Warren Resources (WRES) 10-K 7 Apr 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Apr. 07, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Trading Symbol	WRES
Entity Registrant Name	WARREN RESOURCES INC
Entity Central Index Key	892,986
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	No
Entity Voluntary Filers	No
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		10,000,000
Entity Public Float			$ 1.6

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 5,642
Accounts receivable, net of allowance for doubtful accounts of $808 and $15 at December 31, 2016 and 2015, respectively	10,847
Derivative financial instruments	587
Other current assets	4,503
Total current assets	21,579
Noncurrent Assets
Oil and gas properties - at cost, based on full cost method of accounting, net of accumulated depreciation, depletion and impairment (includes unproven properties excluded from depletion of $- and $14,658 in 2016 and 2015, respectively)	68,363
Property and equipment - at cost, net	30,913
Other assets	3,036
Total other assets	102,312
Total assets	123,891
Current liabilities
Accounts payable and accrued expenses	14,218
Short-term derivatives	6,313
Total current liabilities	20,531
Noncurrent liabilities
Long-term debt-related party	140,320
Other long-term liabilities	39,229
Total liabilities	200,080
Commitments and contingencies
Stockholders' Equity (Deficit)
Common stock, $.01 par value, authorized 100,000,000 shares, 10,000,000 shares issued in 2016; $.001 par value, authorized 100,000,000 shares, 85,203,466 issued in 2015	100
Additional paid-in capital	90,824
Accumulated deficit	(167,113)
Cancellation of Predecessor Company equity	(76,189)
Total liabilities and stockholders' equity	$ 123,891
Predecessor [Member]
Current assets
Cash and cash equivalents		$ 26,764
Accounts receivable, net of allowance for doubtful accounts of $808 and $15 at December 31, 2016 and 2015, respectively		9,880
Restricted investments in U.S. Treasury Bonds - available for sale at fair value (amortization costs of $- and $1,138 in 2016 and 2015, respectively)		1,448
Derivative financial instruments		11,081
Other current assets		5,439
Total current assets		54,612
Noncurrent Assets
Oil and gas properties - at cost, based on full cost method of accounting, net of accumulated depreciation, depletion and impairment (includes unproven properties excluded from depletion of $- and $14,658 in 2016 and 2015, respectively)		162,685
Property and equipment - at cost, net		1,548
Other assets		3,107
Total other assets		167,340
Total assets		221,952
Current liabilities
Accounts payable and accrued expenses		42,971
Current maturities on other long-term debt		153
First Lien Credit Facility, net of debt issuance costs of $4,980		229,685
Second Lien Credit Facility, net of debt issuance costs of $1,952		72,960
Senior Notes, net of debt issuance costs of $5,482		159,885
Total current liabilities		507,194
Noncurrent liabilities
Other long-term liabilities		38,322
Total liabilities		545,516
Commitments and contingencies
Stockholders' Equity (Deficit)
8% convertible preferred stock, par value $.0001; authorized 10,000,000 shares, issued and outstanding, 10,703 shares in 2015, (aggregate liquidation preference $128,437 in 2015)		128
Common stock, $.01 par value, authorized 100,000,000 shares, 10,000,000 shares issued in 2016; $.001 par value, authorized 100,000,000 shares, 85,203,466 issued in 2015		9
Additional paid-in capital		516,715
Accumulated deficit		(840,606)
Accumulated other comprehensive income, net of applicable income taxes		190
Cancellation of Predecessor Company equity		(323,564)
Total liabilities and stockholders' equity		221,952
Predecessor [Member] | Convertible Debentures [Member]
Current liabilities
Convertible Debentures, net of debt issuance costs of $96		$ 1,540

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Accounts receivable, allowance for doubtful accounts	$ 808,000	$ 16,000
Restricted investments in U.S. Treasury bonds-available for sale, amortized cost	0
Oil and gas properties, unproved properties excluded from depletion	0
Net of debt issuance costs	$ 0
Preferred stock dividend rate	8.00%
Common stock, par value	$ 0.010
Common stock, authorized shares	100,000,000
Common stock, issued shares	10,000,000
Predecessor [Member]
Accounts receivable, allowance for doubtful accounts		15,000
Restricted investments in U.S. Treasury bonds-available for sale, amortized cost		1,138,000
Oil and gas properties, unproved properties excluded from depletion		14,658,000
Net of debt issuance costs		$ 12,500,000
Preferred stock dividend rate		8.00%
8% convertible preferred stock, par value		$ 0.0001
8% convertible preferred stock, authorized shares		10,000,000
8% convertible preferred stock, issued shares		10,703
8% convertible preferred stock, outstanding shares		10,703
8% convertible preferred stock, aggregate liquidation preference		$ 128,437,000
Common stock, par value		$ 0.001
Common stock, authorized shares		100,000,000
Common stock, issued shares		85,203,466
First Lien Credit Facility [Member] | Predecessor [Member]
Net of debt issuance costs		$ 4,980,000
Second Lien Credit Facility [Member] | Predecessor [Member]
Net of debt issuance costs		1,952,000
Senior Notes [Member] | Predecessor [Member]
Net of debt issuance costs		5,482,000
Convertible Debentures [Member] | Predecessor [Member]
Net of debt issuance costs		$ 96,000

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Operating Revenues
Oil and gas sales	$ 16,862
Transportation revenue	977
Total revenues	17,839
Operating Expenses
Lease operating expenses and taxes	10,678
Depreciation, depletion and accretion	10,837
Impairment expense	145,117
Transportation expense	459
General and administrative	3,349
Total operating expenses	170,440
Loss from operations	(152,601)
Other income (expense)
Interest and other income	11
Interest expense, net (includes contractual interest expense on debt subject to compromise of $13,040 the nine months ended September 30, 2016)	(3,649)
Gain (loss) on financial instruments	(10,874)
Total other income (expense)	(14,512)
Loss before provision for income taxes	(167,113)
Net loss	(167,113)
Net loss applicable to common stockholders	$ (167,113)
Loss per common share - Basic and diluted	$ (16.71)
Weighted average common shares outstanding - Basic and diluted	10,000,000
Predecessor [Member]
Operating Revenues
Oil and gas sales		$ 39,712	$ 83,734
Transportation revenue		3,205	4,639
Total revenues		42,917	88,373
Operating Expenses
Lease operating expenses and taxes		32,611	49,557
Depreciation, depletion and accretion		18,885	66,159
Impairment expense		87,094	578,323
Transportation expense		1,048	1,706
General and administrative		8,864	17,703
Reorganization items		14,171
Total operating expenses		162,673	713,448
Loss from operations		(119,756)	(625,075)
Other income (expense)
Interest and other income		537	5,621
Interest expense, net (includes contractual interest expense on debt subject to compromise of $13,040 the nine months ended September 30, 2016)		(31,812)	(30,403)
Gain (loss) on financial instruments		1,131	20,083
Loss on contingent consideration		(430)	(540)
Gain on debt extinguishment			14,407
Troubled debt restructuring expense			(4,039)
Total other income (expense)		(30,574)	5,129
Loss before provision for income taxes		(150,330)	(619,946)
Deferred income tax expense		124	17
Net loss		(150,454)	(619,963)
Less dividends and accretion on preferred shares			10
Net loss applicable to common stockholders		$ (150,454)	$ (619,973)
Loss per common share - Basic and diluted		$ (1.77)	$ (7.55)
Weighted average common shares outstanding - Basic and diluted		85,239,176	82,128,892

Consolidated Statements of Ope5

Consolidated Statements of Operations (Parenthetical) $ in Thousands	9 Months Ended
	Sep. 30, 2016USD ($)
Predecessor [Member]
Contractual interest expense on debt subject to compromise	$ 13,040

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net loss	$ (167,113)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and accretion	10,837
Impairment of oil and gas properties	145,117
Unrealized loss (gain) on derivative instruments	10,181
Change in assets and liabilities:
Decrease in accounts receivable - trade	(4,243)
Decrease (increase) in other assets	236
Increase (decrease) in accounts payable and accruals	(2,462)
Net cash provided by (used in) operating activities	(7,447)
Cash flows from investing activities:
Purchase, exploration and development of oil and gas properties	(1,720)
Purchase of property and equipment	(225)
Net cash used in investing activities	(1,945)
Cash flows from financing activities:
Proceeds from Credit Facility and Senior Note offerings	10,000
Net cash provided by (used in) financing activities	10,000
Net increase (decrease) in cash and cash equivalents	608
Cash and cash equivalents at beginning of period	5,034
Cash and cash equivalents at end of period	5,642	$ 5,034
Supplemental disclosure of cash flow information
Cash paid for interest, net of amounts capitalized	3,200
Income taxes paid	0
Noncash investing and financing activities
Accrued interest converted to debt	320
Predecessor [Member]
Cash flows from operating activities:
Net loss		(150,454)	$ (619,963)
Adjustments to reconcile net loss to net cash provided by operating activities:
Accretion of discount on available for sale debt securities		(393)	(69)
Accretion of discount on senior notes		214	426
Accretion of second lien premium		(3,539)
Amortization of deferred bond offering costs		1,783	4,655
Depreciation, depletion and accretion		18,885	66,159
Impairment of oil and gas properties		87,094	578,323
Deferred tax benefit		124	17
Unrealized loss (gain) on derivative instruments		10,947	(7,076)
Loss on contingent consideration		430	540
Stock-based compensation		640	2,212
Bad debt expense		701
Gain on debt extinguishment			(14,407)
Change in assets and liabilities:
Decrease in accounts receivable - trade		2,277	10,145
Decrease (increase) in other assets		868	(7,303)
Increase (decrease) in accounts payable and accruals		12,239	(8,255)
Decrease in other long term liabilities			(1,772)
Net cash provided by (used in) operating activities		(18,184)	3,632
Cash flows from investing activities:
Purchase, exploration and development of oil and gas properties		(3,332)	(36,112)
Purchase of property and equipment		(110)	(254)
Liquidation of U.S. Treasury Bonds		1,527
Net cash used in investing activities		(1,915)	(36,366)
Cash flows from financing activities:
Payments on debt issuance costs		(8)
Payments on debt and debentures		(1,623)	(289,860)
Proceeds from Credit Facility and Senior Note offerings			347,984
Payments on taxes of vested restricted stock and proceeds from the exercise of options			(329)
Net cash provided by (used in) financing activities		(1,631)	57,795
Net increase (decrease) in cash and cash equivalents		(21,730)	25,061
Cash and cash equivalents at beginning of period	$ 5,034	26,764	1,703
Cash and cash equivalents at end of period		5,034	26,764
Supplemental disclosure of cash flow information
Cash paid for interest, net of amounts capitalized		17,048	21,763
Income taxes paid		0	0
Noncash investing and financing activities
Accrued interest converted to debt		$ 3,079
Accrued preferred stock dividend			10
Change in accounts payable relating to oil and gas property			(6,173)
Increase in asset retirement liability			9
Common stock issued for Second Lien Credit Facility			2,000
Noncash debt restructuring exchanges			40,221
Predecessor [Member] | Citrus Acquisition Of Marcellus Assets
Noncash investing and financing activities
Earn-Out provision for Citrus Acquisition			730
Farm-Out provision for Citrus Acquisition			$ (3,410)

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Loss - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Net loss	$ (167,113)
Other comprehensive loss:
Comprehensive loss	$ (167,113)
Predecessor [Member]
Net loss		$ (150,454)	$ (619,963)
Other comprehensive loss:
Gain (loss) on investments available for sale		(190)	(26)
Comprehensive loss		$ (150,644)	$ (619,989)

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity (Deficit) - USD ($) shares in Thousands, $ in Thousands	Total	Preferred Stock [Member]	Common Stock [Member]	Additional Paid-In Capital [Member]	Accumulated Deficit [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Beginning balance (Predecessor [Member]) at Dec. 31, 2014	$ 292,552	$ 128	$ 8	$ 512,843	$ (220,643)	$ 216
Beginning balance, shares (Predecessor [Member]) at Dec. 31, 2014		11	80,754
Shares issued and taxes paid from vesting of restricted stock | Predecessor [Member]	(329)		$ 1	(330)
Shares issued and taxes paid from vesting of restricted stock, shares | Predecessor [Member]			449
Shares issued from debt exchange | Predecessor [Member]	2,000			2,000
Shares issued from debt exchange, shares | Predecessor [Member]			4,000
Dividends declared on preferred stock | Predecessor [Member]	(10)			(10)
Stock-based compensation | Predecessor [Member]	2,212			2,212
Net loss | Predecessor [Member]	(619,963)				(619,963)
Net change in unrealized gain on investment securities available for sale, net of applicable income tax | Predecessor [Member]	(26)					(26)
Ending balance (Predecessor [Member]) at Dec. 31, 2015	(323,564)	$ 128	$ 9	516,715	(840,606)	190
Ending balance, shares (Predecessor [Member]) at Dec. 31, 2015		11	85,203
Issuance of Successor common stock and warrants	90,924		$ 100	90,824
Issuance of Successor common stock and warrants, shares			10,000
Shares issued and taxes paid from vesting of restricted stock, shares | Predecessor [Member]			51
Stock-based compensation | Predecessor [Member]	640			640
Reverse preferred stock dividend | Predecessor [Member]	113			113
Net loss | Predecessor [Member]	(150,454)				(150,454)
Net change in unrealized gain on investment securities available for sale, net of applicable income tax | Predecessor [Member]	(190)					$ (190)
Ending balance (Predecessor [Member]) at Sep. 30, 2016	(473,455)	$ 128	$ 9	517,468	(991,060)
Ending balance at Sep. 30, 2016	90,924		$ 100	90,824
Ending balance, shares (Predecessor [Member]) at Sep. 30, 2016		11	85,254
Ending balance, shares at Sep. 30, 2016			10,000
Cancellation of Predecessor equity | Predecessor [Member]	473,455	$ (128)	$ (9)	(517,468)	991,060
Cancellation of Predecessor equity, shares | Predecessor [Member]		(11)	(85,254)
Net loss	(167,113)				(167,113)
Ending balance at Dec. 31, 2016	$ (76,189)		$ 100	$ 90,824	$ (167,113)
Ending balance, shares at Dec. 31, 2016			10,000

