)							(90,784)			(125,941)	(341,010)
Income tax benefit																0
Net (Loss) Income	(406,275)	(215,069)	(35,157)	(26,237)	(64,547)							(90,784)	$ (406,275)		(125,941)	(341,010)
Net (Loss) Income Attributable to Common Stockholders	$ (406,275)															$ (341,010)
Earnings (Loss) per Share
Basic (in dollars per share)	$ (12.23)															$ (10.26)
Diluted (in dollars per share)	$ (12.23)															$ (10.26)
Weighted Average Number of Common Shares Outstanding
Basic (in shares)	33,212															33,239
Diluted (in shares)	33,212															33,239
Net cash used in operating activities																$ 45,638
Net cash provided by (used in) investing activities																(55,063)
Net cash used in financing activities																(4,214)
Net (Decrease) Increase in Cash and Cash Equivalents																(13,639)
Impairment of oil and natural gas properties	$ 406,275	$ 145,100			40,774							40,774			40,774	$ 185,860	$ 406,300
Predecessor
Total Revenues						$ 153,723	$ 142,963	$ 148,395	$ 116,285	$ 184,615	$ 257,823		296,686	$ 442,438
Operating loss						12,795	(83,329)	(168,119)	(417,866)	(1,513,148)	(918,200)		(70,534)	(2,431,348)				$ (3,017,333)	$ (2,710,891)
(Loss) income before income taxes													2,650,611	(1,883,924)				(1,918,746)	(3,047,188)
Income tax benefit														51				(87)	(613,350)
Net (Loss) Income						2,771,349	(120,738)	(195,460)	160,776	(1,310,583)	(573,392)		2,650,611	(1,883,975)				(1,918,659)	(2,433,838)
Preferred stock dividends														5,664				5,194	11,468
Net (Loss) Income Attributable to Common Stockholders						$ 2,771,349	$ (120,738)	$ (192,612)	$ 158,398	$ (1,313,393)	$ (576,246)		$ 2,650,611	$ (1,889,639)				$ (1,923,853)	$ (2,445,306)
Earnings (Loss) per Share
Basic (in dollars per share)						$ 28.04	$ (1.23)	$ (1.97)	$ 1.65	$ (13.81)	$ (6.08)		$ 26.95	$ (19.91)				$ (20.08)	$ (25.97)
Diluted (in dollars per share)						$ 26.45	$ (1.23)	$ (1.97)	$ 1.55	$ (13.81)	$ (6.08)		$ 25.30	$ (19.91)				$ (20.08)	$ (25.97)
Weighted Average Number of Common Shares Outstanding
Basic (in shares)													98,337	94,926				95,822	94,167
Diluted (in shares)													104,787	94,926				95,822	94,167
Net cash used in operating activities													$ (17,473)	$ (89,924)				$ (166,655)	$ 330,753
Net cash provided by (used in) investing activities													11,706	(82,872)				(122,913)	(460,448)
Net cash used in financing activities													(32,123)	(258,162)				(264,022)	740,737
Net (Decrease) Increase in Cash and Cash Equivalents													(37,890)	(430,958)				(553,590)	611,042
Impairment of oil and natural gas properties							$ 77,600	$ 143,100	$ 340,500	$ 1,425,800	$ 904,700		77,781	2,330,500				2,814,028	$ 2,421,884
Gain on settlement of liabilities subject to compromise	$ (1,983,920)					$ (1,983,900)							(1,983,920)
Fair value adjustment						840,300							840,256
Reorganization expenses						58,000	32,600						90,568					14,201
Gain on early extinguishment of debt									$ 777,000	$ 290,300	$ 458,300			$ 748,600				1,525,596
As reported
Operating loss			(27,979)	(20,081)	(61,503)							(81,584)			(109,563)
(Loss) income before income taxes			(31,580)	(23,643)	(65,315)							(88,958)			(120,538)
Net (Loss) Income			(31,580)	(23,643)	(65,315)							(88,958)			(120,538)
Weighted Average Number of Common Shares Outstanding
Impairment of oil and natural gas properties			$ (2,357)	$ (848)	$ 44,054							$ 43,206			$ 40,849
Predecessor
Operating loss						12,795	(83,329)						(70,534)					(3,017,333)
(Loss) income before income taxes							(120,738)						2,650,611					(1,918,746)
Income tax benefit																		(87)
Net (Loss) Income						$ 2,771,349	(120,738)						$ 2,650,611					(1,918,659)
Preferred stock dividends																		5,194
Net (Loss) Income Attributable to Common Stockholders																		(1,923,853)
Earnings (Loss) per Share
Basic (in dollars per share)						$ 28.04							$ 26.95
Diluted (in dollars per share)						$ 26.45							$ 25.30
Weighted Average Number of Common Shares Outstanding
Basic (in shares)						98,850							98,337
Diluted (in shares)						104,787							104,787