Organization and Accounting Pol

Organization and Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Organization and Accounting Policies	NOTE A—ORGANIZATION AND ACCOUNTING POLICIES Nature of Operations Warren Resources, Inc. (the “Company” or “Warren Resources” or “Warren”), was originally formed on June 12, 1990 for the purpose of acquiring and developing oil and gas properties. The Company was incorporated under the laws of the state of Maryland prior to its reincorporation in the state of Delaware effective October 5, 2016. The Company’s properties are primarily located in California, Pennsylvania and Wyoming. Reclassifications Certain prior year amounts in the consolidated financial statements have been reclassified to conform to the current year presentation. Emergence from Voluntary Reorganization under Chapter 11 On June 2, 2016, the Company and certain of its wholly owned subsidiaries (together with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization (the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”), Case No. 16-32760. “debtors-in-possession” The description of the Plan can be found in its entirety by reference to the full text of the Confirmation Order, filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K Principles of Consolidation The consolidated financial statements include accounts of the Company, its wholly-owned subsidiaries, Warren Development Corp., Warren Drilling Corp., Warren Management Corp., Warren Resources of California, Inc., Warren Energy Services LLC, Warren Marcellus LLC and Warren E&P, Inc. All significant intercompany accounts and transactions have been eliminated in consolidation. Related Parties A party is considered to be related to the Company if the party directly or indirectly or through one or more intermediaries, controls, is controlled by, or is under common control with the Company. Related parties also include principal owners of the Company, its management, members of the immediate families of principal owners of the Company and its management and other parties with which the Company may deal if one party controls or can significantly influence the management or operating policies of the other to an extent that one of the transacting parties might be prevented from fully pursuing its own separate interests. A party which can significantly influence the management or operating policies of the transacting parties or if it has an ownership interest in one of the transacting parties and can significantly influence the other to an extent that one or more of the transacting parties might be prevented from fully pursuing its own separate interests is also a related party. Reorganization Items The Company and the Chapter 11 Subsidiaries have incurred significant one-time costs associated with their reorganization under the Bankruptcy Code, principally professional and legal fees. The amount of these costs, which are being expensed as incurred, significantly affect our results of operations. For the year ended December 31, 2016, restructuring costs amounted to $14.2 million. Oil and Gas Properties The Company accounts for its oil and gas activities using the full cost method. As prescribed by full cost accounting rules, all costs associated with property acquisition, exploration and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of oil and gas properties as well as other internal costs that can be specifically identified with acquisition, exploration and development activities are also capitalized. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs are depleted on the equivalent unit-of-production In accordance with full cost accounting rules, the Company is subject to a limitation on capitalized costs. The capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization, may not exceed the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, plus the cost of unproved properties excluded from amortization, as adjusted for related tax effects. If capitalized costs exceed this limit (the “ceiling limitation”), the excess must be charged to expense. The Company recorded impairment expenses of $145 million in the three months ended December 31, 2016 (Successor), $87 million in the nine months ended September 30, 2016 (Predecessor) and $578 million in the year ended December 31, 2015 (Predecessor). The costs of certain unevaluated oil and gas properties and exploratory wells being drilled are not included in the costs subject to amortization. The Company assesses costs not being amortized for possible impairments or reductions in value and if impairments or a reduction in value has occurred. An impairment of unevaluated oil and gas properties of $184 million was recorded for the year ended December 31, 2015. Revenue Recognition Oil and gas sales result from undivided interests held by the Company in various oil and gas properties. Sales of natural gas and oil produced are recognized when delivered to, or picked up by, the purchaser. For 2016, the largest purchasers and marketers of our total oil and gas production were Phillips 66, Clearwater Enterprises and Devlar Energy, which accounted for 58%, 35% and 6%, respectively, of total oil and natural gas sales sold in 2016. For 2015, the largest purchasers and marketers of our total oil and gas production were Phillips 66, Clearwater Enterprises and Devlar Energy, which accounted for 48%, 41% and 9%, respectively, of total oil and natural gas sales sold in 2015. Cash and Cash Equivalents The Company considers all highly liquid investments with maturities of three months or less when acquired to be cash equivalents. The Company maintains its cash and cash equivalents in bank deposit accounts that may exceed federally insured limits. At December 31, 2016, the Company had the majority of its cash and cash equivalents with one financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on cash and cash equivalents. Accounts Receivable Accounts receivable include trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on evaluation of a customer’s financial condition and, generally, collateral is not required. Accounts receivable under joint operating agreements generally have a right of offset against future oil and gas revenues if a producing well is completed. Accounts receivable are due within 30 days and are stated at amounts due from customers net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. As of December 31, 2016 and 2015, the Company has an allowance of $808,000 and $16,000 respectively, for doubtful accounts. Investments The Company classifies its investment in debt securities as available-for-sale Available-for-sale Available-for-sale non-current Offering Costs Costs incurred in connection with the issuance of debt are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest rate method. The Company had $- million (Successor) and $12.5 million (Predecessor), net of accumulated amortization of $- million (Successor) and $4.7 million (Predecessor), included as a direct deduction from the carrying amount of the associated debt liability at December 31, 2016 and 2015, respectively. Costs associated with the issuance of preferred and common stock are reflected as a reduction of proceeds. Income Taxes Deferred income taxes are recognized for the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts based on enacted tax laws and statutory rates applicable to the period in which the differences are expected to affect taxable income. Valuation allowances are established when, in management’s opinion, it is more likely than not that a portion or all of the deferred tax assets will not be realized. The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. Only tax positions that meet the more-likely-than-not Use of Estimates In preparing financial statements, accounting principles generally accepted in the United States of America require management to make estimates and assumptions in determining the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining year end proved oil and gas reserves. Actual results could differ from those estimates. The estimate of the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect reported results. Gas Imbalances The Company follows the sales method of accounting for gas imbalances. A liability is recorded when the Company’s excess takes of natural gas volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production. The Company has no significant gas imbalances at December 31, 2016 or December 31, 2015. Stock Based Compensation The Company uses the Black-Scholes option-pricing formula and the Monte Carlo Simulation method to estimate the fair value of stock based compensation expense at the grant date related to stock options and certain restricted stock grants issued. This expense is then recognized using the straight-line method over the vesting period. For the nine months ended September 30, 2016 (Predecessor), the Company recognized approximately $0.6 million in compensation expense related to stock option plans and restricted stock. Compensation expense incurred during the year ended December 31, 2015 (Predecessor) amounted to $2.2 million Both the Black-Scholes and the Monte Carlo Simulation method require numerous assumptions, including volatility, service periods and cancellations in their calculations. The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes options-pricing model with the following weighted average assumptions used for grants in 2015. No expected dividends, weighted average volatility of 64%, risk free interest rates of 1.23% and expected lives of 3.5 years for incentive options issued in 2015. The volatility assumptions were calculated based on the performance of our stock prices for the year. The weighted average per share fair values of the options issued in 2015 were $0.40. There were no stock options issued in 2016. Accounting for Long-Lived Assets The Company reviews property and equipment for impairment whenever indicators of impairment are present to determine if the carrying amounts exceed the estimated future net cash flows to be realized. Impairment losses are recognized based on the estimated fair value of the asset. Derivative financial instruments The Company has entered into several crude oil and natural gas hedges in order to minimize any effect of a downturn in oil and gas prices and protect profitability. These derivative financial instruments are carried on the balance sheet at fair value. If a derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. Gains and losses resulting from changes in the fair value of the non-designated Property and Equipment Property and equipment are stated at cost and are depreciated using the straight-line method over the estimated useful lives of the assets, ranging from three to twenty-five years, except for land which is not depreciated. Property and equipment consisted of the following at December 31: Successor Predecessor Year ended Year ended (in thousands) Drilling rig $ — $ 22,374 Equipment 21,592 1,503 Automobiles and trucks 278 801 Furniture and fixtures — 522 Land and buildings 9,077 242 Office equipment 385 2,124 31,332 27,566 Less accumulated depreciation and amortization (419 ) (26,018 ) $ 30,913 $ 1,548 During the year ended December 31, 2015, the Company recognized an impairment expense on their drilling rig of $16.7 million (Predecessor). Earnings (Loss) Per Common Share Basic earnings (loss) per common share is computed by dividing the net earnings (loss) applicable to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share is based on the assumption that stock options and warrants are converted into common shares using the treasury stock method and convertible debentures and preferred stock are converted using the if-converted Successor Predecessor Year ended Year ended Weighted average shares outstanding—basic 10,000,000 82,128,892 Incremental shares issuable from dilutive stock options — — Weighted average shares outstanding—diluted 10,000,000 82,128,892 Potential common shares relating to options, warrants, preferred stock, restricted stock and convertible debentures excluded from the computations of diluted earnings (loss) per share because they are anti-dilutive are as follows: Successor Predecessor Year ended Year ended Employee stock options — 3,593,589 Convertible debentures — 32,720 Preferred stock — 5,352 Restricted stock — 1,277,468 Warrants 526,316 — Preferred stock was convertible from the date of issuance until redemption at 100% of the redemption price amount into common stock of the Company at a conversion rate between 1 to 1 and 1 to 0.5. At December 31, 2015, the Convertible Debentures could be converted until maturity at 100% of principal amount into common stock of the Company at a price of $50.00. Asset Retirement Obligations The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production Balance at December 31, 2014 (Predecessor) $ 29,771 Liabilities incurred 9 Liabilities settled (1,232 ) Accretion expense 2,857 Balance at December 31, 2015 (Predecessor) $ 31,405 Liabilities incurred — Liabilities settled — Accretion expense 2,248 Balance at September 30, 2016 (Predecessor) $ 33,653 Fair value fresh-start adjustment $ (22 ) Balance at September 30, 2016 (Successor) $ 33,631 Liabilities incurred — Liabilities settled — Accretion expense 1,277 Balance at December 31, 2016 (Successor) $ 34,908 Capitalized Interest The Company capitalizes interest on qualifying assets, which include investments in undeveloped oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress. The capitalized interest is determined by multiplying the Company’s interest rate on specific borrowing costs, adjusted to include amortization of bond discount and issuance costs, by the qualifying costs incurred that are excluded from the full cost pool. However, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The capitalized interest amounts are recorded as additions to unevaluated oil and natural gas properties on the consolidated balance sheets. As the costs excluded are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool. Interest of $9.0 million was capitalized for the year ended 2015 and no interest amount was capitalized in 2016. Recent Accounting Pronouncements In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The FASB recently approved a delay which will make the updated guidance effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is not permitted. We are currently evaluating the effect the new standard will have on our financial statements and results of operations. In August 2014, the FASB issued ASU No. 2014-15, 2014-15”). 2014-15 In April 2015, the Financial Accounting Standards Board issued an Accounting Standards Update (“ASU”) that is intended to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2015, and interim periods within those years (early adoption permitted). The Company has included the impact of the adoption of this ASU on its consolidated financial statements and related disclosures and reclassified $12.5 million of deferred bond offering costs to offset debt as of December 31, 2015. In November 2015, the FASB issued authoritative guidance aimed at simplifying the accounting for deferred taxes. Current GAAP requires the deferred taxes for each jurisdiction (or tax-paying jurisdiction-by-jurisdiction In January 2016, the FASB issued authoritative guidance that amends existing requirements on the classification and measurement of financial instruments. The standard principally affects accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective for fiscal periods after December 15, 2017, and interim periods thereafter. Early adoption of certain provisions is permitted. We are currently evaluating the effect the new guidance will have on our financial statements and results of operations. In February 2016, the FASB issued authoritative guidance that supersedes previous lease accounting requirements and requires that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods thereafter. Early adoption is permitted. We are currently evaluating the effect the new guidance will have on our consolidated financial statements and results of operations. In March 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-9, Compensation-Stock Compensation 2016-9). 2016-9 In March 2016, the FASB issued ASU No. 2016-06, Contingent Put and Call Options in Debt Instruments 2016-06). 2016-06 2016-06 In August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-15, 2016-15). 2016-15

Reorganization

Reorganization	12 Months Ended
	Dec. 31, 2016
Reorganizations [Abstract]
Reorganization	NOTE B—REORGANIZATION Bankruptcy Proceedings On June 2, 2016, the Company and certain of its wholly owned subsidiaries (together with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization (the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”), Case No. 16-32760. “debtors-in-possession” The description of the Plan can be found in its entirety by reference to the full text of the Confirmation Order, filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K Termination of Material Definitive Agreements First- and Second-Lien Credit Facilities On the Effective Date, pursuant to the Plan, all amounts outstanding under the First Lien Credit Facility and Second Lien Credit Facility were cancelled and the obligations thereunder were terminated, released and discharged. Lenders under the First Lien Credit Facility and Second Lien Credit Facility received distributions of New Common Stock under the Plan. The Company also entered into the Exit Credit Facility with the lenders of the first-lien credit facility. Indenture On the Effective Date, pursuant to the Plan, the Company’s Senior Notes and the indenture governing the Senior Notes were cancelled and the obligations of the Debtors thereunder were terminated, released and discharged. Holders of the Senior Notes received distributions of New Common Stock under the Plan. Convertible Debentures As of September 30, 2016, pursuant to the Plan, holders of the Company’s Convertible Debentures received payment in full in cash such that the claim of such holders was unimpaired, and the trustees under each series of Convertible Debentures were paid reasonable and documented unpaid fees and expenses incurred on or before the Effective Date. The Convertible Debentures and the indentures governing each series of Convertible Debentures were cancelled and the obligations of the Debtors thereunder were terminated, released and discharged. Other than pursuant to the foregoing, holders of the Convertible Debentures did not receive distributions under the Plan in respect of the Convertible Debentures. Equity Securities and Related Instruments Pursuant to the Plan, on the Effective Date, the previously outstanding shares of the Prepetition Equity Securities, and the obligations of the Debtors thereunder were terminated, released and discharged. Holders of the Prepetition Equity Securities did not receive distributions under the Plan in respect of the Prepetition Equity Securities Entry into a Material Definitive Agreements New First Lien Exit Facility On the Effective Date, pursuant to the Plan, the Company entered into a Credit Agreement by and among the Company, Wilmington Trust, National Association, as Administrative Agent (the “Agent”), and the lenders from time to time party thereto (the “Credit Agreement”). The Credit Agreement provides for a $150 million term loan facility (the “Exit Credit Facility”), consisting of initial senior secured term loans in an aggregate principal amount of $130 million (which, pursuant to the Plan, is deemed to be outstanding without any advancement of funds by the lenders under the Credit Agreement) and additional senior secured term loans (the “delayed draw term loans”) in an aggregate principal amount of up to $20 million, which, subject to the conditions set forth in the Credit Agreement, may be drawn from time to time by the Company. The outstanding term loans, along with accrued and unpaid obligations with respect to such loans, under the Exit Credit Facility are subject to prepayment in respect of (i) proceeds from the issuance or incurrence of debt, excluding those items of debt permitted to be issued or incurred under the Credit Agreement and (ii) casualty proceeds and proceeds received from asset dispositions, subject to limited reinvestment rights and certain excluded asset sales. The Exit Credit Facility is guaranteed by all of the Company’s wholly owned subsidiaries (the “Guarantors”). The Exit Credit Facility is secured by substantially all of the oil and gas assets of the Company and the Guarantors, as well as all of the equity interests in the Guarantors. Certain third-party swap and derivative transactions may be secured pursuant to an intercreditor agreement on a pari passu Proceeds of the delayed draw term loans under the Exit Credit Facility may be used from time to time for lawful corporate purposes, including for working capital needs and to finance corporate and capital expenditures and permitted acquisitions of oil and gas properties and other assets related to the exploration, production, development, processing, gathering, storage and transportation of hydrocarbons. The interest rate on borrowings under the Exit Credit Facility will be equal to the sum of (i) the LIBOR rate (with a minimum LIBOR rate of 1%) plus 9.0% per annum on the aggregate outstanding principal amount of the loans outstanding, which shall be paid in cash, plus (ii) an amount equal to 1.0% per annum on the aggregate outstanding principal amount of the loans outstanding, which shall be paid-in-kind Stockholders Agreement On the Effective Date, pursuant to the Plan, the Company entered into a Stockholders Agreement (the “Stockholders Agreement”) by and among the Company and the stockholders named therein, providing for certain stockholders’ rights and obligations. Among other things, the Stockholders Agreement provides for Board Compensation, Transfer Restrictions, Restrictions on Authority of Board, Information Rights, Registration Rights, Preemptive Rights, Draw-Along and Tag-Along Warrant Agreement On the Effective Date, pursuant to the Plan, the Company entered into the Warrant Agreement, pursuant to which the Company issued the Warrants to Claren Road. The Warrants may be exercised in whole or in part and only during the period (the “Exercise Period”) commencing on the Effective Date and terminating at 5:00 p.m., Eastern time, on October 5, 2021 (the “Warrant Expiration Date”), at an exercise price of $10.50 per share. All Warrants not exercised on or before such time on the Warrant Expiration Date shall become void, and the rights of the holders of such warrants pursuant to the warrants, the Warrant Agreement or the Stockholders Agreement shall cease at such time on the Warrant Expiration Date. The Company may, subject to the Stockholders Agreement, extend the duration of the Warrants by delaying the Warrant Expiration Date. Sales of Equity Securities On the Effective Date, pursuant to the Plan: • 7,899,537 shares of New Common Stock were issued to the lenders under the prepetition first-lien credit facility; • 755,000 shares of New Common Stock were issued to the lenders under the prepetition second-lien credit facility; • 1,284,818 shares of New Common Stock were issued pro rata to the holders of the Senior Notes; and • 60,645 shares of New Common Stock were issued to parties involved in the Marcellus Acquisition. The lenders under the prepetition second-lien credit facility are party to the Warrant Agreement, pursuant to which they received Warrants that are initially exercisable for an aggregate of 526,316 shares of New Common Stock. Additionally, 600,000 shares of New Common Stock were authorized to be issued under the 2016 Equity Compensation Plan. To date, no shares have been issued under this plan.

Fresh-Start Accounting

Fresh-Start Accounting	12 Months Ended
	Dec. 31, 2016
Text Block [Abstract]
Fresh-Start Accounting	NOTE C—FRESH-START ACCOUNTING The Restructuring was accounted for as a purchase and was effective October 5, 2016. However, due to the immateriality of the five day activity period from October 1, 2016 through October 5, 2016, the Restructuring was treated for accounting purposes as effective September 30, 2016. The Restructuring resulted in a new basis of accounting and the Company qualified for and adopted fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the Reorganization Value of the Company’s assets immediately prior to the date of confirmation was less than post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the Predecessor entity received less than 50% of the voting shares of the merging entity. Refer to Note 2, “ Reorganization Presentation of Financial Statements Adopting fresh-start accounting results in a new financial reporting entity with no beginning retained earnings or deficit as of the fresh-start reporting date. Upon the application of fresh-start accounting, the Company allocated the Reorganization Value (the fair value of the Successor Company’s total assets) to its individual assets based on their estimated fair values. The Reorganization Value is intended to represent the approximate amount a willing buyer would value the Company’s assets immediately after the reorganization. Reorganization Value is derived from an estimate of Enterprise Value, or the fair value of the Company’s long-term debt, stockholders’ equity and working capital. The Enterprise Value was derived from a valuation using an asset-based methodology of proved reserve, undeveloped acreage, other long-term asset values and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the fresh-start reporting date of September 30, 2016. The Company’s principal assets are its oil and natural gas properties. For purposes of estimating the fair value of the Company’s proved reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company’s reserves and discounted using a weighted average cost of capital rate of 10%. Weighted average commodity prices utilized in the determination of the fair value of oil and natural properties were $48.24 per barrel of oil, $2.54 per MMBtu of natural gas, after adjustment for transportation fees and regional price differentials. 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 judgement. The following table reconciles the Company’s Enterprise Value to the estimated fair value of the Successor’s common stock as of (in thousands): September 30, 2016 Enterprise Value $ 215,890 Plus: Cash 5,034 Less: Fair value of debt (130,000 ) Fair Value of Successor common stock $ 90,924 The following table reconciles the Company’s Enterprise Value to its Reorganization Value as of September 30, 2016 (in thousands): September 30, 2016 Enterprise Value $ 215,890 Plus: Cash 5,034 Plus: Current liabilities 16,999 Plus: Noncurrent asset retirement obligation 33,632 Reorganization Value of Successor assets $ 271,555 Condensed Consolidated Balance Sheet The following illustrates the effects on the Company’s consolidated balance sheet due to the reorganization and fresh-start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the Company’s assumptions and methods used to determine fair value for its assets and liabilities. Amounts included in the table below are rounded to thousands. As of September 30, 2016 Predecessor Reorganization Fresh-Start Successor ASSETS Current assets Cash and cash equivalents $ 5,034 $ — $ — $ 5,034 Accounts receivable 7,094 — (521 )(6) 6,573 Other current assets 5,498 — (759 )(6) 4,739 Derivative financial instruments 134 — — 134 Total current assets 17,760 — (1,280 ) 16,480 Noncurrent Assets Oil and gas properties 62,659 — 158,276 (6)(7) 220,935 Property and equipment 1,176 — 29,931 (6)(7) 31,107 Other assets 3,026 — 7 (6) 3,033 Total other assets 66,861 — 188,214 255,075 $ 84,621 $ — $ 186,934 $ 271,555 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable and accrued expenses $ 15,116 — $ 1,883 (6) 16,999 Total current liabilities 15,116 — 1,883 16,999 Noncurrent liabilities Other long-term liabilities 33,654 — (22 )(8) 33,632 Long-term debt — 130,000 (1) 130,000 Liabilities subject to compromise 509,306 (509,306 )(2) — — Total liabilities 558,076 (379,306 ) 1,861 180,631 Commitments and contingencies — — — — Stockholders’ Equity (Deficit) Predecessor preferred stock 128 (128 )(3) — — Predecessor common stock 9 (9 )(3) — — Predecessor additional paid-in 517,468 (517,468 )(3) — Successor common stock — 100 (4) — 100 Successor additional paid-in — 90,824 (4) — 90,824 Accumulated deficit (991,060 ) 805,987 (5) 185,073 (9) — Total stockholders’ equity (deficit) (473,455 ) 379,306 185,073 90,924 $ 84,621 $ — $ 186,934 $ 271,555 Reorganization adjustments 1) Reflects issuance of $130 million of debt from the Exit Credit Facility 2) Liabilities subject to compromise were as follows (in thousands): Accounts payable and accrued expenses $ 38,105 First Lien Credit Facility 230,532 Second Lien Credit Facility 71,617 Senior Notes 161,635 Convertible Debentures (83 ) Other long-term liabilities 7,500 Gain on settlement of liabilities subject to compromise $ 509,306 3) Reflects the cancellation of Predecessor equity as follows (in thousands): Predecessor preferred stock $ 128 Predecessor common stock 9 Predecessor additional paid-in-capital 517,468 Cancellation of Predecessor Company equity $ 517,605 4) Reflects the issuance of Successor equity as follows (in thousands): Successor common stock $ 100 Successor additional paid-in-capital 90,824 Issuance of Successor equity $ 90,924 5) Reflects the cumulative effect of the reorganization adjustments of $806 million. Fresh-start accounting adjustments 6) In estimating the fair value of its oil and natural gas and other properties, the Company used a combination of the income and market approaches. For purposes of estimating the fair value of the Company’s proved reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10% for proved reserves. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $48.24 per barrel of oil and $2.54 per MMBtu of natural gas, after adjustment for transportation fees and regional price differentials. Amount reflects the reclassification of the Company’s gas pipeline cost from oil and gas properties into property and equipment. Other line item amounts reflects changes attributable to oil and gas operations. 7) For purposes of estimating the fair value of its gas pipeline, an income approach was used that estimated future cash flows associated with the assets over the remaining useful lives. The valuation included such inputs as estimated future production, gathering and compression revenues and operating expenses that were discounted at a weighted average cost of capital rate of 9.5%. For purposes of estimating the fair value of the land, an appraisal was performed by an independent third party appraisal firm. 8) Reflects the adjustment of asset retirement obligations to fair value using estimated plugging and abandonment costs as of September 30, 2016. 9) Reflects the cumulative effect of fresh-start accounting adjustments.

Debt

Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Debt	NOTE D— DEBT Current maturing long-term debt, net of debt issuance costs and discounts, consisted of the following: Successor Predecessor December 31, December 31, (in thousands) Exit Credit Facility $ 140,320 $ — First Lien Credit Facility — 229,685 Second Lien Credit Facility — 72,960 Convertible Debentures — 1,540 Senior Notes — 159,885 140,320 464,070 Less current portion — (464,070 ) Long-term portion $ 140,320 $ — Exit Credit Facility On the Effective Date, pursuant to the Plan, the Company entered into a Credit Agreement by and among the Company, Wilmington Trust, National Association, as Administrative Agent (the “Agent”), and the lenders (related party) from time to time party thereto (the “Credit Agreement”). The Credit Agreement provides for a $150 million term loan facility (the “Exit Credit Facility”), consisting of initial senior secured term loans in an aggregate principal amount of $130 million (which, pursuant to the Plan, is deemed to be outstanding without any advancement of funds by the lenders under the Credit Agreement) and additional senior secured term loans (the “delayed draw term loans”) in an aggregate principal amount of up to $20 million, which, subject to the conditions set forth in the Credit Agreement, may be drawn from time to time by the Company. The outstanding term loans, along with accrued and unpaid obligations with respect to such loans, under the Exit Credit Facility are subject to prepayment in respect of (i) proceeds from the issuance or incurrence of debt, excluding those items of debt permitted to be issued or incurred under the Credit Agreement and (ii) casualty proceeds and proceeds received from asset dispositions, subject to limited reinvestment rights and certain excluded asset sales. The Exit Credit Facility is guaranteed by all of the Company’s wholly owned subsidiaries (the “Guarantors”). The Exit Credit Facility is secured by substantially all of the oil and gas assets of the Company and the Guarantors, as well as all of the equity interests in the Guarantors. Certain third-party swap and derivative transactions may be secured pursuant to an intercreditor agreement on a pari passu Proceeds of the delayed draw term loans under the Exit Credit Facility may be used from time to time for lawful corporate purposes, including for working capital needs and to finance corporate and capital expenditures and permitted acquisitions of oil and gas properties and other assets related to the exploration, production, development, processing, gathering, storage and transportation of hydrocarbons. The interest rate on borrowings under the Exit Credit Facility will be equal to the sum of (i) the LIBOR rate (with a minimum LIBOR rate of 1%) plus 9.0% per annum on the aggregate outstanding principal amount of the loans outstanding, which shall be paid in cash, plus (ii) an amount equal to 1.0% per annum on the aggregate outstanding principal amount of the loans outstanding, which shall be paid-in-kind At any time on or prior to October 5, 2017, if the Company repays all or any part of the principal balance of any loan under the Exit Credit Facility, or there is an acceleration of the Company’s obligations under the Exit Credit Facility following the occurrence and continuation of an event of default under the Credit Agreement and notice from the Agent of such acceleration or there occurs a substitution of any lender pursuant to the terms of the Credit Agreement, the Company will pay the Agent, for the benefit of all of the lenders (or in the case of substitution, the substituted lender), in addition to the amount so repaid, due or assigned and any accrued and unpaid interest thereon, a make-whole premium equal to the present value at such time, computed on such repayment or assignment date using a discount rate equal to the treasury rate plus 50 basis points of the amount of (i) 4% the principal amount of such loan so repaid, due or assigned and (ii) the interest that would have accrued on the principal balance of the applicable loan being repaid or so due or assigned from the date of repayment, acceleration or assignment through October 5, 2017 if such loan remained outstanding and were repaid one day after such date. After October 5, 2017, if the Company repays all or any part of the principal balance of any loan under the Exit Credit Facility, or if there is an acceleration of the Company’s obligations under the Exit Credit Facility following the occurrence and continuation of an event of default under the Credit Agreement and notice from the Agent of such acceleration or there occurs a substitution of any lender pursuant to the terms of the Credit Agreement, the Company will pay the Agent, for the benefit of all of the lenders (or in the case of substitution, the substituted lender), in addition to the amount so repaid, due or assigned and any accrued and unpaid interest thereon, a repayment premium equal to the product of (i) the principal amount of the loans so repaid, due or assigned multiplied by (ii) the applicable percentage set forth below: Year Percentage October 6, 2017 through October 5, 2018 4 % October 6, 2018 through October 5, 2019 2 % October 6, 2019 and thereafter 0 % The Company is subject to affirmative and negative covenants under the Credit Agreement, including, but not limited to, financial covenants with respect to Consolidated Total Leverage Ratio (as such term is defined in the Credit Agreement) and minimum liquidity. The Consolidated Total Leverage Ratio covenant requires that, commencing on June 30, 2017, the Consolidated Total Leverage Ratio for any period of four consecutive fiscal quarters shall not be greater than, determined as of the last day of each fiscal quarter, (a) during the period following June 30, 2017 until December 31, 2017, 5.5 to 1.0, (b) during the period following March 31, 2018 until December 31 , 2018, 5.0 to 1 .0 and (c) during the period following March 31, 2019 until the Maturity Date, 4.5 to 1.0. The minimum liquidity covenant requires that the Company and its Subsidiaries at all times maintain the aggregate amount of undrawn availability under the delayed draw term loans, unrestricted cash and cash equivalents of at least $5 million. The Exit Credit Facility is subject to other usual and customary conditions, representations, warranties and covenants including, but not limited to, restrictions on additional indebtedness, liens, contingent obligations, payments, investments, mergers, asset dispositions, speculative commodity transactions, transactions with affiliates and other matters. The Exit Credit Facility is subject to customary events of default. If an event of default occurs and is continuing, the Agent may, or at the request of certain required lenders shall, accelerate amounts due under the Exit Credit Facility (except for a bankruptcy event of default, in which case such amounts will automatically become due and payable). The outstanding balance of the Exit Credit Facility at December 31, 2016 amounted to $140.3 million which includes $0.3 million of paid-in-kind First Lien Credit Facility and Senior Notes Exchange On May 22, 2015, Warren Resources entered into a first lien credit agreement by and among the Company, Wilmington Trust, National Association, as Administrative Agent, and the lenders from time to time party thereto, that provides for a five-year, $250 million term loan facility (as amended, the “First Lien Credit Facility”) which matures on May 22, 2020. At the closing of the First Lien Credit Facility, certain of the first lien lenders extended credit in the form of new term loans in the amount of $172.5 million and in the form of commitments for delayed draw term loans for up to an additional $30 million, subject to certain incurrence tests. Approximately $47 million in additional term loans were issued under the First Lien Credit Facility at closing in exchange for $69.59 million in face value of the 9.000% Senior Notes due 2022, as described further under “9.000% Senior Notes due 2022” below. The conditions applicable to further draw downs under the First Lien Credit Facility were modified as part of the First Amendment to the First Lien Credit Facility that was entered into on October 22, 2015. The First Lien Credit Facility was guaranteed by Warren California, Warren E&P and Warren Marcellus, which are three of the Company’s wholly-owned subsidiaries, and was collateralized by substantially all of Warren’s assets, including the equity interests of the guarantors. Warren used the proceeds drawn at the closing of the First Lien Credit Facility to repay the balance on its former credit facility, and has been released from all legal obligations on such former facility. The Company accounted for this Exchange transaction in accordance with ASC 470 and ASC 405 and as a result recognized a gain on the retirement of debt in the amount of $14.4 million during 2015. The First Lien Credit Facility is subject to prepayment in respect of asset sales, subject to limited reinvestment rights and certain excluded asset sales. The First Lien Credit Facility also includes certain covenants, including a maintenance covenant requiring the Company to maintain a minimum consolidated first lien leverage ratio. The terms of the maintenance covenant were modified as part of the First Amendment to the First Lien Credit Facility that was entered into on October 22, 2015. The First Lien Credit Facility is subject to other usual and customary conditions, representations, and warranties, including restrictions on certain additional indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of our common stock, speculative commodity transactions, transactions with affiliates and other matters. The First Lien Credit Facility is also subject to customary events of default. If an event of default occurs and is continuing, the Agent may, or at the request of certain required lenders shall, accelerate amounts due under the First Lien Credit Facility (except for a bankruptcy event of default, in which case such amounts will automatically, by their terms, become due and payable). The annual interest rate on borrowings under the First Lien Credit Facility was 8.5% plus LIBOR for the applicable LIBOR period (with a minimum LIBOR rate of 1%) and was payable quarterly in arrears on the next to last business day of each March, June, September and December. At September 30, 2016 the interest rate was 9.5%. On November 9, 2015, $15 million of additional borrowings were drawn depleting the total available under the facility. On the Effective Date, pursuant to the Plan, all amounts outstanding under the First Lien Credit Facility were cancelled and the obligation thereunder terminated, released and discharged. Lenders under the First Lien Credit Facility received distributions of the Company’s common stock, par value $0.01 (the “New Common Stock”) under the Plan and entered into a new term loan facility with the Company (the Exit Credit Facility as discussed below). Second Lien Credit Facility and Senior Note Exchange On October 22, 2015, the Company entered into a second lien credit facility (the “Second Lien Credit Facility”) by and among the Company, Cortland Capital Market Services, LLC, as Administrative Agent, and the lenders from time to time party thereto. The Second Lien Credit Facility provided for a five-year, approximately $51.0 million term loan facility that matured on November 1, 2020. At closing, certain of the lenders exchanged approximately $63.1 million in face value of previously-issued Senior Notes held by them, plus accrued interest, for (i) approximately $40.1 million of second lien term loans under the Second Lien Credit Facility, and (ii) four million (4,000,000) shares of the Company’s Common Stock and, in addition, extended credit in the form of new second lien term loans in the amount of approximately $11.0 million. The annual interest rate on borrowings under the Second Lien Credit Facility was 12%, with interest payable semi-annually in arrears on each April 20 and October 20. On the first three semi-annual interest payment dates, beginning with April 20, 2016, the Company could elect to pay up to all of such interest (6% per semi-annual period) by capitalizing accrued and unpaid interest and adding the same to the principal amount of the second lien loans then outstanding. For the subsequent three semi-annual interest payment dates, beginning with October 20, 2017 and ending October 20, 2018, the Company could elect to pay up to one quarter of such interest (1.5% per semi-annual period) by capitalizing accrued and unpaid interest and adding the same to the principal amount of the Second Lien Loans then outstanding. The transaction was accounted for as a troubled debt restructuring in accordance with ASC 470, whereby no gain on the retirement of debt was recognized and a premium on the issuance equal to the amount of debt retired could be amortized over the life of the instrument. The total outstanding balance at September 30, 2016 amounted to $71.6 million which was net of debt issuance costs of $1.6 million. On the Effective Date, pursuant to the Plan, all amounts outstanding under the Second Lien Credit Facility were cancelled and the obligations thereunder terminated, released and discharged. Lenders under the Second Lien Credit Facility received distributions of New Common Stock under the Plan. Additionally, the lenders under the Second Lien Credit Facility were party to the Plan Warrant Agreement, dated as of October 5, 2016, by and among the Company, and Claren Road Credit Master Fund, Ltd. and Claren Road Credit Opportunities Master Fund, Ltd. (collectively, “Claren Road”) and the other registered holders from time to time party thereto, pursuant to which they received warrants exercisable, in accordance with the terms thereof, for an aggregate of 526,316 shares of New Common Stock (the “Warrants”). 9.000% Senior Notes due 2022 On August 11, 2014, we acquired essentially all of the Marcellus Assets (the “Marcellus Assets”) of Citrus Energy Corporation (“Citrus”) and two other working interest owners (the “Marcellus Asset Acquisition”). To finance the Marcellus Asset Acquisition, on August 11, 2014, the Company issued 9.000% senior notes in a private offering at a price equal to 98.617% for a total of $300 million due to mature on August 1, 2022 (the “Unregistered Senior Notes”). Interest was payable on the Unregistered Senior Notes semi-annually in arrears at a rate of 9.000% per annum on each February 1 and August 1. In connection with the First Lien Credit Facility entered into on May 22, 2015, the Company exchanged $69.59 million in face value of the Unregistered Senior Notes previously held by the lenders under the First Lien Credit Facility for approximately $45.23 million of first lien term loans plus accrued unpaid interest of $1.9 million rolled into the First Lien Term Loans as additional borrowing. On July 27, 2015, substantially all of the outstanding Unregistered Senior Notes were exchanged for an equal principal amount of registered 9.000% Senior Notes due 2022 pursuant to a registration statement on Form S-4 In connection with the Second Lien Credit Facility entered into on October 22, 2015, the Company exchanged $63.1 million in face value of Registered Senior Notes previously held by the lenders under the Second Lien Credit Facility for approximately $40.1 million of second lien term loans. We could redeem, at specified redemption prices, some or all of the Senior Notes at any time on or after August 1, 2017. We could also redeem up to 35% of the Senior Notes using the proceeds of certain equity offerings completed before August 1, 2017. If we should sell certain of our assets or experience certain kinds of changes in control, we could be required to offer to purchase the Senior Notes from the holders. The Senior Notes were fully, unconditionally and jointly and severally guaranteed on a senior unsecured basis by certain of our existing subsidiaries and were fully, unconditionally and jointly and severally guaranteed on a senior unsecured basis by our future domestic subsidiaries, subject to certain exceptions. Warren is a holding company with no independent assets or operations. Any subsidiaries of the Company other than the subsidiary guarantors are minor. There were no significant restrictions on the Company’s ability, or the ability of any subsidiary guarantor, to obtain funds from its subsidiaries through dividends, loans, advances or otherwise. The total outstanding balance at September 30, 2016 amounted to $161.6 million which was net of debt issuance costs of $3.9 million. On the Effective Date, pursuant to the Plan, the Company’s 9% Senior Notes due 2022 and the indenture governing the Senior Notes were cancelled and the obligations of the Debtors thereunder were terminated, released and discharged. Holders of the Senior Notes received distributions of New Common Stock under the Plan. Convertible Debentures Convertible debentures, net of debt issuance costs of $96,000, consisted of the following (in thousands): Successor Predecessor Maturity date December 31, 2016 December 31, 2015 Secured Convertible 12% Debentures December 31, 2020 $ — $ 783 Secured Convertible 12% Debentures December 31, 2022 — 757 $ — $ 1,540 As of September 30, 2016, pursuant to the Plan, holders of the Company’s 12% Secured Convertible Bonds due December 31, 2020 and the 12% Secured Convertible Bonds due December 31, 2022 (together, the “Convertible Debentures”) received payment in full in cash such that the claim of such holders was unimpaired, and the trustees under each series of Convertible Debentures were paid reasonable and documented unpaid fees and expenses incurred on or before the Effective Date. On the Effective Date, the Convertible Debentures and the indentures governing each series of Convertible Debentures were cancelled and the obligations of the Debtors thereunder were terminated, released and discharged. Other than pursuant to the foregoing, holders of the Convertible Debentures did not receive distributions under the Plan in respect of the Convertible Debentures.

Investments

Investments	12 Months Ended
	Dec. 31, 2016
Investments, Debt and Equity Securities [Abstract]
Investments	NOTE E—INVESTMENTS The amortized cost, unrealized gains and estimated fair values of the Company’s available-for-sale Successor Predecessor December 31, December 31, (in thousands) U.S. Treasury Bonds, stripped of interest, maturing 2020 and 2022, aggregate par value of $1.6 million Amortized cost $ — $ 1,138 Gross unrealized gains — 310 Estimated fair value $ — $ 1,448 The unrealized gains for each year results from the disposition of such securities due to the release of the Company’s obligation related to securing its commitment under debentures. The basis of the securities sold is determined using the specific identification method.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Stockholders' Equity	NOTE F—STOCKHOLDERS’ EQUITY Prepetition Equity Securities Pursuant to the Plan, on the Effective Date, the previously outstanding shares of the Prepetition Equity Securities were terminated, released and discharged. Holders of the Prepetition Equity Securities did not receive distributions under the Plan in respect of the Prepetition Equity Securities. Stockholders Agreement On the Effective Date, pursuant to the Plan, the Company entered into a Stockholders Agreement (the “Stockholders Tag-Along New Common Stock On the Effective Date, pursuant to the Plan: • 7,899,537 shares of New Common Stock were issued to the lenders under the prepetition first-lien credit facility; • 755,000 shares of New Common Stock were issued to the lenders under the prepetition second-lien credit facility; • 1,284,818 shares of New Common Stock were issued pro rata to the holders of the Senior Notes; and • 60,645 shares of New Common Stock were issued to parties involved in the Marcellus Acquisition. The lenders under the prepetition second-lien credit facility are party to the Warrant Agreement, pursuant to which they received Warrants that are initially exercisable for an aggregate of 526,316 shares of New Common Stock. Additionally, 600,000 shares of New Common Stock were authorized to be issued under the 2016 Equity Compensation Plan. To date, no shares have been issued under this plan. Warrant Agreement On the Effective Date, pursuant to the Plan, the Company entered into the Warrant Agreement, pursuant to which the Company issued the Warrants to Claren Road. The Warrants may be exercised in whole or in part and only during the period (the “Exercise Period”) commencing on the Effective Date and terminating at 5:00 p.m., Eastern time, on October 5, 2021 (the “Warrant Expiration Date”), at an exercise price of $10.50 per share. All Warrants not exercised on or before such time on the Warrant Expiration Date shall become void, and the rights of the holders of such warrants pursuant to the warrants, the Warrant Agreement or the Stockholders Agreement shall cease at such time on the Warrant Expiration Date. The Company may, subject to the Stockholders Agreement, extend the duration of the Warrants by delaying the Warrant Expiration Date. Preferred Stock The Company’s preferred stock, pays an 8% cumulative dividend which is treated as a deduction of additional paid in capital due to insufficient retained earnings. Holders of the stock are not entitled to vote except as defined by the agreement or as provided by applicable law. The preferred stock may be voluntarily converted, at the election of the holder, into common stock of the Company based on a conversion rate of one share of preferred stock for 0.50 shares of common stock. The accrual of the dividend is deducted from earnings in the calculation of earnings attributable to common stockholders. Additionally, holders of the preferred stock can elect to require the Company to redeem their preferred stock at a redemption price equal to the liquidation value of $12.00 per share, plus accrued but unpaid dividends, if any, (“Redemption Price”). Upon the receipt of a redemption election, the Company, at its option, shall either: (1) pay the holder cash in the amount equal to the Redemption Price or (2) issue to the holder shares of common stock in an amount equal to 125% of the redemption price and any accrued and unpaid dividends, based on the weighted average closing “bid” price of the Company’s common stock for the thirty trading days immediately preceding the date of the written redemption election by the holder up to a maximum of 1.5 shares of common stock for each one share of preferred stock redeemed. The Company has accreted the carrying value of its preferred stock to its redemption price using the effective interest method with changes recorded to additional paid in capital. The accretion of preferred stock results in a reduction of earnings applicable to common stockholders. Notwithstanding the forgoing, if the closing “bid” price of the Company’s publicly traded common stock as reported by the NASDAQ stock market, or any exchange on which the shares of common stock are traded, exceeds 133% of the conversion price then in effect for the convertible preferred shares for at least 10 days during any 30-day Pursuant to the Plan, on the Effective Date, all outstanding shares of Preferred Stock were terminated, released and discharged. Holders of Preferred Stock did not receive distributions under the Plan. Securities Authorized for Issuance Under Compensation Plans The Company utilizes restricted stock and stock options to compensate employees, officers, directors and consultants. Total stock-based compensation expense related to stock options and restrictive stock awards amounted to $0.6 million for the nine months ended September 30, 2016 (Predecessor) and $2.2 million for the year ended December 31, 2015 (Predecessor). No such expenses were incurred for the three months ended December 31, 2016 (Successor). A summary of the Company’s stock options is as follows: Incentive Weighted Options outstanding at December 31, 2014 (Predecessor) 1,987,159 $ 4.37 Issued 2,730,400 $ 0.88 Exercised — — Forfeited or expired (1,123,970 ) $ 2.64 Outstanding at December 31, 2015 (Predecessor) 3,593,589 $ 2.26 Issued — — Exercised — — Forfeited or expired (1,085,882 ) $ 2.44 Cancelled (2,507,707 ) $ 2.21 Outstanding at September 30, 2016 (Predecessor) — $ — A summary of the Company’s restricted stock is as follows: Shares Weighted Outstanding at December 31, 2014 (Predecessor) 689,370 $ 2.87 Granted 1,669,655 0.56 Vested (697,630 ) 1.79 Forfeited (383,927 ) 2.06 Outstanding at December 31, 2015 (Predecessor) 1,277,468 $ 0.69 Granted — — Vested (83,884 ) 3.70 Forfeited (21,097 ) 3.70 Cancelled (1,172,487 ) 0.41 Outstanding at September 30, 2016 (Predecessor) — $ —