Net cash used in operating activities													$ (17,473)					(166,655)
Net cash provided by (used in) investing activities													11,706					(122,913)
Net cash used in financing activities													(32,123)					(264,022)
Net (Decrease) Increase in Cash and Cash Equivalents													(37,890)					(553,590)
Impairment of oil and natural gas properties							77,558						77,781					2,814,028
Gain on early extinguishment of debt																		1,525,596
Predecessor | As reported
Operating loss						$ 11,708	(93,737)						(82,029)					(3,017,425)
(Loss) income before income taxes							(131,146)						2,653,903					(1,918,838)
Income tax benefit																		(87)
Net (Loss) Income						$ 2,785,049	(131,146)						$ 2,653,903					(1,918,751)
Preferred stock dividends																		8,394
Net (Loss) Income Attributable to Common Stockholders																		(1,927,145)
Earnings (Loss) per Share
Basic (in dollars per share)						$ 28.17							$ 26.99
Diluted (in dollars per share)						$ 26.58							$ 25.33
Weighted Average Number of Common Shares Outstanding
Basic (in shares)						98,850							98,337
Diluted (in shares)						104,787							104,787
Net cash used in operating activities													$ (17,473)					(166,655)
Net cash provided by (used in) investing activities													11,706					(122,913)
Net cash used in financing activities													(32,123)					(264,022)
Net (Decrease) Increase in Cash and Cash Equivalents													(37,890)					(553,590)
Impairment of oil and natural gas properties							$ 86,820						$ 86,820					2,813,570
Gain on early extinguishment of debt																		$ 1,525,596

Selected Quarterly Financial148

Selected Quarterly Financial Data – Unaudited (Details) - USD ($) $ / shares in Units, $ in Thousands	Dec. 31, 2016	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015
Revenues		$ 93,838	$ 115,701	$ 144,019	$ 158,086
Operating loss	$ (406,275)	(211,462)	(31,556)	(22,675)	(60,735)							$ (83,410)			$ (114,966)	$ (326,428)
Net (Loss) Income	(406,275)	$ (215,069)	$ (35,157)	$ (26,237)	$ (64,547)							$ (90,784)	$ (406,275)		$ (125,941)	(341,010)
Net income (loss) attributable to common stockholders	$ (406,275)															$ (341,010)
Net income (loss) per share attributable to common stockholders(1)
Basic and Diluted (in dollars per share)		$ (6.47)	$ (1.06)	$ (0.79)	$ (1.94)							$ (2.73)			$ (3.79)
Basic (in dollars per share)	$ (12.23)															$ (10.26)
Diluted (in dollars per share)	$ (12.23)															$ (10.26)
Impairment of oil and natural gas properties	$ 406,275	$ 145,100			$ 40,774							$ 40,774			$ 40,774	$ 185,860	$ 406,300
Predecessor
Revenues						$ 153,723	$ 142,963	$ 148,395	$ 116,285	$ 184,615	$ 257,823		296,686	$ 442,438
Operating loss						12,795	(83,329)	(168,119)	(417,866)	(1,513,148)	(918,200)		(70,534)	(2,431,348)				$ (3,017,333)	$ (2,710,891)
Net (Loss) Income						2,771,349	(120,738)	(195,460)	160,776	(1,310,583)	(573,392)		2,650,611	(1,883,975)				(1,918,659)	(2,433,838)
Preferred stock dividends								(2,848)	2,378	2,810	2,854
Net income (loss) attributable to common stockholders						$ 2,771,349	$ (120,738)	$ (192,612)	$ 158,398	$ (1,313,393)	$ (576,246)		$ 2,650,611	$ (1,889,639)				$ (1,923,853)	$ (2,445,306)
Net income (loss) per share attributable to common stockholders(1)
Basic (in dollars per share)						$ 28.04	$ (1.23)	$ (1.97)	$ 1.65	$ (13.81)	$ (6.08)		$ 26.95	$ (19.91)				$ (20.08)	$ (25.97)
Diluted (in dollars per share)						$ 26.45	$ (1.23)	$ (1.97)	$ 1.55	$ (13.81)	$ (6.08)		$ 25.30	$ (19.91)				$ (20.08)	$ (25.97)
Impairment of oil and natural gas properties							$ 77,600	$ 143,100	$ 340,500	$ 1,425,800	$ 904,700		$ 77,781	$ 2,330,500				$ 2,814,028	$ 2,421,884
Reorganization items													2,733,608					(14,201)
Gain on early extinguishment of debt									$ 777,000	$ 290,300	$ 458,300			$ 748,600				1,525,596
Gain on settlement of liabilities subject to compromise	$ 1,983,920					$ 1,983,900							1,983,920
Fair value adjustment						840,300							840,256
Reorganization expenses						58,000	32,600						90,568					14,201
Adjustment