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	NOTE G—FAIR VALUE OF FINANCIAL INSTRUMENTS The estimated fair values of financial instruments recognized in the Consolidated Balance Sheets or disclosed within these Notes to Consolidated Financial Statements have been determined using available market information, information from unrelated third party financial institutions and appropriate valuation methodologies, primarily discounted projected cash flows. However, considerable judgment is required when interpreting market information and other data to develop estimates of fair value. Short -term Assets and Liabilities. U.S. Treasury Bonds—Available-For-Sale Collateral Security Agreement Account (included in other non-current Fixed Rate Debentures. Other Long-Term Liabilities. First Lien Credit Facility. Second Lien Credit Facility. Derivative Financial Instruments. 9.000% Senior Notes. Contingent Earn-Out. Successor Predecessor 2016 2015 Fair Carrying Fair Carrying (in thousands) Financial assets: Collateral Security account $ 2,952 $ 2,952 $ 2,812 $ 2,812 U.S. Treasury Bonds — — 1,448 1,636 Derivative Assets 587 5,87 11,081 11,081 Financial liabilities: Exit Credit Facility 140,320 140,320 — — Derivative Liability 10,633 10,633 — — Fixed rate debentures — — 3,057 1,636 First Lien Credit Facility — — 234,665 234,665 Second Lien Credit Facility — — 74,912 74,912 Senior Notes — — 25,090 165,368 FAIR VALUE MEASUREMENTS: Fair value as defined by authoritative literature is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories: Level 1: Level 2: non-exchange over-the-counter Level 3: The valuation assumptions utilized to measure the fair value of the Company’s commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs). The fair value of our commodity derivatives were determined through a discounted cash flow model, using terms of the derivative instruments, market prices for the periods covered by the derivatives, and the credit adjusted risk-free interest rates. The following table presents for each hierarchy level our assets and liabilities, including both current and non-current December 31, 2016 Level 1 Level 2 Level 3 Total (in thousands) Current Assets Derivative Financial Instruments $ — $ 587 $ — $ 587 Current Liabilities Derivatives Financial Instruments $ — $ 6,313 $ — $ 6,313 Noncurrent Liabilities Derivative Financial Instruments $ — $ 4,320 $ — $ 4,320 December 31, 2015 Level 1 Level 2 Level 3 Total (in thousands) Current Assets U.S. Treasury Bonds—Available-For-Sale $ 1,448 $ — $ — $ 1,448 Derivative Financial Instruments $ — $ 11,081 $ — $ 11,081

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	NOTE H—DERIVATIVE FINANCIAL INSTRUMENTS To minimize the effect of a downturn in oil and gas prices and protect our profitability and the economics of our development plans, we enter into crude oil and natural gas hedge contracts. The terms of contracts depend on various factors, including management’s view of future crude oil and natural gas prices. This price hedging program is designed to moderate the effects of a crude oil and natural gas price downturn while allowing us to participate in some commodity price increases. Management regularly monitors the crude oil and natural gas markets and our financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging and/or basis adjustments or other price protection is appropriate. Currently, our more commonly used derivatives are in the form of swaps. However, we may use a variety of derivative instruments in the future to hedge. The Company has not designated these derivatives as hedges. The following table summarizes the open financial derivative positions as of December 31, 2016 related to oil and gas production. The Company will receive prices as noted in the table below and will pay a counterparty market price based on the NYMEX (for natural gas production) or WTI (for oil production) index price, settled monthly. Product Type Contract Period Volume Price per BRENT Oil Collar 01/01/17 - 12/31/17 250 Bbl/d $ 42.00 – 57.25 BRENT Oil Collar 01/01/17 - 12/31/18 250 Bbl/d $ 42.00 – 60.00 BRENT Oil Collar 01/01/17 - 12/31/18 250 Bbl/d $ 42.00 – 60.50 BRENT Oil Collar 01/01/17 - 12/31/18 250 Bbl/d $ 43.00 – 61.50 BRENT Oil Collar 01/01/17 - 12/31/18 250 Bbl/d $ 42.00 – 59.60 BRENT Oil Swap 01/01/17 - 12/31/17 100 Bbl/d $ 55.30 BRENT Oil Swap 01/01/17 - 12/31/17 250 Bbl/d $ 56.25 CIG Basis Swap 01/01/17 - 03/31/19 7,500 MMBtu/d $ (0.36 ) DTI Basis Swap 01/01/17 - 03/31/17 10,000 MMBtu/d $ (0.86 ) DTI Basis Swap 01/01/17 - 03/31/19 10,000 MMBtu/d $ (0.98 ) DTI Basis Swap 01/01/17 - 03/31/19 10,000 MMBtu/d $ (1.04 ) NYMEX Gas Collar 01/01/17 - 12/31/17 15,000 MMBtu/d $ 2.80 – 3.10 NYMEX Gas Collar 01/01/17 - 12/31/18 10,000 MMBtu/d $ 2.80 – 3.15 NYMEX Gas Collar 01/01/18 - 12/31/18 10,000 MMBtu/d $ 2.80 – 3.30 NYMEX Gas Swap 01/01/17 - 03/31/18 10,000 MMBtu/d $ 3.56 NYMEX Gas Swap 01/01/17 - 07/31/17 5,000 MMBtu/d $ 3.55 The tables below summarize the amount of gains (losses) recognized in income from derivative instruments not designated as hedging instruments under authoritative guidance (in thousands). Successor Predecessor Predecessor Derivatives not designated as Hedging Instrument under authoritative guidance For the three For the nine For the (in thousands) Realized cash settlements on hedges $ (693 ) $ 11,741 $ 13,007 Unrealized gain (loss) on hedges (10,181 ) (10,947 ) 7,076 Total gain (loss) $ (10,874 ) $ 794 $ 20,083 The table below reflects the line item in our Consolidated Balance Sheet where the fair value of our net derivatives, are included. December 31, 2016 Balance Fair Value (in thousands) Commodity—Natural Gas Current assets $ 587 Total derivatives not designated as hedging instruments $ 587 (in thousands) Commodity—Oil Current liabilities $ 1,562 Commodity—Natural Gas Current liabilities 4,751 Total derivatives not designated as hedging instruments $ 6,313 (in thousands) Commodity—Oil Other long-term liabilities $ 1,615 Commodity—Natural Gas Other long-term liabilities 2,705 Total derivatives not designated as hedging instruments $ 4,320 December 31, 2015 Balance Fair Value (in thousands) Commodity—Natural Gas Current assets $ 7,816 Commodity—Oil Current assets 3,265 Total derivatives not designated as hedging instruments $ 11,081 Derivatives Credit risk The Company does not require collateral or other security from counterparties to support derivative instruments. However, the agreements with those counterparties typically contain netting provisions such that if a default occurs, the non-defaulting The Company’s derivative agreements contain provisions that require cross defaults and acceleration of those instruments to any material debt. If the Company were to default on any of its material debt agreements, it would be a violation of these provisions, and the counterparties to the derivative instruments could request immediate payment on derivative instruments that are in a net liability position at that time.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	NOTE I—INCOME TAXES The Company and its subsidiaries file a consolidated federal income tax return. The Company's effective income tax rate differed from the federal statutory rate as follows: December 31, September 30, 2015 (in thousands) Income Taxes at Federal Statutory Rate $ (56,818 ) $ (51,112 ) $ (210,781 ) Change in Valuation Allowance 36,912 60,625 251,045 Nondeductible Expenses 4 (788 ) (2,523 ) State Income Taxes Net of Federal Benefit (6,618 ) (5,953 ) (37,197 ) Section 382 NOL Reduction 26,520 — — Other — (2,648 ) (527 ) — 124 17 December 31, September 30, 2015 (in thousands) Deferred Tax Assets Relating To: Net Operating Loss Carryforward 159,636 176,741 130,816 Oil and Gas Properties and Tangible Equipment 195,957 219,440 228,324 Stock Option Expense — 4,564 4,207 Unrealized Loss on Derivatives 4,036 — — Other 1,147 1,105 719 360,776 401,850 364,066 Less Valuation Allowance 360,553 401,800 359,510 Total Deferred Tax Asset 223 50 4,556 Deferred Tax Liabilities Relating To: Unrealized Gain on Derivatives (223 ) (50 ) (4,432 ) Net Unrealized Gain on Investments — — (124 ) Total Deferred Tax Liability (223 ) (50 ) (4,556 ) Net Deferred Tax Asset (Liability) — — — A valuation allowance for deferred tax assets is required when it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of this deferred tax asset depends on the Company’s ability to generate sufficient taxable income in the future. Management believes it is more-likely-than-not that the net deferred tax asset will not be realized by future operating results. The valuation allowance decreased by approximately $41 million for the 3 month period ended December 31, 2016 and increased by approximately $42 million for the 9 month period ended September 30, 2016. At December 31, 2016, the Company had net operating loss carryforwards for federal income tax purposes of approximately $421 million, which will expire in years 2019 through 2035. Tax years beginning in 2013 are subject to examination by taxing authorities, although net operating loss and credit carryforwards from all years are subject to examination and adjustments for at least three years following the year in which the attributes are used. The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. Only tax positions that meet the more-likely-than-not recognition threshold are recorded.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE J—COMMITMENTS AND CONTINGENCIES General Commitments The Company has entered into various commitments and operating agreements related to development and production of certain oil and gas properties. It is management’s belief that such commitments, as stated below, will be met without significant adverse impact to the Company’s financial position or results of operations. Leases The Company leases corporate office space in Denver, Colorado on a month to month status. The Company leases oil and gas administrative offices located in Dallas, Texas which expires in April, 2022. The Company leases field office space in Rawlins, Wyoming which is on a month to month status. The Company leases office space in Long Beach, California which expires in November 2018. The Company leases office space in Tunkhannock, Pennsylvania which expires in August 2019. The Company leases office space in Casper, Wyoming on a month to month status. Future minimum annual rental payments, which are subject to escalation and include utility charges as of December 31, 2016, are as follows: (in thousands) Year ending December 31: 2017 $ 349 2018 438 2019 384 2020 393 2021 401 Thereafter 134 $ 2,099 Rent expense under these leases was approximately $0.1 million for the three months ended December 31, 2016 (Successor), $0.8 million for the nine months ended September 30, 2016 (Predecessor) and $1.1 million for the year ended December 31, 2015 (Predecessor). Transportation Fee Contracts assumed related to the Marcellus assets stipulated that the Company pay a fixed monthly amount of $1,241,000 for transportation of gas through the interstate pipeline, up to 120,000 dekatherms per day for a term ending in July 2022 (67 months remain on the contract). If the Company exceeds 120,000 dekatherms per day, the agreement states that a monthly fee of $0.34 per dekatherm over the contractually stipulated amount should be paid. Following the emergence from bankruptcy in October 2016, the commitment was reduced to 90,000 dekatherms per day for the next 36 months of the contract. Warren accounts for the aforementioned gathering and transportation fees on the Consolidated Statements of Operations within the lease operating expenses and taxes line item, as incurred. No overage fees have been included in the calculation of transportation fees. Long-term debt and interest obligations See Note D – Debt for additional information. Additionally, the outstanding principal balance of $140.3 million is due May 2022. Asset Retirement Obligations See Note A – Organization and Accounting Policies for additional information. Bankruptcy Claims Associated with the Company’s filing and emergence from the Chapter II Cases, creditors have filed claims against the Company. The claims reconciliation process is ongoing and the estimated liability has not been finalized. The process includes review of the underlying claim filed against the Company and a reconciliation against the debtor’s books and records. The Company has estimated the liabilities associated with these claims at $1.5 million. This liability is included as a current liability in the consolidated financial statements at December 31, 2016.

Oil and Gas Information

Oil and Gas Information	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Oil and Gas Information	NOTE K—OIL AND GAS INFORMATION Costs related to the oil and gas activities of the Company were incurred as follows for the years ended December 31: Successor Predecessor 2016 2015 (in thousands) Property acquisition—unproved $ — $ — Property acquisition—proved — 18,626 Exploration costs — 3 Development costs 5,052 17,359 $ 5,052 $ 35,988 Asset retirement cost included in oil and gas property costs increased by approximately $0.6 million in 2016 and $0.1 million in 2015. The Company had the following aggregate capitalized costs relating to the Company’s oil and gas activities at December 31: Successor Predecessor 2016 2015 (in thousands) Unproved oil and gas properties $ — $ 14,658 Proved oil and gas properties 222,655 1,125,297 222,655 1,139,955 Less accumulated depreciation, depletion and impairment expense (154,292 ) (977,270 ) $ 68,363 $ 162,685 The following table sets forth the Company’s results of operations from oil and natural gas producing activities: Successor Predecessor Predecessor Three months Nine months Year ended 2016 2016 2015 (in thousands) Revenues $ 16,862 $ 39,712 $ 83,734 Production costs (10,678 ) (32,611 ) (49,557 ) Accretion of asset retirement obligation (1,277 ) (2,248 ) (2,857 ) Impairment (145,117 ) (87,094 ) (562,151 ) Depreciation, depletion, amortization (9,175 ) (15,128 ) (59,729 ) Loss from oil and gas producing activities $ (149,385 ) $ (97,369 ) $ (590,560 ) In the presentation above, no deduction has been made for indirect costs such as corporate overhead or interest expense. No income taxes are reflected above due to the Company’s tax loss carryforwards. The following is a summary of Warren’s oil and gas properties not subject to amortization: Successor Predecessor December 31, December 31, (in thousands) Acquisition costs $ — $ — Exploration costs — — Development costs(1) — 365 Total oil and gas properties not subject to amortization $ — $ 365 (1) The Company’s development costs primarily reflect investment in well cellars and facilities in its Wilmington oil field to facilitate the development of future oil wells. These costs will be allocated to future wells drilled, the majority of these wells are expected to be drilling during the next five to eight years.

Oil and Gas Reserve Data (Unaud

Oil and Gas Reserve Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
Text Block [Abstract]
Oil and Gas Reserve Data (Unaudited)	NOTE L—OIL AND GAS RESERVE DATA (UNAUDITED) The following estimates of proved reserve quantities and related standardized measure of discounted future net cash flows are estimates only, and do not purport to reflect realizable values or fair market values of the Company’s reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company’s reserves are located in the United States. Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. The standardized measure of discounted future net cash flows were computed by applying 12-month year-end year-end The following summaries of changes in reserves and standardized measure of discounted future net cash flows were prepared from estimates of proved reserves provided by Netherland, Sewell & Associates, Inc. for 2016 and 2015: Oil Gas Equivalent Proved reserves: Balance at December 31, 2014 (Predecessor) 16,794 327,328 71,348 Purchases of oil and gas reserves in place — — — Discoveries and extensions 69 4,654 845 Revisions of previous estimates (2,944 ) (140,218 ) (26,314 ) Production (980 ) (28,033 ) (5,652 ) Balance at December 31, 2015 (Predecessor) 12,939 163,731 40,227 Purchases of oil and gas reserves in place — — — Discoveries and extensions — — — Revisions of previous estimates (7,413 ) (17,124 ) (10,267 ) Production (794 ) (22,791 ) (4,593 ) Balance at December 31, 2016 (Successor) 4,732 123,816 25,368 Proved reserves at December 31, 2015 (Predecessor) Proved developed reserves 6,824 153,093 32,339 Proved undeveloped reserves 6,115 10,638 7,888 12,939 163,731 40,227 Proved reserves at December 31, 2016 (Successor) Proved developed reserves 4,008 114,719 23,127 Proved undeveloped reserves 724 9,097 2,241 4,732 123,816 25,368 On December 31, 2016, our total proved reserves were 25.4 MMBoe. Revisions decreased 2016 proved natural gas reserves and oil reserves by a net amount of 16.9 Bcf and 7.4 MMbbls as described below: Wyoming – Lower gas prices coupled with increased marketing differentials resulted in a 53% drop in total proved reserves, comprised of a 10% decrease in proved developed producing reserves, 20% in proved developed non-producing Pennsylvania – Although the gas pricing used to generate the 2016 reserves was lower than 2015 pricing, marketing differentials decreased significantly resulting in a 17% increase in total proved reserves compared with 2015, virtually all realized in the proved developed producing category. The total value of the proved reserves (PV10%) increase by $12.6 million from a negative $5.6 million to $7.0 million. California – A significant drop in SEC oil prices for 2016 resulted in a decrease of 58% to the total proved reserves. This decrease was comprised of a 33% decrease in proved developed producing reserves, a 25% decrease in proved developed non-producing At December 31, 2015, our proved reserves were 40.2 MMBoe, all of which are scheduled to be drilled within five years of initial disclosure. Undeveloped reserves transferred to developed reserves were 0.8 MMBoe for the year ended December 31, 2015 and capital costs incurred to convert these proved undeveloped reserves were $12.9 million. Revisions decreased 2015 proved natural gas reserves and oil reserves by a net amount of 140 Bcf and 2.9 MMbbls, of which for natural gas 124 Bcf was due to pricing, 16 Bcf due to performance, and for oil 2.2 MMBbl was due to pricing and 0.7 MMBbl was due to performance. In 2015, total oil extensions and discoveries of 0.07 MMbbls resulted from the Company’s drilling and completion activities in the Wilmington Townlot and North Wilmington Units in California. In 2015, total gas extensions and discoveries of 4.7 Bcf were from drilling activities in the Marcellus. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Successor Predecessor 2016 2015 Future cash inflows $ 354,611 $ 862,751 Future production costs and taxes (264,246 ) (503,702 ) Future development costs(1) (66,605 ) (180,790 ) Future income tax expenses — — Net future cash flows 23,760 178,259 Discounted at 10% for estimated timing of cash flows 4,595 (82,236 ) Standardized measure of discounted future net cash flows $ 28,355 $ 96,023 (1) Includes future estimated asset retirement obligations of $53.6 million in 2016 and $55.8 million in 2015. Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves Successor Predecessor 2016 2015 Sales, net of production costs and taxes $ (13,286 ) $ (34,176 ) Discoveries and extensions — 2,540 Purchases of reserves in place — — Changes in prices and production costs (108,350 ) (342,650 ) Revisions of quantity estimates (51,108 ) (202,716 ) Development costs incurred 1,807 12,869 Net changes in development costs 74,142 131,919 Interest factor—accretion of discount 12,632 55,506 Net change in income taxes — (54,059 ) Changes in production rates (timing) and other 16,495 (28,277 ) Net (decrease) increase (67,668 ) (459,044 ) Balance at beginning of year 96,023 555,067 Balance at end of year $ 28,355 $ 96,023 Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2016 and 2015 along with estimates of the operating costs, production taxes and future development and abandonment costs (less salvage value) necessary to produce such reserves. The prices used at December 31, 2016 and 2015 were $33.39 and $42.81 per Bbl and $1.59, $1.74 per Mcf, respectively. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense. Operating costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development costs including abandonment costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated to be spent to develop the Company’s portion of proved undeveloped and proved developed non-producing Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards, for both regular and alternative minimum tax. The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.

Organization and Accounting P21

Organization and Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Nature of Operations	Nature of Operations Warren Resources, Inc. (the “Company” or “Warren Resources” or “Warren”), was originally formed on June 12, 1990 for the purpose of acquiring and developing oil and gas properties. The Company was incorporated under the laws of the state of Maryland prior to its reincorporation in the state of Delaware effective October 5, 2016. The Company’s properties are primarily located in California, Pennsylvania and Wyoming.
Reclassifications	Reclassifications Certain prior year amounts in the consolidated financial statements have been reclassified to conform to the current year presentation.
Emergence from Voluntary Reorganization under Chapter 11	Emergence from Voluntary Reorganization under Chapter 11 On June 2, 2016, the Company and certain of its wholly owned subsidiaries (together with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization (the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”), Case No. 16-32760. “debtors-in-possession” The description of the Plan can be found in its entirety by reference to the full text of the Confirmation Order, filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include accounts of the Company, its wholly-owned
Related Parties	Related Parties A party is considered to be related to the Company if the party directly or indirectly or through one or more intermediaries, controls, is controlled by, or is under common control with the Company. Related parties also include principal owners of the Company, its management, members of the immediate families of principal owners of the Company and its management and other parties with which the Company may deal if one party controls or can significantly influence the management or operating policies of the other to an extent that one of the transacting parties might be prevented from fully pursuing its own separate interests. A party which can significantly influence the management or operating policies of the transacting parties or if it has an ownership interest in one of the transacting parties and can significantly influence the other to an extent that one or more of the transacting parties might be prevented from fully pursuing its own separate interests is also a related party.
Reorganization Items	Reorganization Items The Company and the Chapter 11 Subsidiaries have incurred significant one-time costs associated with their reorganization under the Bankruptcy Code, principally professional and legal fees. The amount of these costs, which are being expensed as incurred, significantly affect our results of operations. For the year ended December 31, 2016, restructuring costs amounted to $14.2 million.
Oil and Gas Properties	Oil and Gas Properties The Company accounts for its oil and gas activities using the full cost method. As prescribed by full cost accounting rules, all costs associated with property acquisition, exploration and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of oil and gas properties as well as other internal costs that can be specifically identified with acquisition, exploration and development activities are also capitalized. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs are depleted on the equivalent unit-of-production In accordance with full cost accounting rules, the Company is subject to a limitation on capitalized costs. The capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization, may not exceed the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, plus the cost of unproved properties excluded from amortization, as adjusted for related tax effects. If capitalized costs exceed this limit (the “ceiling limitation”), the excess must be charged to expense. The Company recorded impairment expenses of $145 million in the three months ended December 31, 2016 (Successor), $87 million in the nine months ended September 30, 2016 (Predecessor) and $578 million in the year ended December 31, 2015 (Predecessor). The costs of certain unevaluated oil and gas properties and exploratory wells being drilled are not included in the costs subject to amortization. The Company assesses costs not being amortized for possible impairments or reductions in value and if impairments or a reduction in value has occurred. An impairment of unevaluated oil and gas properties of $184 million was recorded for the year ended December 31, 2015.
Revenue Recognition	Revenue Recognition Oil and gas sales result from undivided interests held by the Company in various oil and gas properties. Sales of natural gas and oil produced are recognized when delivered to, or picked up by, the purchaser. For 2016, the largest purchasers and marketers of our total oil and gas production were Phillips 66, Clearwater Enterprises and Devlar Energy, which accounted for 58%, 35% and 6%, respectively, of total oil and natural gas sales sold in 2016. For 2015, the largest purchasers and marketers of our total oil and gas production were Phillips 66, Clearwater Enterprises and Devlar Energy, which accounted for 48%, 41% and 9%, respectively, of total oil and natural gas sales sold in 2015.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company considers all highly liquid investments with maturities of three months or less when acquired to be cash equivalents. The Company maintains its cash and cash equivalents in bank deposit accounts that may exceed federally insured limits. At December 31, 2016, the Company had the majority of its cash and cash equivalents with one financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on cash and cash equivalents.
Accounts Receivable	Accounts Receivable Accounts receivable include trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on evaluation of a customer’s financial condition and, generally, collateral is not required. Accounts receivable under joint operating agreements generally have a right of offset against future oil and gas revenues if a producing well is completed. Accounts receivable are due within 30 days and are stated at amounts due from customers net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. As of December 31, 2016 and 2015, the Company has an allowance of $808,000 and $16,000 respectively, for doubtful accounts.
Investments	Investments The Company classifies its investment in debt securities as available-for-sale Available-for-sale Available-for-sale non-current
Offering Costs	Offering Costs Costs incurred in connection with the issuance of debt are capitalized and amortized over the term of the related debt using the straight-line
Income Taxes	Income Taxes Deferred income taxes are recognized for the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts based on enacted tax laws and statutory rates applicable to the period in which the differences are expected to affect taxable income. Valuation allowances are established when, in management’s opinion, it is more likely than not that a portion or all of the deferred tax assets will not be realized. The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. Only tax positions that meet the more-likely-than-not
Use of Estimates	Use of Estimates In preparing financial statements, accounting principles generally accepted in the United States of America require management to make estimates and assumptions in determining the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining year end proved oil and gas reserves. Actual results could differ from those estimates. The estimate of the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect reported results.
Gas Imbalances	Gas Imbalances The Company follows the sales method of accounting for gas imbalances. A liability is recorded when the Company’s excess takes of natural gas volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production. The Company has no significant gas imbalances at December 31, 2016 or December 31, 2015.
Stock Based Compensation	Stock Based Compensation The Company uses the Black-Scholes option-pricing The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes options-pricing
Accounting for Long-Lived Assets	Accounting for Long-Lived The Company reviews property and equipment for impairment whenever indicators of impairment are present to determine if the carrying amounts exceed the estimated future net cash flows to be realized. Impairment losses are recognized based on the estimated fair value of the asset.
Derivative financial instruments	Derivative financial instruments The Company has entered into several crude oil and natural gas hedges in order to minimize any effect of a downturn in oil and gas prices and protect profitability. These derivative financial instruments are carried on the balance sheet at fair value. If a derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. Gains and losses resulting from changes in the fair value of the non-designated
Property and Equipment	Property and Equipment Property and equipment are stated at cost and are depreciated using the straight-line method over the estimated useful lives of the assets, ranging from three to twenty-five years, except for land which is not depreciated. Property and equipment consisted of the following at December 31: Successor Predecessor Year ended Year ended (in thousands) Drilling rig $ — $ 22,374 Equipment 21,592 1,503 Automobiles and trucks 278 801 Furniture and fixtures — 522 Land and buildings 9,077 242 Office equipment 385 2,124 31,332 27,566 Less accumulated depreciation and amortization (419 ) (26,018 ) $ 30,913 $ 1,548
Earnings (Loss) Per Common Share	Earnings (Loss) Per Common Share Basic earnings (loss) per common share is computed by dividing the net earnings (loss) applicable to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share is based on the assumption that stock options and warrants are converted into common shares using the treasury stock method and convertible debentures and preferred stock are converted using the if-converted Successor Predecessor Year ended 2016 Year ended 2015 Weighted average shares outstanding—basic 10,000,000 82,128,892 Incremental shares issuable from dilutive stock options — — Weighted average shares outstanding—diluted 10,000,000 82,128,892 Potential common shares relating to options, warrants, preferred stock, restricted stock and convertible debentures excluded from the computations of diluted earnings (loss) per share because they are anti-dilutive Successor Predecessor Year ended December 31, 2016 Year ended 2015 Employee stock options — 3,593,589 Convertible debentures — 32,720 Preferred stock — 5,352 Restricted stock — 1,277,468 Warrants 526,316 — Preferred stock was convertible from the date of issuance until redemption at 100% of the redemption price amount into common stock of the Company at a conversion rate between 1 to 1 and 1 to 0.5. At December 31, 2015, the Convertible Debentures could be converted until maturity at 100% of principal amount into common stock of the Company at a price of $50.00.
Asset Retirement Obligations	Asset Retirement Obligations The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production Balance at December 31, 2014 (Predecessor) $ 29,771 Liabilities incurred 9 Liabilities settled (1,232 ) Accretion expense 2,857 Balance at December 31, 2015 (Predecessor) $ 31,405 Liabilities incurred — Liabilities settled — Accretion expense 2,248 Balance at September 30, 2016 (Predecessor) $ 33,653 Fair value fresh-start adjustment $ (22 ) Balance at September 30, 2016 (Successor) $ 33,631 Liabilities incurred — Liabilities settled — Accretion expense 1,277 Balance at December 31, 2016 (Successor) $ 34,908
Capitalized Interest	Capitalized Interest The Company capitalizes interest on qualifying assets, which include investments in undeveloped oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress. The capitalized interest is determined by multiplying the Company’s interest rate on specific borrowing costs, adjusted to include amortization of bond discount and issuance costs, by the qualifying costs incurred that are excluded from the full cost pool. However, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The capitalized interest amounts are recorded as additions to unevaluated oil and natural gas properties on the consolidated balance sheets. As the costs excluded are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool. Interest of $9.0 million was capitalized for the year ended 2015 and no interest amount was capitalized in 2016.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The FASB recently approved a delay which will make the updated guidance effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is not permitted. We are currently evaluating the effect the new standard will have on our financial statements and results of operations. In August 2014, the FASB issued ASU No. 2014-15, 2014-15”). 2014-15 In April 2015, the Financial Accounting Standards Board issued an Accounting Standards Update (“ASU”) that is intended to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2015, and interim periods within those years (early adoption permitted). The Company has included the impact of the adoption of this ASU on its consolidated financial statements and related disclosures and reclassified $12.5 million of deferred bond offering costs to offset debt as of December 31, 2015. In November 2015, the FASB issued authoritative guidance aimed at simplifying the accounting for deferred taxes. Current GAAP requires the deferred taxes for each jurisdiction (or tax-paying jurisdiction-by-jurisdiction In January 2016, the FASB issued authoritative guidance that amends existing requirements on the classification and measurement of financial instruments. The standard principally affects accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective for fiscal periods after December 15, 2017, and interim periods thereafter. Early adoption of certain provisions is permitted. We are currently evaluating the effect the new guidance will have on our financial statements and results of operations. In February 2016, the FASB issued authoritative guidance that supersedes previous lease accounting requirements and requires that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods thereafter. Early adoption is permitted. We are currently evaluating the effect the new guidance will have on our consolidated financial statements and results of operations. In March 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-9, Compensation-Stock Compensation 2016-9). 2016-9 In March 2016, the FASB issued ASU No. 2016-06, Contingent Put and Call Options in Debt Instruments 2016-06). 2016-06 2016-06 In August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-15, 2016-15). 2016-15

Organization and Accounting P22

Organization and Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Schedule of Components of Property and Equipment	Property and equipment are stated at cost and are depreciated using the straight-line method over the estimated useful lives of the assets, ranging from three to twenty-five years, except for land which is not depreciated. Property and equipment consisted of the following at December 31: Successor Predecessor Year ended Year ended (in thousands) Drilling rig $ — $ 22,374 Equipment 21,592 1,503 Automobiles and trucks 278 801 Furniture and fixtures — 522 Land and buildings 9,077 242 Office equipment 385 2,124 31,332 27,566 Less accumulated depreciation and amortization (419 ) (26,018 ) $ 30,913 $ 1,548
Schedule of Diluted Weighted Average Common Shares	Successor Predecessor Year ended 2016 Year ended 2015 Weighted average shares outstanding—basic 10,000,000 82,128,892 Incremental shares issuable from dilutive stock options — — Weighted average shares outstanding—diluted 10,000,000 82,128,892
Schedule of Potential Common Shares Excluded from Computations of Diluted Earnings (Loss) Per Share	Potential common shares relating to options, warrants, preferred stock, restricted stock and convertible debentures excluded from the computations of diluted earnings (loss) per share because they are anti-dilutive Successor Predecessor Year ended December 31, 2016 Year ended 2015 Employee stock options — 3,593,589 Convertible debentures — 32,720 Preferred stock — 5,352 Restricted stock — 1,277,468 Warrants 526,316 —
Schedule of Reconciliation of the Company's Asset Retirement Obligations	A reconciliation of the Company’s asset retirement obligations is as follows: Balance at December 31, 2014 (Predecessor) $ 29,771 Liabilities incurred 9 Liabilities settled (1,232 ) Accretion expense 2,857 Balance at December 31, 2015 (Predecessor) $ 31,405 Liabilities incurred — Liabilities settled — Accretion expense 2,248 Balance at September 30, 2016 (Predecessor) $ 33,653 Fair value fresh-start adjustment $ (22 ) Balance at September 30, 2016 (Successor) $ 33,631 Liabilities incurred — Liabilities settled — Accretion expense 1,277 Balance at December 31, 2016 (Successor) $ 34,908

Fresh-Start Accounting (Tables)

Fresh-Start Accounting (Tables)	12 Months Ended
	Dec. 31, 2016
Text Block [Abstract]
Reconciliation of Enterprise Value to Estimated Fair Value of Successor's Common Stock	The following table reconciles the Company’s Enterprise Value to the estimated fair value of the Successor’s common stock as of (in thousands): September 30, 2016 Enterprise Value $ 215,890 Plus: Cash 5,034 Less: Fair value of warrants (130,000 ) Fair Value of Successor common stock $ 90,924
Reconciliation of Enterprise Value to Reorganization Value	The following table reconciles the Company’s Enterprise Value to its Reorganization Value as of September 30, 2016 (in thousands): September 30, 2016 Enterprise Value $ 215,890 Plus: Cash 5,034 Plus: Current liabilities 16,999 Plus: Noncurrent asset retirement obligation 33,632 Reorganization Value of Successor assets $ 271,555
Summary of Effects on Consolidated Balance Sheet Due to Reorganization and Fresh-start Accounting Adjustments	The following illustrates the effects on the Company’s consolidated balance sheet due to the reorganization and fresh-start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the Company’s assumptions and methods used to determine fair value for its assets and liabilities. Amounts included in the table below are rounded to thousands. As of September 30, 2016 Predecessor Reorganization Fresh-Start Successor ASSETS Current assets Cash and cash equivalents $ 5,034 $ — $ — $ 5,034 Accounts receivable 7,094 — (521 )(6) 6,573 Other current assets 5,498 — (759 )(6) 4,739 Derivative financial instruments 134 — — 134 Total current assets 17,760 — (1,280 ) 16,480 Noncurrent Assets Oil and gas properties 62,659 — 158,276 (6)(7) 220,935 Property and equipment 1,176 — 29,931 (6)(7) 31,107 Other assets 3,026 — 7 (6) 3,033 Total other assets 66,861 — 188,214 255,075 $ 84,621 $ — $ 186,934 $ 271,555 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable and accrued expenses $ 15,116 — $ 1,883 (6) 16,999 Total current liabilities 15,116 — 1,883 16,999 Noncurrent liabilities Other long-term liabilities 33,654 — (22 )(8) 33,632 Long-term debt — 130,000 (1) 130,000 Liabilities subject to compromise 509,306 (509,306 )(2) — — Total liabilities 558,076 (379,306 ) 1,861 180,631 Commitments and contingencies — — — — Stockholders’ Equity (Deficit) Predecessor preferred stock 128 (128 )(3) — — Predecessor common stock 9 (9 )(3) — — Predecessor additional paid-in 517,468 (517,468 )(3) — Successor common stock — 100 (4) — 100 Successor additional paid-in — 90,824 (4) — 90,824 Accumulated deficit (991,060 ) 805,987 (5) 185,073 (9) — Total stockholders’ equity (deficit) (473,455 ) 379,306 185,073 90,924 $ 84,621 $ — $ 186,934 $ 271,555 Reorganization adjustments 1) Reflects issuance of $130 million of debt from the Exit Credit Facility 2) Liabilities subject to compromise were as follows (in thousands): Accounts payable and accrued expenses $ 38,105 First Lien Credit Facility 230,532 Second Lien Credit Facility 71,617 Senior Notes 161,635 Convertible Debentures (83 ) Other long-term liabilities 7,500 Gain on settlement of liabilities subject to compromise $ 509,306 3) Reflects the cancellation of Predecessor equity as follows (in thousands): Predecessor preferred stock $ 128 Predecessor common stock 9 Predecessor additional paid-in-capital 517,468 Cancellation of Predecessor Company equity $ 517,605 4) Reflects the issuance of Successor equity as follows (in thousands): Successor common stock $ 100 Successor additional paid-in-capital 90,824 Issuance of Successor equity $ 90,924 5) Reflects the cumulative effect of the reorganization adjustments of $806 million. Fresh-start accounting adjustments 6) In estimating the fair value of its oil and natural gas and other properties, the Company used a combination of the income and market approaches. For purposes of estimating the fair value of the Company’s proved reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10% for proved reserves. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $48.24 per barrel of oil and $2.54 per MMBtu of natural gas, after adjustment for transportation fees and regional price differentials. Amount reflects the reclassification of the Company’s gas pipeline cost from oil and gas properties into property and equipment. Other line item amounts reflects changes attributable to oil and gas operations. 7) For purposes of estimating the fair value of its gas pipeline, an income approach was used that estimated future cash flows associated with the assets over the remaining useful lives. The valuation included such inputs as estimated future production, gathering and compression revenues and operating expenses that were discounted at a weighted average cost of capital rate of 9.5%. For purposes of estimating the fair value of the land, an appraisal was performed by an independent third party appraisal firm. 8) Reflects the adjustment of asset retirement obligations to fair value using estimated plugging and abandonment costs as of September 30, 2016. 9) Reflects the cumulative effect of fresh-start accounting adjustments.
Summary of Liabilities Subject to Compromise	Accounts payable and accrued expenses $ 38,105 First Lien Credit Facility 230,532 Second Lien Credit Facility 71,617 Senior Notes 161,635 Convertible Debentures (83 ) Other long-term liabilities 7,500 Gain on settlement of liabilities subject to compromise $ 509,306
Summary of Cancellation of Predecessor Equity	Reflects the cancellation of Predecessor equity as follows (in thousands): Predecessor preferred stock $ 128 Predecessor common stock 9 Predecessor additional paid-in-capital 517,468 Cancellation of Predecessor Company equity $ 517,605
Summary of Issuance of Successor Equity	Reflects the issuance of Successor equity as follows (in thousands): Successor common stock $ 100 Successor additional paid-in-capital 90,824 Issuance of Successor equity $ 90,924