Operating loss			$ (3,577)	$ (2,594)	768							(1,826)			(5,403)
Net (Loss) Income			$ (3,577)	$ (2,594)	$ 768							$ (1,826)			$ (5,403)
Net income (loss) per share attributable to common stockholders(1)
Basic and Diluted (in dollars per share)			$ (0.11)	$ (0.08)	$ 0.02							$ (0.05)			$ (0.16)
Impairment of oil and natural gas properties			$ 2,357	$ 848	$ (3,280)							$ (2,432)			$ (75)
Predecessor
Operating loss						12,795	(83,329)						(70,534)					(3,017,333)
Net (Loss) Income						$ 2,771,349	$ (120,738)						$ 2,650,611					(1,918,659)
Net income (loss) attributable to common stockholders																		$ (1,923,853)
Net income (loss) per share attributable to common stockholders(1)
Basic and Diluted (in dollars per share)							$ (1.23)											$ (20.08)
Basic (in dollars per share)						$ 28.04							$ 26.95
Diluted (in dollars per share)						$ 26.45							$ 25.30
Impairment of oil and natural gas properties							$ 77,558						$ 77,781					$ 2,814,028
Reorganization items							(32,633)						2,733,608					(14,201)
Gain on early extinguishment of debt																		1,525,596
Predecessor | Adjustment
Operating loss						$ 1,087	10,408						11,495					92
Net (Loss) Income						$ (13,700)	$ 10,408						$ (3,292)					92
Net income (loss) attributable to common stockholders																		$ 3,292
Net income (loss) per share attributable to common stockholders(1)
Basic and Diluted (in dollars per share)							$ 0.11											$ 0.03
Basic (in dollars per share)						$ (0.14)							$ (0.04)
Diluted (in dollars per share)						$ (0.13)							$ (0.03)
Impairment of oil and natural gas properties							$ (9,262)						$ (9,039)					$ 458
Reorganization items													$ (14,787)

Selected Quarterly Financial149

Selected Quarterly Financial Data - Unaudited adjustments (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Dec. 31, 2016	Dec. 31, 2014	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015
Revenues
Oil sales				$ 113,697	$ 118,484	$ 133,793							$ 252,277			$ 365,974	$ 481,922
Natural gas liquids sales				2,209	2,370	2,227							4,597			6,806	8,542
Natural gas sales				12,261	13,753	18,368							32,121			44,382	53,805
(Loss) Gain on derivative financial instruments				(12,466)	9,412	3,698							13,110			644	(32,625)
Total Revenues				115,701	144,019	158,086							302,105			417,806	511,644
Costs and Expenses
Lease operating				77,822	83,655	77,267							160,922			238,744	319,671
Production taxes				471	482	239							721			1,192	1,355
Gathering and transportation				(2,441)	2,678	11,222							13,900			11,459	21,666
Pipeline facility fee				10,495	10,494	10,494							20,988			31,483	41,977
Depreciation, depletion and amortization				36,131	38,685	41,896							80,581			116,712	150,151
Accretion of asset retirement obligations				9,753	9,984	13,081							23,065			32,818	42,780
Impairment of oil and natural gas properties	$ 406,275		$ 145,100			40,774							40,774			40,774	185,860	$ 406,300
General and administrative expense				15,026	20,716	23,848							42,320			57,346	72,057
Reorganization items													2,244			2,244	2,555
Total Costs and Expenses	406,275			147,257	166,694	218,821							385,515			532,772	838,072
Operating Loss	(406,275)		(211,462)	(31,556)	(22,675)	(60,735)							(83,410)			(114,966)	(326,428)
Other Income (Expense)
Other income, net				52	80	22							102			154	254
Interest expense				(3,653)	(3,642)	(3,834)							(7,476)			(11,129)	(14,836)
Total Other (Expense) Income, net				(3,601)	(3,562)	(3,812)							(7,374)			(10,975)	(14,582)
Loss Before Reorganization Items and Income Taxes	(406,275)																(341,010)
(Loss) Income Before Income Taxes	(406,275)			(35,157)	(26,237)	(64,547)							(90,784)			(125,941)	(341,010)
Income Tax Benefit																	0
Net (Loss) Income	$ (406,275)		$ (215,069)	$ (35,157)	$ (26,237)	$ (64,547)							$ (90,784)	$ (406,275)		$ (125,941)	$ (341,010)
Net income (loss) per share attributable to common stockholders(1)
Basic and Diluted (in dollars per share)			$ (6.47)	$ (1.06)	$ (0.79)	$ (1.94)							$ (2.73)			$ (3.79)
Basic (in dollars per share)	$ (12.23)																$ (10.26)
Diluted (in dollars per share)	$ (12.23)																$ (10.26)
Weighted Average Number of Common Shares Outstanding
Basic (in shares)	33,212																33,239
Diluted (in shares)	33,212																33,239
Basic and Diluted (in shares)				33,241	33,237	33,228							33,234			33,236
Predecessor
Revenues
Oil sales														256,050					$ 532,505	$ 1,025,017
Natural gas liquids sales														3,533					14,852	27,714
Natural gas sales														37,103					69,255	117,282
(Loss) Gain on derivative financial instruments																			90,506	235,439
Total Revenues														296,686					707,118	1,405,452
Costs and Expenses
Lease operating														136,578					328,183	449,972
Production taxes														482					1,442	8,385
Gathering and transportation														5,910					33,156	34,707
Pipeline facility fee														20,330					40,659
Depreciation, depletion and amortization														60,202					339,539	705,521
Accretion of asset retirement obligations														38,380					64,708	50,081
Impairment of oil and natural gas properties								$ 77,600	$ 143,100	$ 340,500	$ 1,425,800	$ 904,700		77,781	$ 2,330,500				2,814,028	2,421,884
Goodwill impairment		$ 329,300																		329,293
General and administrative expense														27,557					102,736	116,500
Total Costs and Expenses														367,220					3,724,451	4,116,343
Operating Loss							$ 12,795	(83,329)	(168,119)	(417,866)	(1,513,148)	(918,200)		(70,534)	(2,431,348)				(3,017,333)	(2,710,891)
Other Income (Expense)
Other income, net														117					3,596	4,176
Interest expense														(12,580)					(405,658)	(323,308)
Total Other (Expense) Income, net														(12,463)					1,112,788	(336,297)
Loss Before Reorganization Items and Income Taxes														(82,997)					(1,904,545)	(3,047,188)
Reorganization items														2,733,608					(14,201)
(Loss) Income Before Income Taxes														2,650,611	(1,883,924)				(1,918,746)	(3,047,188)
Income Tax Benefit															51				(87)	(613,350)
Net (Loss) Income							$ 2,771,349	$ (120,738)	$ (195,460)	$ 160,776	$ (1,310,583)	$ (573,392)		$ 2,650,611	$ (1,883,975)				$ (1,918,659)	$ (2,433,838)
Net income (loss) per share attributable to common stockholders(1)
Basic (in dollars per share)							$ 28.04	$ (1.23)	$ (1.97)	$ 1.65	$ (13.81)	$ (6.08)		$ 26.95	$ (19.91)				$ (20.08)	$ (25.97)
Diluted (in dollars per share)							$ 26.45	$ (1.23)	$ (1.97)	$ 1.55	$ (13.81)	$ (6.08)		$ 25.30	$ (19.91)				$ (20.08)	$ (25.97)
Weighted Average Number of Common Shares Outstanding
Basic (in shares)														98,337	94,926				95,822	94,167
Diluted (in shares)														104,787	94,926				95,822	94,167
As reported
Revenues
Oil sales				$ 114,991	$ 118,180	$ 133,621							$ 251,801			$ 366,792
Natural gas liquids sales				2,209	2,370	2,227							4,597			6,806
Natural gas sales				12,261	13,753	18,368							32,121			44,382
(Loss) Gain on derivative financial instruments				(12,466)	9,412	3,698							13,110			644
Total Revenues				116,995	143,715	157,914							301,629			418,624
Costs and Expenses
Lease operating				77,822	85,336	75,157							160,493			238,315
Production taxes				471	482	239							721			1,192
Gathering and transportation				(2,441)	2,678	11,222							13,900			11,459
Pipeline facility fee				10,495	10,494	10,494							20,988			31,483
Depreciation, depletion and amortization				36,066	38,661	42,006							80,667			116,733
Accretion of asset retirement obligations				9,892	10,050	12,397							22,447			32,339
Impairment of oil and natural gas properties				(2,357)	(848)	44,054							43,206			40,849
General and administrative expense				15,026	20,716	23,848							42,320			57,346
Reorganization items					(3,773)								(1,529)			(1,529)
Total Costs and Expenses				144,974	163,796	219,417							383,213			528,187
Operating Loss				(27,979)	(20,081)	(61,503)							(81,584)			(109,563)
Other Income (Expense)
Other income, net				52	80	22							102			154
Interest expense				(3,653)	(3,642)	(3,834)							(7,476)			(11,129)
Total Other (Expense) Income, net				(3,601)	(3,562)	(3,812)							(7,374)			(10,975)
(Loss) Income Before Income Taxes				(31,580)	(23,643)	(65,315)							(88,958)			(120,538)