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of Long-Term Liabilities	Current maturing long-term debt, net of debt issuance costs and discounts, consisted of the following: Successor Predecessor December 31, December 31, (in thousands) Exit Credit Facility $ 140,320 $ — First Lien Credit Facility — 229,685 Second Lien Credit Facility — 72,960 Convertible Debentures — 1,540 Senior Notes — 159,885 140,320 464,070 Less current portion — (464,070 ) Long-term portion $ 140,320 $ —
Schedule of Repayment of Principal Amount of Loans	Repayment premium equal to the product of (i) the principal amount of the loans so repaid, due or assigned multiplied by (ii) the applicable percentage set forth below: Year Percentage October 6, 2017 through October 5, 2018 4 % October 6, 2018 through October 5, 2019 2 % October 6, 2019 and thereafter 0 %
Schedule of Convertible Debt	Convertible debentures, net of debt issuance costs of $96,000, consisted of the following (in thousands): Successor Predecessor Maturity date December 31, 2016 December 31, 2015 Secured Convertible 12% Debentures December 31, 2020 $ — $ 783 Secured Convertible 12% Debentures December 31, 2022 — 757 $ — $ 1,540

Investments (Tables)

Investments (Tables)	12 Months Ended
	Dec. 31, 2016
Investments, Debt and Equity Securities [Abstract]
Summary of Amortized Cost, Unrealized Gains and Estimated Fair Values of Available-for-sale Securities	The amortized cost, unrealized gains and estimated fair values of the Company’s available-for-sale Successor Predecessor December 31, December 31, (in thousands) U.S. Treasury Bonds, stripped of interest, maturing 2020 and 2022, aggregate par value of $1.6 million Amortized cost $ — $ 1,138 Gross unrealized gains — 310 Estimated fair value $ — $ 1,448

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Summary of Company's Stock Options	A summary of the Company’s stock options is as follows: Incentive Weighted Options outstanding at December 31, 2014 (Predecessor) 1,987,159 $ 4.37 Issued 2,730,400 $ 0.88 Exercised — — Forfeited or expired (1,123,970 ) $ 2.64 Outstanding at December 31, 2015 (Predecessor) 3,593,589 $ 2.26 Issued — — Exercised — — Forfeited or expired (1,085,882 ) $ 2.44 Cancelled (2,507,707 ) $ 2.21 Outstanding at September 30, 2016 (Predecessor) — $ —
Schedule of Restricted Stock	A summary of the Company’s restricted stock is as follows: Shares Weighted Outstanding at December 31, 2014 (Predecessor) 689,370 $ 2.87 Granted 1,669,655 0.56 Vested (697,630 ) 1.79 Forfeited (383,927 ) 2.06 Outstanding at December 31, 2015 (Predecessor) 1,277,468 $ 0.69 Granted — — Vested (83,884 ) 3.70 Forfeited (21,097 ) 3.70 Cancelled (1,172,487 ) 0.41 Outstanding at September 30, 2016 (Predecessor) — $ —

Fair Value of Financial Instr27

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Schedule of Carrying Amount and Estimated Fair Value of Financial Instruments	Successor Predecessor 2016 2015 Fair Carrying Fair Carrying (in thousands) Financial assets: Collateral Security account $ 2,952 $ 2,952 $ 2,812 $ 2,812 U.S. Treasury Bonds — — 1,448 1,636 Derivative Assets 587 5,87 11,081 11,081 Financial liabilities: Exit Credit Facility 140,320 140,320 — — Derivative Liability 10,633 10,633 — — Fixed rate debentures — — 3,057 1,636 First Lien Credit Facility — — 234,665 234,665 Second Lien Credit Facility — — 74,912 74,912 Senior Notes — — 25,090 165,368
Schedule of Assets and Liabilities, Including both Current and Non-Current Portions, Measured at Fair Value on a Recurring Basis	The following table presents for each hierarchy level our assets and liabilities, including both current and non-current December 31, 2016 Level 1 Level 2 Level 3 Total (in thousands) Current Assets Derivative Financial Instruments $ — $ 587 $ — $ 587 Current Liabilities Derivatives Financial Instruments $ — $ 6,313 $ — $ 6,313 Noncurrent Liabilities Derivative Financial Instruments $ — $ 4,320 $ — $ 4,320 December 31, 2015 Level 1 Level 2 Level 3 Total (in thousands) Current Assets U.S. Treasury Bonds—Available-For-Sale $ 1,448 $ — $ — $ 1,448 Derivative Financial Instruments $ — $ 11,081 $ — $ 11,081

Derivative Financial Instrume28

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of Open Financial Derivative Positions Related to Oil and Gas Production	The following table summarizes the open financial derivative positions as of December 31, 2016 related to oil and gas production. The Company will receive prices as noted in the table below and will pay a counterparty market price based on the NYMEX (for natural gas production) or WTI (for oil production) index price, settled monthly. Product Type Contract Period Volume Price per BRENT Oil Collar 01/01/17 - 12/31/17 250 Bbl/d $ 42.00 – 57.25 BRENT Oil Collar 01/01/17 - 12/31/18 250 Bbl/d $ 42.00 – 60.00 BRENT Oil Collar 01/01/17 - 12/31/18 250 Bbl/d $ 42.00 – 60.50 BRENT Oil Collar 01/01/17 - 12/31/18 250 Bbl/d $ 43.00 – 61.50 BRENT Oil Collar 01/01/17 - 12/31/18 250 Bbl/d $ 42.00 – 59.60 BRENT Oil Swap 01/01/17 - 12/31/17 100 Bbl/d $ 55.30 BRENT Oil Swap 01/01/17 - 12/31/17 250 Bbl/d $ 56.25 CIG Basis Swap 01/01/17 - 03/31/19 7,500 MMBtu/d $ (0.36 ) DTI Basis Swap 01/01/17 - 03/31/17 10,000 MMBtu/d $ (0.86 ) DTI Basis Swap 01/01/17 - 03/31/19 10,000 MMBtu/d $ (0.98 ) DTI Basis Swap 01/01/17 - 03/31/19 10,000 MMBtu/d $ (1.04 ) NYMEX Gas Collar 01/01/17 - 12/31/17 15,000 MMBtu/d $ 2.80 – 3.10 NYMEX Gas Collar 01/01/17 - 12/31/18 10,000 MMBtu/d $ 2.80 – 3.15 NYMEX Gas Collar 01/01/18 - 12/31/18 10,000 MMBtu/d $ 2.80 – 3.30 NYMEX Gas Swap 01/01/17 - 03/31/18 10,000 MMBtu/d $ 3.56 NYMEX Gas Swap 01/01/17 - 07/31/17 5,000 MMBtu/d $ 3.55
Summary of Amount of Gains (Losses) Recognized In Income from Derivative Instruments Not Designated as Hedging Instruments	The tables below summarize the amount of gains (losses) recognized in income from derivative instruments not designated as hedging instruments under authoritative guidance (in thousands). Successor Predecessor Predecessor Derivatives not designated as Hedging Instrument under authoritative guidance For the three For the nine For the (in thousands) Realized cash settlements on hedges $ (693 ) $ 11,741 $ 13,007 Unrealized gain (loss) on hedges (10,181 ) (10,947 ) 7,076 Total gain (loss) $ (10,874 ) $ 794 $ 20,083
Schedule of Fair Value and Balance Sheet Location of Net Derivatives	The table below reflects the line item in our Consolidated Balance Sheet where the fair value of our net derivatives, are included. December 31, 2016 Balance Fair Value (in thousands) Commodity—Natural Gas Current assets $ 587 Total derivatives not designated as hedging instruments $ 587 (in thousands) Commodity—Oil Current liabilities $ 1,562 Commodity—Natural Gas Current liabilities 4,751 Total derivatives not designated as hedging instruments $ 6,313 (in thousands) Commodity—Oil Other long-term liabilities $ 1,615 Commodity—Natural Gas Other long-term liabilities 2,705 Total derivatives not designated as hedging instruments $ 4,320 December 31, 2015 Balance Fair Value (in thousands) Commodity—Natural Gas Current assets $ 7,816 Commodity—Oil Current assets 3,265 Total derivatives not designated as hedging instruments $ 11,081

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of Difference Between Company's Effective Income Tax Rate and Federal Statutory Rate	The Company's effective income tax rate differed from the federal statutory rate as follows: December 31, September 30, 2015 (in thousands) Income Taxes at Federal Statutory Rate $ (56,818 ) $ (51,112 ) $ (210,781 ) Change in Valuation Allowance 36,912 60,625 251,045 Nondeductible Expenses 4 (788 ) (2,523 ) State Income Taxes Net of Federal Benefit (6,618 ) (5,953 ) (37,197 ) Section 382 NOL Reduction 26,520 — — Other — (2,648 ) (527 ) — 124 17
Schedule of Deferred Tax Assets and Liabilities	December 31, September 30, 2015 (in thousands) Deferred Tax Assets Relating To: Net Operating Loss Carryforward 159,636 176,741 130,816 Oil and Gas Properties and Tangible Equipment 195,957 219,440 228,324 Stock Option Expense — 4,564 4,207 Unrealized Loss on Derivatives 4,036 — — Other 1,147 1,105 719 360,776 401,850 364,066 Less Valuation Allowance 360,553 401,800 359,510 Total Deferred Tax Asset 223 50 4,556 Deferred Tax Liabilities Relating To: Unrealized Gain on Derivatives (223 ) (50 ) (4,432 ) Net Unrealized Gain on Investments — — (124 ) Total Deferred Tax Liability (223 ) (50 ) (4,556 ) Net Deferred Tax Asset (Liability) — — —

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Annual Rental Payments which are Subject to Escalation and Include Utility Charges	Future minimum annual rental payments, which are subject to escalation and include utility charges as of December 31, 2016, are as follows: (in thousands) Year ending December 31: 2017 $ 349 2018 438 2019 384 2020 393 2021 401 Thereafter 134 $ 2,099

Oil and Gas Information (Tables

Oil and Gas Information (Tables)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Schedule of Costs Related to the Oil and Gas Activities Incurred	Costs related to the oil and gas activities of the Company were incurred as follows for the years ended December 31: Successor Predecessor 2016 2015 (in thousands) Property acquisition—unproved $ — $ — Property acquisition—proved — 18,626 Exploration costs — 3 Development costs 5,052 17,359 $ 5,052 $ 35,988
Schedule of Aggregate Capitalized Costs Relating to the Company's Oil and Gas Activities	The Company had the following aggregate capitalized costs relating to the Company’s oil and gas activities at December 31: Successor Predecessor 2016 2015 (in thousands) Unproved oil and gas properties $ — $ 14,658 Proved oil and gas properties 222,655 1,125,297 222,655 1,139,955 Less accumulated depreciation, depletion and impairment expense (154,292 ) (977,270 ) $ 68,363 $ 162,685
Schedule of the Company's Results of Operations from Oil and Natural Gas Producing Activities	The following table sets forth the Company’s results of operations from oil and natural gas producing activities: Successor Predecessor Predecessor Three months Nine months Year ended 2016 2016 2015 (in thousands) Revenues $ 16,862 $ 39,712 $ 83,734 Production costs (10,678 ) (32,611 ) (49,557 ) Accretion of asset retirement obligation (1,277 ) (2,248 ) (2,857 ) Impairment (145,117 ) (87,094 ) (562,151 ) Depreciation, depletion, amortization (9,175 ) (15,128 ) (59,729 ) Loss from oil and gas producing activities $ (149,385 ) $ (97,369 ) $ (590,560 )
Summary of Warren's Oil and Gas Properties Not Subject to Amortization	The following is a summary of Warren’s oil and gas properties not subject to amortization: Successor Predecessor December 31, 2016 December 31, 2015 (in thousands) Acquisition costs $ — $ — Exploration costs — — Development costs(1) — 365 Total oil and gas properties not subject to amortization $ — $ 365 (1) The Company’s development costs primarily reflect investment in well cellars and facilities in its Wilmington oil field to facilitate the development of future oil wells. These costs will be allocated to future wells drilled, the majority of these wells are expected to be drilling during the next five to eight years.

Oil and Gas Reserve Data (Una32

Oil and Gas Reserve Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Text Block [Abstract]
Schedule of Summary of Changes in Proved Reserves	The following summaries of changes in reserves and standardized measure of discounted future net cash flows were prepared from estimates of proved reserves provided by Netherland, Sewell & Associates, Inc. for 2016 and 2015: Oil Gas Equivalent Proved reserves: Balance at December 31, 2014 (Predecessor) 16,794 327,328 71,348 Purchases of oil and gas reserves in place — — — Discoveries and extensions 69 4,654 845 Revisions of previous estimates (2,944 ) (140,218 ) (26,314 ) Production (980 ) (28,033 ) (5,652 ) Balance at December 31, 2015 (Predecessor) 12,939 163,731 40,227 Purchases of oil and gas reserves in place — — — Discoveries and extensions — — — Revisions of previous estimates (7,413 ) (17,124 ) (10,267 ) Production (794 ) (22,791 ) (4,593 ) Balance at December 31, 2016 (Successor) 4,732 123,816 25,368 Proved reserves at December 31, 2015 (Predecessor) Proved developed reserves 6,824 153,093 32,339 Proved undeveloped reserves 6,115 10,638 7,888 12,939 163,731 40,227 Proved reserves at December 31, 2016 (Successor) Proved developed reserves 4,008 114,719 23,127 Proved undeveloped reserves 724 9,097 2,241 4,732 123,816 25,368
Schedule of Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves	Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Successor Predecessor 2016 2015 Future cash inflows $ 354,611 $ 862,751 Future production costs and taxes (264,246 ) (503,702 ) Future development costs(1) (66,605 ) (180,790 ) Future income tax expenses — — Net future cash flows 23,760 178,259 Discounted at 10% for estimated timing of cash flows 4,595 (82,236 ) Standardized measure of discounted future net cash flows $ 28,355 $ 96,023 (1) Includes future estimated asset retirement obligations of $53.6 million in 2016 and $55.8 million in 2015.
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves	Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves Successor Predecessor 2016 2015 Sales, net of production costs and taxes $ (13,286 ) $ (34,176 ) Discoveries and extensions — 2,540 Purchases of reserves in place — — Changes in prices and production costs (108,350 ) (342,650 ) Revisions of quantity estimates (51,108 ) (202,716 ) Development costs incurred 1,807 12,869 Net changes in development costs 74,142 131,919 Interest factor—accretion of discount 12,632 55,506 Net change in income taxes — (54,059 ) Changes in production rates (timing) and other 16,495 (28,277 ) Net (decrease) increase (67,668 ) (459,044 ) Balance at beginning of year 96,023 555,067 Balance at end of year $ 28,355 $ 96,023

Organization and Accounting P33

Organization and Accounting Policies - Additional Information (Detail)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)shares	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)Institution$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares
Organization And Significant Accounting Policies [Line Items]
Restructuring costs			$ 14,200,000
Discount rate applied to estimated future net revenues from proved oil and gas reserves			10.00%
Impairment of oil and gas properties	$ 145,117,000
Book value of impairment of unevaluated oil and gas properties				$ 184,000,000
Number of financial institutions holding majority of the entity's cash and cash equivalents | Institution			1
Credit period			30 days
Allowance for doubtful accounts	808,000		$ 808,000	$ 16,000
Deferred finance costs, net of accumulated amortization	0	$ 3,900,000	0
Accumulated amortization of debt issuance costs	0		$ 0
Compensation expense related to stock options and restricted stock	$ 0
Number of common shares into which one share of preferred stock is to be converted | shares	0.50		0.50
Conversion price | $ / shares				$ 50
Fair market value of cash held in escrow that is legally restricted for potential plugging and abandonment liability	$ 2,900,000		$ 2,900,000	$ 2,900,000
Interest costs capitalized			$ 0
Reclassification of deferred bond offering cost				$ 12,500,000
Minimum [Member]
Organization And Significant Accounting Policies [Line Items]
Estimated useful lives of assets except land			3 years
Maximum [Member]
Organization And Significant Accounting Policies [Line Items]
Estimated useful lives of assets except land			25 years
Stock Options [Member]
Organization And Significant Accounting Policies [Line Items]
Expected dividends rate			0.00%
Weighted average volatility			64.00%
Risk-free interest rate			1.23%
Expected life			3 years 6 months
Weighted average per share fair value | $ / shares			$ 0.40
Stock option issued | shares			0
Preferred Stock [Member]
Organization And Significant Accounting Policies [Line Items]
Percentage of redemption price amount from the date of issuance until redemption that may be converted			100.00%
Preferred Stock [Member] | Maximum [Member]
Organization And Significant Accounting Policies [Line Items]
Number of common shares into which one share of preferred stock is to be converted | shares	1		1
Convertible Debt Securities [Member]
Organization And Significant Accounting Policies [Line Items]
Percentage of principal amount at which debentures may be converted from the date of issuance until maturity into common stock				100.00%
Phillips 66 [Member] | Sales Revenue, Net [Member] | Customer Concentration Risk [Member]
Organization And Significant Accounting Policies [Line Items]
Percentage of total oil and natural gas sales sold accounted by the largest purchasers and marketers for the company's production			58.00%	48.00%
Clearwater Enterprises [Member] | Sales Revenue, Net [Member] | Customer Concentration Risk [Member]
Organization And Significant Accounting Policies [Line Items]
Percentage of total oil and natural gas sales sold accounted by the largest purchasers and marketers for the company's production			35.00%	41.00%
Devlar Energy [Member] | Sales Revenue, Net [Member] | Customer Concentration Risk [Member]
Organization And Significant Accounting Policies [Line Items]
Percentage of total oil and natural gas sales sold accounted by the largest purchasers and marketers for the company's production			6.00%	9.00%
Predecessor [Member]
Organization And Significant Accounting Policies [Line Items]
Restructuring costs		14,171,000
Impairment of oil and gas properties		87,094,000		$ 578,323,000
Allowance for doubtful accounts				15,000
Deferred finance costs, net of accumulated amortization				12,500,000
Accumulated amortization of debt issuance costs				4,700,000
Compensation expense related to stock options and restricted stock		$ 600,000		2,200,000
Interest costs capitalized				9,000,000
Predecessor [Member] | Drilling Rig [Member]
Organization And Significant Accounting Policies [Line Items]
Impairment of oil and gas properties				$ 16,700,000
Predecessor [Member] | Stock Options [Member]
Organization And Significant Accounting Policies [Line Items]
Stock option issued | shares				2,730,400