Net (Loss) Income				$ (31,580)	$ (23,643)	$ (65,315)							$ (88,958)			$ (120,538)
Net income (loss) per share attributable to common stockholders(1)
Basic and Diluted (in dollars per share)				$ (0.95)	$ (0.71)	$ (1.97)							$ (2.68)			$ (3.63)
Weighted Average Number of Common Shares Outstanding
Basic and Diluted (in shares)				33,241	33,237	33,228							33,234			33,236
Adjustment
Revenues
Oil sales				$ (1,294)	$ 304	$ 172							$ 476			$ (818)
Total Revenues				(1,294)	304	172							476			(818)
Costs and Expenses
Lease operating					(1,681)	2,110							429			429
Depreciation, depletion and amortization				65	24	(110)							(86)			(21)
Accretion of asset retirement obligations				(139)	(66)	684							618			479
Impairment of oil and natural gas properties				2,357	848	(3,280)							(2,432)			(75)
Reorganization items					3,773								3,773			3,773
Total Costs and Expenses				2,283	2,898	(596)							2,302			4,585
Operating Loss				(3,577)	(2,594)	768							(1,826)			(5,403)
Other Income (Expense)
(Loss) Income Before Income Taxes				(3,577)	(2,594)	768							(1,826)			(5,403)
Net (Loss) Income				$ (3,577)	$ (2,594)	$ 768							$ (1,826)			$ (5,403)
Net income (loss) per share attributable to common stockholders(1)
Basic and Diluted (in dollars per share)				$ (0.11)	$ (0.08)	$ 0.02							$ (0.05)			$ (0.16)
Weighted Average Number of Common Shares Outstanding
Basic and Diluted (in shares)				33,241	33,237	33,228							33,234			33,236
Predecessor
Revenues
Oil sales								$ 123,084						$ 256,050					$ 532,505
Natural gas liquids sales								2,144						3,533					14,852
Natural gas sales								17,735						37,103					69,255
(Loss) Gain on derivative financial instruments																			90,506
Total Revenues							$ 153,723	142,963						296,686					707,118
Costs and Expenses
Lease operating								65,170						136,578					328,183
Production taxes								214						482					1,442
Gathering and transportation								7,534						5,910					33,156
Pipeline facility fee								10,165						20,330					40,659
Depreciation, depletion and amortization								31,141						60,202					339,539
Accretion of asset retirement obligations								19,075						38,380					64,708
Impairment of oil and natural gas properties								77,558						77,781					2,814,028
General and administrative expense								15,435						27,557					102,736
Total Costs and Expenses								226,292						367,220					3,724,451
Operating Loss							12,795	(83,329)						(70,534)					(3,017,333)
Other Income (Expense)
Other income, net								62						117					3,596
Interest expense								(4,838)						(12,580)					(405,658)
Total Other (Expense) Income, net								(4,776)						(12,463)					1,112,788
Loss Before Reorganization Items and Income Taxes								(88,105)						(82,997)					(1,904,545)
Reorganization items								(32,633)						2,733,608					(14,201)
(Loss) Income Before Income Taxes								(120,738)						2,650,611					(1,918,746)
Income Tax Benefit																			(87)
Net (Loss) Income							$ 2,771,349	$ (120,738)						$ 2,650,611					$ (1,918,659)
Net income (loss) per share attributable to common stockholders(1)
Basic and Diluted (in dollars per share)								$ (1.23)											$ (20.08)
Basic (in dollars per share)							$ 28.04							$ 26.95
Diluted (in dollars per share)							$ 26.45							$ 25.30
Weighted Average Number of Common Shares Outstanding
Basic (in shares)							98,850							98,337
Diluted (in shares)							104,787							104,787
Basic and Diluted (in shares)								97,824											95,822
Predecessor | As reported
Revenues
Oil sales								$ 122,732						$ 255,040					$ 531,914
Natural gas liquids sales								2,144						3,533					14,852
Natural gas sales								17,735						37,103					69,255
(Loss) Gain on derivative financial instruments																			90,506
Total Revenues							$ 153,065	142,611						295,676					706,527
Costs and Expenses
Lease operating								65,170						137,007					328,183
Production taxes								214						482					1,442
Gathering and transportation								7,534						5,910					33,156
Pipeline facility fee								10,165						20,330					40,659