Organization and Accounting P34

Organization and Accounting Policies - Schedule of Components of Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 31,332
Less accumulated depreciation and amortization	(419)
Property and equipment, net	30,913
Equipment [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross	21,592
Automobiles and Trucks [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross	278
Land and Buildings [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross	9,077
Office Equipment [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross	$ 385
Predecessor [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross		$ 27,566
Less accumulated depreciation and amortization		(26,018)
Property and equipment, net		1,548
Predecessor [Member] | Drilling Rig [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross		22,374
Predecessor [Member] | Equipment [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross		1,503
Predecessor [Member] | Automobiles and Trucks [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross		801
Predecessor [Member] | Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross		522
Predecessor [Member] | Land and Buildings [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross		242
Predecessor [Member] | Office Equipment [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, gross		$ 2,124

Organization and Accounting P35

Organization and Accounting Policies - Schedule of Diluted Weighted Average Common Shares (Detail) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted average shares outstanding-basic	10,000,000
Incremental shares issuable from dilutive stock options	0
Weighted average shares outstanding-diluted	10,000,000
Predecessor [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted average shares outstanding-basic		82,128,892
Incremental shares issuable from dilutive stock options		0
Weighted average shares outstanding-diluted		82,128,892

Organization and Accounting P36

Organization and Accounting Policies - Schedule of Potential Common Shares Excluded from Computations of Diluted Earnings (Loss) Per Share (Detail) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Warrant [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive securities (in shares)	526,316
Predecessor [Member] | Stock Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive securities (in shares)		3,593,589
Predecessor [Member] | Convertible Debt Securities [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive securities (in shares)		32,720
Predecessor [Member] | Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive securities (in shares)		1,277,468
Predecessor [Member] | Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive securities (in shares)		5,352

Organization and Accounting P37

Organization and Accounting Policies - Schedule of Reconciliation of the Company's Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Asset Retirement Obligations [Line Items]
Balance at beginning of period	$ 33,631
Fair value fresh-start adjustment		$ (22)
Accretion expense	1,277
Balance at end of period	34,908	33,631
Predecessor [Member]
Asset Retirement Obligations [Line Items]
Balance at beginning of period	$ 33,653	31,405	$ 29,771
Liabilities incurred			9
Liabilities settled			(1,232)
Accretion expense		2,248	2,857
Balance at end of period		$ 33,653	$ 31,405

Reorganization - Additional Inf

Reorganization - Additional Information (Detail) - USD ($)	Oct. 05, 2016	Dec. 31, 2016	May 22, 2015
Reorganization Under Chapter 11 Of US Bankruptcy Code Disclosure [Line Items]
Bankruptcy petition filed date		Jun. 2, 2016
Bankruptcy proceedings court where petition was filed		United States Bankruptcy Court for the Southern District of Texas (the "Bankruptcy Court")
Plan of reorganization confirmation date		Sep. 14, 2016
Plan of reorganization effective date		Oct. 5, 2016
Warrant expiration date		Oct. 5, 2021
Warrant exercise price		$ 10.50
Marcellus Asset Acquisition [Member]
Reorganization Under Chapter 11 Of US Bankruptcy Code Disclosure [Line Items]
Common stock, new issues		60,645
2016 Equity Compensation Plan [Member]
Reorganization Under Chapter 11 Of US Bankruptcy Code Disclosure [Line Items]
Common stock share authorized		600,000
First Lien Credit Facility [Member]
Reorganization Under Chapter 11 Of US Bankruptcy Code Disclosure [Line Items]
Common stock, new issues		7,899,537
Second Lien Credit Facility [Member]
Reorganization Under Chapter 11 Of US Bankruptcy Code Disclosure [Line Items]
Common stock, new issues		755,000
Credit Facility [Member]
Reorganization Under Chapter 11 Of US Bankruptcy Code Disclosure [Line Items]
Common stock, new issues		1,284,818
Credit Facility [Member] | First Lien Exit Facility [Member]
Reorganization Under Chapter 11 Of US Bankruptcy Code Disclosure [Line Items]
Face amount of debt instrument		$ 150,000,000
Borrowing capacity		130,000,000
Additional borrowing capacity		$ 20,000,000
Variable rate basis		LIBOR
Credit Facility [Member] | First Lien Exit Facility [Member] | LIBOR [Member]
Reorganization Under Chapter 11 Of US Bankruptcy Code Disclosure [Line Items]
Interest rate (as a percent)		9.00%
Credit Facility [Member] | First Lien Credit Facility [Member]
Reorganization Under Chapter 11 Of US Bankruptcy Code Disclosure [Line Items]
Face amount of debt instrument			$ 250,000,000
Credit Facility [Member] | Second Lien Credit Facility [Member]
Reorganization Under Chapter 11 Of US Bankruptcy Code Disclosure [Line Items]
Common stock, new issues	526,316	526,316
Credit Facility [Member] | Second Lien Credit Facility [Member] | 2016 Equity Compensation Plan [Member]
Reorganization Under Chapter 11 Of US Bankruptcy Code Disclosure [Line Items]
Common stock, new issues		0
Common stock share authorized		600,000

Fresh-Start Accounting - Additi

Fresh-Start Accounting - Additional Information (Detail)	Sep. 30, 2016USD ($)$ / Boe$ / MMBTU
Fresh-Start Adjustment [Line Items]
Retained earnings, balance on fresh-start reporting date | $	$ 0
Weighted average cost of capital rate	10.00%
Oil and Natural Properties [Member]
Fresh-Start Adjustment [Line Items]
Weighted average commodity price | $ / Boe	48.24
Natural Gas [Member]
Fresh-Start Adjustment [Line Items]
Weighted average commodity price | $ / MMBTU	2.54

Fresh-Start Accounting - Reconc

Fresh-Start Accounting - Reconciliation of Enterprise Value to Estimated Fair Value of Successor's Common Stock (Detail) $ in Thousands	Sep. 30, 2016USD ($)
Reorganizations [Abstract]
Enterprise Value	$ 215,890
Plus: Cash	5,034
Less: Fair value of debt	(130,000)
Fair Value of Successor common stock	$ 90,924

Fresh-Start Accounting - Reco41

Fresh-Start Accounting - Reconciliation of Enterprise Value to Reorganization Value (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Sep. 30, 2016
Reorganizations [Abstract]
Enterprise Value		$ 215,890
Plus: Cash		5,034
Plus: Current liabilities	$ 20,531	16,999
Plus: Noncurrent asset retirement obligation		33,632
Reorganization Value of Successor assets		$ 271,555

Fresh-Start Accounting - Summar

Fresh-Start Accounting - Summary of Effects on Consolidated Balance Sheet Due to Reorganization and Fresh-start Accounting Adjustments (Detail)	Sep. 30, 2016USD ($)$ / Boe$ / MMBTU
Fresh-Start Adjustment [Line Items]
Cash and cash equivalents	$ 5,034,000
Accounts receivable	6,573,000
Other current assets	4,739,000
Derivative financial instruments	134,000
Total current assets	16,480,000
Oil and gas properties	220,935,000
Property and equipment	31,107,000
Other assets	3,033,000
Total other assets	255,075,000
Total assets	271,555,000
Accounts payable and accrued expenses	16,999,000
Total current liabilities	16,999,000
Other long-term liabilities	33,632,000
Long-term debt	130,000,000
Liabilities subject to compromise	509,306,000
Total liabilities	180,631,000
Commitments and contingencies	0
Successor common stock	100,000
Successor additional paid-in capital	90,824,000
Accumulated deficit	0
Total stockholders' equity (deficit)	90,924,000
Total liabilities and stockholders' equity (deficit)	$ 271,555,000
Weighted average cost of capital rate	10.00%
Reorganization Adjustments [Member]
Fresh-Start Adjustment [Line Items]
Long-term debt	$ 130,000,000
Liabilities subject to compromise	(509,306,000)
Total liabilities	(379,306,000)
Commitments and contingencies	0
Predecessor preferred stock	(128,000)
Predecessor common stock	(9,000)
Predecessor additional paid-in capital	(517,468,000)
Successor common stock	100,000
Successor additional paid-in capital	90,824,000
Accumulated deficit	805,987,000
Total stockholders' equity (deficit)	379,306,000
Fresh-Start Adjustments [Member]
Fresh-Start Adjustment [Line Items]
Accounts receivable	(521,000)
Other current assets	(759,000)
Total current assets	(1,280,000)
Oil and gas properties	158,276,000
Property and equipment	29,931,000
Other assets	7,000
Total other assets	188,214,000
Total assets	186,934,000
Accounts payable and accrued expenses	1,883,000
Total current liabilities	1,883,000
Other long-term liabilities	(22,000)
Total liabilities	1,861,000
Commitments and contingencies	0
Accumulated deficit	185,073,000
Total stockholders' equity (deficit)	185,073,000
Total liabilities and stockholders' equity (deficit)	$ 186,934,000
Oil and Natural Properties [Member]
Fresh-Start Adjustment [Line Items]
Weighted average commodity price | $ / Boe	48.24
Natural Gas [Member]
Fresh-Start Adjustment [Line Items]
Weighted average commodity price | $ / MMBTU	2.54
Predecessor [Member]
Fresh-Start Adjustment [Line Items]
Cash and cash equivalents	$ 5,034,000
Accounts receivable	7,094,000
Other current assets	5,498,000
Derivative financial instruments	134,000
Total current assets	17,760,000
Oil and gas properties	62,659,000
Property and equipment	1,176,000
Other assets	3,026,000
Total other assets	66,861,000
Total assets	84,621,000
Accounts payable and accrued expenses	15,116,000
Total current liabilities	15,116,000
Other long-term liabilities	33,654,000
Liabilities subject to compromise	509,306,000
Total liabilities	558,076,000
Commitments and contingencies	0
Predecessor preferred stock	128,000
Predecessor common stock	9,000
Predecessor additional paid-in capital	517,468,000
Accumulated deficit	(991,060,000)
Total stockholders' equity (deficit)	(473,455,000)
Total liabilities and stockholders' equity (deficit)	$ 84,621,000

Fresh-Start Accounting - Summ43

Fresh-Start Accounting - Summary of Effects on Consolidated Balance Sheet Due to Reorganization and Fresh-start Accounting Adjustments (Parenthetical) (Detail) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2016
Fresh-Start Adjustment [Line Items]
Long-term debt		$ 140,320
Reorganization adjustments	$ 806,000
Weighted average cost of capital rate	10.00%
Natural Gas Pipe Lines [Member]
Fresh-Start Adjustment [Line Items]
Weighted average cost of capital rate	9.50%
Exit Credit Facility [Member]
Fresh-Start Adjustment [Line Items]
Long-term debt	$ 130,000

Fresh-Start Accounting - Summ44

Fresh-Start Accounting - Summary of Liabilities Subject to Compromise (Detail) $ in Thousands	Sep. 30, 2016USD ($)
Fresh-Start Adjustment [Line Items]
Gain on settlement of liabilities subject to compromise	$ 509,306
Accounts Payable and Accrued Expenses [Member]
Fresh-Start Adjustment [Line Items]
Gain on settlement of liabilities subject to compromise	38,105
Other long-term liabilities [Member]
Fresh-Start Adjustment [Line Items]
Gain on settlement of liabilities subject to compromise	7,500
First Lien Credit Facility [Member]
Fresh-Start Adjustment [Line Items]
Gain on settlement of liabilities subject to compromise	230,532
Second Lien Credit Facility [Member]
Fresh-Start Adjustment [Line Items]
Gain on settlement of liabilities subject to compromise	71,617
Senior Notes [Member]
Fresh-Start Adjustment [Line Items]
Gain on settlement of liabilities subject to compromise	161,635
Convertible Debenture [Member]
Fresh-Start Adjustment [Line Items]
Gain on settlement of liabilities subject to compromise	$ (83)

Fresh-Start Accounting - Summ45

Fresh-Start Accounting - Summary of Cancellation of Predecessor Equity (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015	Dec. 31, 2014
Fresh-Start Adjustment [Line Items]
Predecessor preferred stock		$ 100
Predecessor common stock	$ 100	90,824
Predecessor additional paid-in-capital	90,824
Cancellation of Predecessor Company equity	$ (76,189)	90,924
Predecessor [Member]
Fresh-Start Adjustment [Line Items]
Predecessor preferred stock			$ 128
Predecessor common stock			9
Predecessor additional paid-in-capital			516,715
Cancellation of Predecessor Company equity		(473,455)	$ (323,564)	$ 292,552
Predecessor [Member] | Reorganization Adjustments [Member]
Fresh-Start Adjustment [Line Items]
Predecessor preferred stock		128
Predecessor common stock		9
Predecessor additional paid-in-capital		517,468
Cancellation of Predecessor Company equity		$ (517,605)

Fresh-Start Accounting - Summ46

Fresh-Start Accounting - Summary of Issuance of Successor Equity (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Sep. 30, 2016
Reorganizations [Abstract]
Successor common stock		$ 100
Successor additional paid-in-capital	$ 100	90,824
Cancellation of Predecessor Company equity	$ (76,189)	$ 90,924

Debt - Schedule of Long-term Li

Debt - Schedule of Long-term Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Senior Notes		$ 161,600
Total long-term debt	$ 140,320
Total long-term debt	140,320
Long-term portion	140,320
Exit Credit Facility [Member]
Debt Instrument [Line Items]
Exit Credit Facility	$ 140,320
Predecessor [Member]
Debt Instrument [Line Items]
Convertible Debentures			$ 1,540
Senior Notes			159,885
Total long-term debt			464,070
Total long-term debt			464,070
Less current portion			(464,070)
Predecessor [Member] | First Lien Credit Facilities [Member]
Debt Instrument [Line Items]
Exit Credit Facility			229,685
Predecessor [Member] | Second Lien Credit Facility [Member]
Debt Instrument [Line Items]
Exit Credit Facility			$ 72,960

Debt - Additional Information (

Debt - Additional Information (Detail)	Oct. 05, 2017	Aug. 01, 2017	Oct. 05, 2016shares	Nov. 09, 2015USD ($)	Oct. 22, 2015USD ($)ItemSubsidiariesshares	May 22, 2015USD ($)	Dec. 31, 2016USD ($)$ / shares	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)	Aug. 11, 2014USD ($)
Debt Instrument [Line Items]
Minimum amount to be kept as undrawn availability under credit agreement							$ 5,000,000		$ 5,000,000
Draws on additional borrowings							$ 10,000,000
Common stock, par value | $ / shares							$ 0.010		$ 0.010
Debt issuance costs, net							$ 0	$ 3,900,000	$ 0
Senior Notes								$ 161,600,000
Credit Facility [Member]
Debt Instrument [Line Items]
Common stock, new issues | shares									1,284,818
Senior Notes [Member]
Debt Instrument [Line Items]
Face amount of debt instrument											$ 300,000,000
Interest rate (as a percent)						9.00%					9.00%
Gain on retirement of debt										$ 14,400,000
Percentage on initial purchase price											98.617%
Secured Convertible Debentures, due December 31, 2020 [Member]
Debt Instrument [Line Items]
Interest rate (as a percent)							12.00%	12.00%	12.00%
Secured Convertible Debentures, due December 31, 2022 [Member]
Debt Instrument [Line Items]
Interest rate (as a percent)							12.00%	12.00%	12.00%
Convertible Debenture [Member]
Debt Instrument [Line Items]
Debt issuance costs, net							$ 96,000		$ 96,000
Scenario, Forecast [Member] | Senior Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Percentage of Senior Notes can be redeemed on or after August 1, 2017		35.00%
First Lien Credit Facility [Member]
Debt Instrument [Line Items]
Common stock, new issues | shares									7,899,537
First Lien Credit Facility [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Face amount of debt instrument						$ 250,000,000
Term of loan						5 years
Debt conversion, face amount						$ 47,000,000
Number of wholly-owned subsidiaries that guarantee Line of Credit Facility | Subsidiaries					3
First Lien Credit Facility [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Fair value of Senior Notes exchanged						69,590,000
First Lien Credit Facility [Member] | Certain Lenders [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Borrowing capacity						172,500,000
Additional borrowing capacity						30,000,000
Debt conversion, face amount						45,230,000
Accrued unpaid interest rolled into the Lien Term Loans						$ 1,900,000
Second Lien Credit Facility [Member]
Debt Instrument [Line Items]
Common stock, new issues | shares									755,000
Second Lien Credit Facility [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Common stock, new issues | shares			526,316						526,316
Second Lien Credit Facility [Member] | Certain Holders | Credit Facility [Member]
Debt Instrument [Line Items]
Debt conversion, face amount					$ 40,100,000
Second Lien Credit Facility [Member] | Certain Holders | Senior Notes [Member]
Debt Instrument [Line Items]
Fair value of Senior Notes exchanged					$ 63,100,000
June 30, 2017 Until December 31, 2017 [Member]
Debt Instrument [Line Items]
Credit agreement, consolidated total leverage ratio									550.00%
March 31, 2018 Until December 31 , 2018 [Member]
Debt Instrument [Line Items]
Credit agreement, consolidated total leverage ratio									500.00%
March 31, 2019 Until Maturity Date [Member]
Debt Instrument [Line Items]
Credit agreement, consolidated total leverage ratio									450.00%
Credit Facility [Member] | First Lien Credit Facility [Member]
Debt Instrument [Line Items]
Draws on additional borrowings				$ 15,000,000
Common stock, par value | $ / shares							$ 0.01		$ 0.01
Credit Facility [Member] | First Lien Credit Facility [Member] | LIBOR [Member]
Debt Instrument [Line Items]
Interest rate (as a percent)					8.50%
Variable rate basis									LIBOR
Interest rate during the period (as a percent)								9.50%
Credit Facility [Member] | First Lien Credit Facility [Member] | LIBOR [Member] | Minimum [Member]
Debt Instrument [Line Items]
Margin (as a percent)									1.00%
Credit Facility [Member] | Second Lien Credit Facility [Member]
Debt Instrument [Line Items]
Face amount of debt instrument					$ 51,000,000
Interest rate (as a percent)					12.00%
Outstanding balance								$ 71,600,000
Term of loan					5 years
Gain on retirement of debt									$ 0
Debt issuance costs, net								$ 1,600,000
Credit Facility [Member] | Second Lien Credit Facility [Member] | Beginning With April 20, 2016 [Member]
Debt Instrument [Line Items]
Number of semi annual interest payment dates | Item					3
Semi-annual interest may elect (as a percent)					6.00%
Credit Facility [Member] | Second Lien Credit Facility [Member] | Beginning with October 20, 2017 and Ending October 20, 2018 [Member]
Debt Instrument [Line Items]
Number of semi annual interest payment dates | Item					3
Semi-annual interest may elect (as a percent)					1.50%
Credit Facility [Member] | Second Lien Credit Facility [Member] | Certain Lenders [Member]
Debt Instrument [Line Items]
Face amount of debt instrument					$ 11,000,000
Credit Facility [Member] | Second Lien Credit Facility [Member] | Certain Holders
Debt Instrument [Line Items]
Debt conversion, face amount					40,100,000
Fair value of Senior Notes exchanged					$ 63,100,000
Number of common stock shares issued for conversion of debt | shares					4,000,000
Exit Credit Facility [Member]
Debt Instrument [Line Items]
Paid-in-kind interest									300,000
Outstanding balance							$ 140,300,000		140,300,000
Exit Credit Facility [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Face amount of debt instrument							150,000,000		150,000,000
Borrowing capacity							130,000,000		130,000,000
Additional borrowing capacity							$ 20,000,000		$ 20,000,000
Percentage of principal payment amount	4.00%
Variable rate basis									LIBOR
Exit Credit Facility [Member] | Credit Facility [Member] | LIBOR [Member]
Debt Instrument [Line Items]
Interest rate (as a percent)							9.00%		9.00%
Exit Credit Facility [Member] | Credit Facility [Member] | Discount Rate [Member]
Debt Instrument [Line Items]
Percentage of principal payment amount	0.50%