Depreciation, depletion and amortization								31,573						60,626					339,516
Accretion of asset retirement obligations								19,437						38,973					64,690
Impairment of oil and natural gas properties								86,820						86,820					2,813,570
General and administrative expense								15,435						27,557					102,736
Total Costs and Expenses								236,348						377,705					3,723,952
Operating Loss							11,708	(93,737)						(82,029)					(3,017,425)
Other Income (Expense)
Other income, net								62						117					3,596
Interest expense								(4,838)						(12,580)					(405,658)
Total Other (Expense) Income, net								(4,776)						(12,463)					1,112,788
Loss Before Reorganization Items and Income Taxes								(98,513)						(94,492)					(1,904,637)
Reorganization items								(32,633)						2,748,395					(14,201)
(Loss) Income Before Income Taxes								(131,146)						2,653,903					(1,918,838)
Income Tax Benefit																			(87)
Net (Loss) Income							$ 2,785,049	$ (131,146)						$ 2,653,903					$ (1,918,751)
Net income (loss) per share attributable to common stockholders(1)
Basic and Diluted (in dollars per share)								$ (1.34)											$ (20.11)
Basic (in dollars per share)							$ 28.17							$ 26.99
Diluted (in dollars per share)							$ 26.58							$ 25.33
Weighted Average Number of Common Shares Outstanding
Basic (in shares)							98,850							98,337
Diluted (in shares)							104,787							104,787
Basic and Diluted (in shares)								97,824											95,822
Predecessor | Adjustment
Revenues
Oil sales								$ 352						$ 1,010					$ 591
Total Revenues							$ 658	352						1,010					591
Costs and Expenses
Lease operating														(429)
Depreciation, depletion and amortization								(432)						(424)					23
Accretion of asset retirement obligations								(362)						(593)					18
Impairment of oil and natural gas properties								(9,262)						(9,039)					458
Total Costs and Expenses								(10,056)						(10,485)					499
Operating Loss							1,087	10,408						11,495					92
Other Income (Expense)
Loss Before Reorganization Items and Income Taxes								10,408						11,495					92
Reorganization items														(14,787)
(Loss) Income Before Income Taxes								10,408						(3,292)					92
Net (Loss) Income							$ (13,700)	$ 10,408						$ (3,292)					$ 92
Net income (loss) per share attributable to common stockholders(1)
Basic and Diluted (in dollars per share)								$ 0.11											$ 0.03
Basic (in dollars per share)							$ (0.14)							$ (0.04)
Diluted (in dollars per share)							$ (0.13)							$ (0.03)
Weighted Average Number of Common Shares Outstanding
Basic (in shares)							98,850							98,337
Diluted (in shares)							104,787							104,787
Basic and Diluted (in shares)								97,824											95,822

Supplementary Oil and Gas In150

Supplementary Oil and Gas Information – Unaudited - Costs incurred for oil and natural gas property (Details) $ in Thousands	6 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)MMBoe	Dec. 31, 2017USD ($)MMBoe	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)MMBoe	Jun. 30, 2014MMBoe
Property acquisitions
Proved		$ 96
Exploration costs		669
Development costs		$ 62,283
Proved Undeveloped Reserves (Energy) | MMBoe	36,498	22,039
Future development costs associated with proved undeveloped reserves	$ 443,200	$ 356,100
Predecessor
Property acquisitions
Proved	1,500		$ 26,400
Unevaluated				$ 2,304
Exploration costs			1,400	38,183
Development costs	$ 22,300		$ 57,400	$ 608,605
Proved Undeveloped Reserves (Energy) | MMBoe				58,151	96,256

Supplementary Oil and Gas In151

Supplementary Oil and Gas Information – Unaudited - Estimated quantities and changes in quantities of proved reserves (Details) $ in Millions	6 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)MMBoeMMcfMBbls	Dec. 31, 2017USD ($)MMBoeMMcfMBbls	Jun. 30, 2016MMBoeMMcfMBbls	Jun. 30, 2015MMBoeMMcfMBbls	Jun. 30, 2014MMBoeMMcfMBbls
Reserves
Proved reserves, beginning balance (Energy) | MMBoe		121,937
Production (Energy) | MMBoe		(12,493)
Extensions, discoveries and other additions (Energy) | MMBoe		7,082
Revisions of previous estimates (Energy) | MMBoe		(28,327)
Proved reserves, ending balance (Energy) | MMBoe	121,937	88,199
Proved developed reserves (Energy) | MMBoe	85,439	66,160
Proved undeveloped reserves (Energy) | MMBoe	36,498	22,039
Decrease in proved reserves (in MMBOE) | MMBoe		33.7
Increase in proved reserves (as a percent)		28.00%
Future development costs associated with proved undeveloped reserves | $	$ 443.2	$ 356.1
Proved Developed Nonproducing Reserves
Reserves
Negative revisions (Energy) | MMBoe		9.6
Oil Reserves
Reserves
Proved reserves, beginning balance (Volume)		95,250
Production (Volume)		(9,324)
Extensions, discoveries and other additions (Volume)		5,691
Revisions of previous estimates (Volume)		(17,261)
Proved reserves, ending balance (Volume)	95,250	74,356
Proved developed reserves (Volume)	63,728	55,005
Proved undeveloped reserves (Volume)	31,522	19,351
Natural Gas Liquids
Reserves
Proved reserves, beginning balance (Volume)		3,148
Production (Volume)		(288)
Extensions, discoveries and other additions (Volume)		217
Revisions of previous estimates (Volume)		(1,397)
Proved reserves, ending balance (Volume)	3,148	1,680
Proved developed reserves (Volume)	2,777	1,335
Proved undeveloped reserves (Volume)	371	345
Natural Gas Reserves
Reserves
Proved reserves, beginning balance (Volume) | MMcf		141,238
Production (Volume) | MMcf		(17,282)
Extensions, discoveries and other additions (Volume) | MMcf		7,030
Revisions of previous estimates (Volume) | MMcf		(58,001)
Proved reserves, ending balance (Volume) | MMcf	141,238	72,985
Proved developed reserves (Volume) | MMcf	113,603	58,918
Proved undeveloped reserves (Volume) | MMcf	27,635	14,067
Predecessor
Reserves
Proved reserves, beginning balance (Energy) | MMBoe	86,564		183,496	246,198
Production (Energy) | MMBoe	(7,897)		(19,209)	(21,504)
Extensions, discoveries and other additions (Energy) | MMBoe	36,852		1,704	17,295
Revisions of previous estimates (Energy) | MMBoe	6,418		(91,031)	(46,333)
Sales of reserves (Energy) | MMBoe				(12,160)
Purchases of reserves (Energy) | MMBoe			11,604
Proved reserves, ending balance (Energy) | MMBoe			86,564	183,496
Proved developed reserves (Energy) | MMBoe			86,564	125,345	149,942
Proved undeveloped reserves (Energy) | MMBoe				58,151	96,256
Predecessor | Oil Reserves
Reserves
Proved reserves, beginning balance (Volume)	62,140		129,596	175,816
Production (Volume)	(5,482)		(12,624)	(14,272)
Extensions, discoveries and other additions (Volume)	31,846		1,370	10,056
Revisions of previous estimates (Volume)	6,746		(61,347)	(32,115)
Sales of reserves (Volume)				(9,889)
Purchases of reserves (Volume)			5,145
Proved reserves, ending balance (Volume)			62,140	129,596
Proved developed reserves (Volume)			62,140	88,607	106,900
Proved undeveloped reserves (Volume)				40,989	68,916
Predecessor | Natural Gas Liquids
Reserves
Proved reserves, beginning balance (Volume)	4,233		7,476	9,573
Production (Volume)	(167)		(923)	(987)
Extensions, discoveries and other additions (Volume)	375		46	517
Revisions of previous estimates (Volume)	(1,293)		(3,237)	(1,615)
Sales of reserves (Volume)				(12)
Purchases of reserves (Volume)			871
Proved reserves, ending balance (Volume)			4,233	7,476
Proved developed reserves (Volume)			4,233	5,406	5,889
Proved undeveloped reserves (Volume)				2,070	3,684
Predecessor | Natural Gas Reserves
Reserves
Proved reserves, beginning balance (Volume) | MMcf	121,147		278,543	364,856
Production (Volume) | MMcf	(13,485)		(33,973)	(37,472)
Extensions, discoveries and other additions (Volume) | MMcf	27,788		1,729	40,330
Revisions of previous estimates (Volume) | MMcf	5,788		(158,681)	(75,617)
Sales of reserves (Volume) | MMcf				(13,554)
Purchases of reserves (Volume) | MMcf			33,529
Proved reserves, ending balance (Volume) | MMcf			121,147	278,543
Proved developed reserves (Volume) | MMcf			121,147	187,993	222,916
Proved undeveloped reserves (Volume) | MMcf				90,550	141,940
Reserve Revision Due To Change In Estimates Of Lease Operating Expenses
Reserves
Negative revisions (Energy) | MMBoe		10.7
Reserve Revision Due To Updated Technical Assessments Delayed Drilling Activity And Changes To Drilling Schedule | Proved Undeveloped Reserves
Reserves
Negative revisions (Energy) | MMBoe		17.4
Reserve Revision Due To Changes In Drilling Schedule Truncating Proved Economic Field Lives | Proved Developed Nonproducing Reserves
Reserves
Negative revisions (Energy) | MMBoe		4.2
Reserve Revision Due To Updated Technical Assessments | Proved Developed Nonproducing Reserves
Reserves
Negative revisions (Energy) | MMBoe		5.2
Reserve Revision Due To Increased Product Prices And Improved Field Economics
Reserves
Upward revisions (Energy) | MMBoe		7
Reserve Revision Due To Performance | Proved Developed Producing Reserves
Reserves
Upward revisions (Energy) | MMBoe		3.3

Supplementary Oil and Gas In152

Supplementary Oil and Gas Information – Unaudited - Standardized measure of discounted future net cash flows - Average price (Details)	12 Months Ended
	Dec. 31, 2017$ / MMBTU$ / bbl
Oil
Standardized Measure of Discounted Future Net Cash Flows
Average price used to compute future cash inflows (in dollars per unit)	47.79
Average realized adjusted product price used to compute future net revenue (in dollars per unit)	50.99
NGL
Standardized Measure of Discounted Future Net Cash Flows
Average realized adjusted product price used to compute future net revenue (in dollars per unit)	26.79
Natural gas
Standardized Measure of Discounted Future Net Cash Flows
Average price used to compute future cash inflows (in dollars per unit) | $ / MMBTU	2.98
Average realized adjusted product price used to compute future net revenue (in dollars per unit) | $ / MMBTU	2.85

Supplementary Oil and Gas In153

Supplementary Oil and Gas Information – Unaudited - Schedule of standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows	$ 4,044,208
Production costs	2,714,819
Development and abandonment costs	1,425,847
Future net cash flows	(96,458)
Less: Ten percent annual discount for estimated timing of cash flows	(111,594)
Standardized measure of discounted future net cash flows	$ 15,136	$ 148,845
Predecessor
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows		4,344,985	$ 2,966,317	$ 10,641,151
Production costs		2,648,363	2,223,645	4,131,526
Development and abandonment costs		1,571,271	1,033,717	1,970,526
Income taxes				168,655
Future net cash flows		125,351	(291,045)	4,370,444
Less: Ten percent annual discount for estimated timing of cash flows		(23,494)	(349,398)	1,613,034
Standardized measure of discounted future net cash flows		$ 148,845	$ 58,353	$ 2,757,410	$ 5,947,525

Supplementary Oil and Gas In154

Supplementary Oil and Gas Information – Unaudited - Changes in standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Jun. 30, 2016	Jun. 30, 2015
Changes in Standardized Measure of Discounted Future Net Cash Flows
Beginning of period		$ 148,845
Changes in prices and costs		252,357
Changes in quantities		(198,211)
Additions to proved reserves resulting from extensions, discoveries, other additions and improved recovery, less related costs		8,908
Accretion of discount		14,885
Sales, net of production and gathering and transportation costs		(224,976)
Changes in rate of production and other		(22,862)
Development costs incurred		3,878
Changes in estimated future development and abandonment costs		32,312
Net change		(133,709)
End of period	$ 148,845	15,136
Predecessor
Changes in Standardized Measure of Discounted Future Net Cash Flows
Beginning of period	58,353	$ 148,845	$ 2,757,410	$ 5,947,525
Changes in prices and costs	(104,993)		(3,287,459)	(2,959,883)
Changes in quantities	53,585		(214,631)	(2,390,099)
Additions to proved reserves resulting from extensions, discoveries, other additions and improved recovery, less related costs	325,892		26,911	201,234
Purchases (sales) of reserves in place			212,961	(244,507)
Accretion of discount	(893)		215,297	760,175
Sales, net of production and gathering and transportation costs	(131,947)		(212,581)	(676,949)
Net change in income taxes			77,025	1,576,954
Changes in rate of production and other	(2,704)		4,189	(191,668)
Development costs incurred	11,283		10,493	237,173
Changes in estimated future development and abandonment costs	(59,731)		468,738	497,455
Net change	90,492		(2,699,057)	(3,190,115)
End of period	$ 148,845		$ 58,353	$ 2,757,410