Debt - Schedule of Repayment of

Debt - Schedule of Repayment of Principal Amount of Loans (Detail)	12 Months Ended
	Dec. 31, 2016
October 6, 2017 through October 5, 2018 [Member]
Debt Instrument, Redemption [Line Items]
October 6, 2017 through October 5, 2018	4.00%
October 6, 2018 through October 5, 2019 [Member]
Debt Instrument, Redemption [Line Items]
October 6, 2017 through October 5, 2018	2.00%
October 6, 2019 and Thereafter [Member]
Debt Instrument, Redemption [Line Items]
October 6, 2017 through October 5, 2018	0.00%

Debt - Schedule of Convertible

Debt - Schedule of Convertible Debt (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2016
Secured Convertible Debentures, due December 31, 2020 [Member]
Debt Conversion [Line Items]
Maturity date	Dec. 31, 2020
Interest rate (as a percent)	12.00%		12.00%
Secured Convertible Debentures, due December 31, 2022 [Member]
Debt Conversion [Line Items]
Maturity date	Dec. 31, 2022
Interest rate (as a percent)	12.00%		12.00%
Predecessor [Member] | Secured Convertible Debentures, due December 31, 2020 [Member]
Debt Conversion [Line Items]
Maturity date		Dec. 31, 2020
Principal amount		$ 783
Interest rate (as a percent)		12.00%
Predecessor [Member] | Secured Convertible Debentures, due December 31, 2022 [Member]
Debt Conversion [Line Items]
Maturity date		Dec. 31, 2022
Principal amount		$ 757
Interest rate (as a percent)		12.00%
Predecessor [Member] | Secured Convertible Debentures [Member]
Debt Conversion [Line Items]
Principal amount		$ 540

Investments - Summary of Amorti

Investments - Summary of Amortized Cost, Unrealized Gains and Estimated Fair Values of Available-for-sale Securities (Detail) - Predecessor [Member] - U.S. Treasury Bonds [Member] $ in Thousands	Dec. 31, 2015USD ($)
Schedule of Available-for-sale Securities [Line Items]
Amortized cost	$ 1,138
Gross unrealized gains	310
Estimated fair value	$ 1,448

Investments - Summary of Amor52

Investments - Summary of Amortized Cost, Unrealized Gains and Estimated Fair Values of Available-for-sale Securities (Parenthetical) (Detail) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
U.S. Treasury Bonds, maturing 2020 [Member]
Schedule of Available-for-sale Securities [Line Items]
Aggregate par value	$ 1,600,000
U.S. Treasury Bonds, maturing 2020 [Member] | Predecessor [Member]
Schedule of Available-for-sale Securities [Line Items]
Aggregate par value		$ 1,600,000
U.S. Treasury Bonds, maturing 2022 [Member]
Schedule of Available-for-sale Securities [Line Items]
Aggregate par value	$ 1,600,000
U.S. Treasury Bonds, maturing 2022 [Member] | Predecessor [Member]
Schedule of Available-for-sale Securities [Line Items]
Aggregate par value		$ 1,600,000

Stockholders' Equity - Addition

Stockholders' Equity - Additional Information (Detail) - USD ($)	Oct. 05, 2016	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Warrant expiration date				Oct. 5, 2021
Warrant exercise price		$ 10.50		$ 10.50
Cumulative dividend on preferred stock (as a percent)				8.00%
Number of common shares into which one share of preferred stock is to be converted		0.50		0.50
Redemption price (in dollars per share)		$ 12		$ 12
Shares to be issued as percentage of redemption price and any accrued and unpaid dividends				125.00%
Number of trading days considered for calculating the weighted average closing bid price at which preferred stock will be redeemed				30 days
Maximum number of shares of common stock that the company, at its option, can issue for each one share of preferred stock redeemed				1.5
Percentage of conversion price that the entity's common stock must exceed to give the entity the right to redeem				133.00%
Minimum number of days within 30-day trading period in which the closing price of the entity's common stock must exceed the conversion price				10 days
Number of trading days during which the closing bid price of the entity's common stock must exceed the conversion price				30 days
Total stock-based compensation expense related to stock options and restrictive stock award		$ 0
First Lien Credit Facility [Member]
Class of Stock [Line Items]
Common stock, new issues				7,899,537
Second Lien Credit Facility [Member]
Class of Stock [Line Items]
Common stock, new issues				755,000
Marcellus Asset Acquisition [Member]
Class of Stock [Line Items]
Common stock, new issues				60,645
Predecessor [Member]
Class of Stock [Line Items]
Cumulative dividend on preferred stock (as a percent)					8.00%
Total stock-based compensation expense related to stock options and restrictive stock award			$ 600,000		$ 2,200,000
2016 Equity Compensation Plan [Member]
Class of Stock [Line Items]
Common stock share authorized				600,000
Credit Facility [Member]
Class of Stock [Line Items]
Common stock, new issues				1,284,818
Credit Facility [Member] | Second Lien Credit Facility [Member]
Class of Stock [Line Items]
Common stock, new issues	526,316			526,316
Credit Facility [Member] | 2016 Equity Compensation Plan [Member] | Second Lien Credit Facility [Member]
Class of Stock [Line Items]
Common stock, new issues				0
Common stock share authorized				600,000
Preferred Stock [Member]
Class of Stock [Line Items]
Redemption price (in dollars per share)		$ 12		$ 12

Stockholder's Equity - Summary

Stockholder's Equity - Summary of Company's Stock Options (Detail) - Stock Options [Member] - $ / shares	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015
Incentive options
Incentive Options,Issued		0
Predecessor [Member]
Incentive options
Incentive options, Outstanding Beginning balance	3,593,589	3,593,589	1,987,159
Incentive Options,Issued			2,730,400
Incentive options, Exercised	0		0
Incentive options, Forfeited or expired	(1,085,882)		(1,123,970)
Incentive options, Cancelled	(2,507,707)
Incentive options, Outstanding Ending balance			3,593,589
Weighted Average Exercise
Weighted Average Exercise Price, Outstanding Beginning balance	$ 2.26	$ 2.26	$ 4.37
Weighted Average Exercise Price, Issued			0.88
Weighted Average Exercise Price, Exercised	0		0
Weighted Average Exercise Price, Forfeited or expired	2.44		2.64
Weighted Average Exercise Price, Cancelled	$ 2.21
Weighted Average Exercise Price, Outstanding Ending balance			$ 2.26

Stockholder's Equity - Schedule

Stockholder's Equity - Schedule of Restricted Stock Issued to Employees (Detail) - Restricted Stock [Member] - Predecessor [Member] - $ / shares	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares, Outstanding, Beginning balance	1,277,468	689,370
Shares, Granted		1,669,655
Shares, Vested	(83,884)	(697,630)
Shares, Forfeited	(21,097)	(383,927)
Shares, Cancelled	(1,172,487)
Shares, Outstanding, Ending balance		1,277,468
Weighted Average Fair Value, Outstanding, Beginning balance	$ 0.69	$ 2.87
Weighted Average Fair Value, Granted		0.56
Weighted Average Fair Value, Vested	3.70	1.79
Weighted Average Fair Value, Forfeited	3.70	2.06
Weighted Average Fair Value, Cancelled	$ 0.41
Weighted Average Fair Value, Outstanding, Ending balance		$ 0.69

Fair Value of Financial Instr56

Fair Value of Financial Instruments - Schedule of Carrying Amount and Estimated Fair Value of Financial Instruments (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Financial liabilities:
Senior Notes		$ 130,000
Predecessor [Member]
Financial assets:
U.S. Treasury Bonds			$ 1,448
Fair Value [Member]
Financial assets:
Collateral Security account	$ 2,952
Derivative Assets	587
Financial liabilities:
Exit Credit Facility	140,320
Derivative Liability	10,633
Fair Value [Member] | Predecessor [Member]
Financial assets:
Collateral Security account			2,812
U.S. Treasury Bonds			1,448
Derivative Assets			11,081
Financial liabilities:
Fixed rate debentures			3,057
First Lien Credit Facility			234,665
Second Lien Credit Facility			74,912
Senior Notes			25,090
Carrying Amount[ Member]
Financial assets:
Collateral Security account	2,952
Derivative Assets	587
Financial liabilities:
Exit Credit Facility	140,320
Derivative Liability	$ 10,633
Carrying Amount[ Member] | Predecessor [Member]
Financial assets:
Collateral Security account			2,812
U.S. Treasury Bonds			1,636
Derivative Assets			11,081
Financial liabilities:
Fixed rate debentures			1,636
First Lien Credit Facility			234,665
Second Lien Credit Facility			74,912
Senior Notes			$ 165,368

Fair Value of Financial Instr57

Fair Value of Financial Instruments - Schedule of Assets and Liabilities, Including both Current and Non-Current Portions, Measured at Fair Value on a Recurring Basis (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current Liabilities
Derivative Financial Instruments	$ 6,313
Fair Value, Measurements, Recurring [Member]
Current Assets
Derivative Financial Instruments	587
Current Liabilities
Derivative Financial Instruments	6,313
Noncurrent Liabilities
Derivative Financial Instruments	4,320
Fair Value, Measurements, Recurring [Member] | Predecessor [Member]
Current Assets
U.S. Treasury Bonds-Available-For-Sale Securities		$ 1,448
Derivative Financial Instruments		11,081
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Predecessor [Member]
Current Assets
U.S. Treasury Bonds-Available-For-Sale Securities		1,448
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Current Assets
Derivative Financial Instruments	587
Current Liabilities
Derivative Financial Instruments	6,313
Noncurrent Liabilities
Derivative Financial Instruments	$ 4,320
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Predecessor [Member]
Current Assets
Derivative Financial Instruments		$ 11,081

Derivative Financial Instrume58

Derivative Financial Instruments - Summary of Open Financial Derivative Positions Related to Oil and Gas Production (Detail) - Long [Member]	12 Months Ended
	Dec. 31, 2016MMBTU / dbbl / d$ / bbl$ / Mcf
BRENT Oil [Member] | Collar 01/01/17 - 12/31/17 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Dec. 31, 2017
Volume | bbl / d	250
Price per Mcf or Bbl, Floor Price | $ / bbl	42
Price per Mcf or Bbl, Cap Price | $ / bbl	57.25
BRENT Oil [Member] | Collar 01/01/17 - 12/31/18 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Dec. 31, 2018
Volume | bbl / d	250
Price per Mcf or Bbl, Floor Price | $ / bbl	42
Price per Mcf or Bbl, Cap Price | $ / bbl	60
BRENT Oil [Member] | Collar 01/01/17 - 12/31/18 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Dec. 31, 2018
Volume | bbl / d	250
Price per Mcf or Bbl, Floor Price | $ / bbl	42
Price per Mcf or Bbl, Cap Price | $ / bbl	60.50
BRENT Oil [Member] | Collar 01/01/17 - 12/31/18 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Dec. 31, 2018
Volume | bbl / d	250
Price per Mcf or Bbl, Floor Price | $ / bbl	43
Price per Mcf or Bbl, Cap Price | $ / bbl	61.50
BRENT Oil [Member] | Collar 01/01/17 - 12/31/18 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Dec. 31, 2018
Volume | bbl / d	250
Price per Mcf or Bbl, Floor Price | $ / bbl	42
Price per Mcf or Bbl, Cap Price | $ / bbl	59.60
BRENT Oil [Member] | Swap 01/01/17 - 12/31/17 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Dec. 31, 2017
Volume | bbl / d	100
Price per Mcf or Bbl, Strike Price | $ / bbl	55.30
BRENT Oil [Member] | Swap 01/01/17 - 12/31/17 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Dec. 31, 2017
Volume | bbl / d	250
Price per Mcf or Bbl, Strike Price | $ / bbl	56.25
CIG Basis [Member] | Swap 01/01/17 - 03/31/19 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Mar. 31, 2019
Volume | MMBTU / d	7,500
Price per Mcf or Bbl, Spread On Index Strike Price | $ / Mcf	(0.36)
DTI Basis [Member] | Swap 01/01/17 - 03/31/17 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Mar. 31, 2017
Volume | MMBTU / d	10,000
Price per Mcf or Bbl, Spread On Index Strike Price | $ / Mcf	(0.86)
DTI Basis [Member] | Swap 01/01/17 - 03/31/19 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Mar. 31, 2019
Volume | MMBTU / d	10,000
Price per Mcf or Bbl, Spread On Index Strike Price | $ / Mcf	(0.98)
DTI Basis [Member] | Swap 01/01/17 - 03/31/19 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Mar. 31, 2019
Volume | MMBTU / d	10,000
Price per Mcf or Bbl, Spread On Index Strike Price | $ / Mcf	(1.04)
NYMEX Gas [Member] | Collar 01/01/17 - 12/31/17 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Dec. 31, 2017
Volume | MMBTU / d	15,000
Price per Mcf or Bbl, Floor Price | $ / Mcf	2.80
Price per Mcf or Bbl, Cap Price | $ / Mcf	3.10
NYMEX Gas [Member] | Collar 01/01/17 - 12/31/18 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Dec. 31, 2018
Volume | MMBTU / d	10,000
Price per Mcf or Bbl, Floor Price | $ / Mcf	2.80
Price per Mcf or Bbl, Cap Price | $ / Mcf	3.15
NYMEX Gas [Member] | Collar 01/01/18 - 12/31/18 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2018
Contract Period, Ending	Dec. 31, 2018
Volume | MMBTU / d	10,000
Price per Mcf or Bbl, Floor Price | $ / Mcf	2.80
Price per Mcf or Bbl, Cap Price | $ / Mcf	3.30
NYMEX Gas [Member] | Swap 01/01/17 - 03/31/18 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Mar. 31, 2018
Volume | MMBTU / d	10,000
Price per Mcf or Bbl, Strike Price | $ / Mcf	3.56
NYMEX Gas [Member] | Swap 01/01/17 - 07/31/17 [Member]
Derivative [Line Items]
Contract Period, Beginning	Jan. 1, 2017
Contract Period, Ending	Jul. 31, 2017
Volume | MMBTU / d	5,000
Price per Mcf or Bbl, Strike Price | $ / Mcf	3.55

Derivative Financial Instrume59

Derivative Financial Instruments - Summary of Amount of Gains (Losses) Recognized In Income from Derivative Instruments Not Designated as Hedging Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on hedges	$ (10,181)
Total gain (loss)	(10,874)
Predecessor [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on hedges		$ (10,947)	$ 7,076
Total gain (loss)		1,131	20,083
Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized cash settlements on hedges	(693)
Unrealized gain (loss) on hedges	(10,181)
Total gain (loss)	$ 10,874
Commodity Derivatives [Member] | Predecessor [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized cash settlements on hedges		11,741	13,007
Unrealized gain (loss) on hedges		(10,947)	7,076
Total gain (loss)		$ 794	$ 20,083

Derivative Financial Instrume60

Derivative Financial Instruments - Schedule of Fair Value and Balance Sheet Location of Net Derivatives (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Current Assets	$ 587
Current liabilities	6,313
Predecessor [Member]
Derivatives, Fair Value [Line Items]
Current Assets		$ 11,081
Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Current Assets	587
Current liabilities	6,313
Other long-term liabilities	4,320
Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member] | Predecessor [Member]
Derivatives, Fair Value [Line Items]
Current Assets		11,081
Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member]
Derivatives, Fair Value [Line Items]
Current liabilities	1,562
Other long-term liabilities	1,615
Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member] | Oil [Member] | Predecessor [Member]
Derivatives, Fair Value [Line Items]
Current Assets		3,265
Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Current Assets	587
Current liabilities	4,751
Other long-term liabilities	$ 2,705
Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | Predecessor [Member]
Derivatives, Fair Value [Line Items]
Current Assets		$ 7,816

Income Taxes - Schedule of Diff

Income Taxes - Schedule of Difference Between Company's Effective Income Tax Rate and Federal Statutory Rate (Detail) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes at Federal Statutory Rate	$ (51,112)	$ (56,818)	$ (210,781)
Change in Valuation Allowance	60,625	36,912	251,045
Nondeductible Expenses	(788)	4	(2,523)
State Income Taxes Net of Federal Benefit	(5,953)	(6,618)	(37,197)
Section 382 NOL Reduction		$ 26,520
Other	(2,648)		(527)
Total	$ 124		$ 17

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Deferred Tax Assets Relating To:
Net Operating Loss Carryforward	$ 159,636	$ 176,741	$ 130,816
Oil and Gas Properties and Tangible Equipment	195,957	219,440	228,324
Stock Option Expense		4,564	4,207
Unrealized Loss on Derivatives	4,036
Other	1,147	1,105	719
Total Gross Deferred Tax Assets	360,776	401,850	364,066
Less Valuation Allowance	360,553	401,800	359,510
Total Deferred Tax Asset	223	50	4,556
Deferred Tax Liabilities Relating To:
Unrealized Gain on Derivatives	(223)	(50)	(4,432)
Net Unrealized Gain on Investments			(124)
Total Deferred Tax Liability	(223)	(50)	(4,556)
Net Deferred Tax Asset (Liability)	$ 0	$ 0	$ 0

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2016
Income Taxes Disclosure [Line Items]
Increase (decrease) in valuation allowance	$ (41)	$ 42
Minimum [Member]
Income Taxes Disclosure [Line Items]
Operating loss and credit carryforwards period subject to examination and adjustments			3 years
Federal Income Tax [Member]
Income Taxes Disclosure [Line Items]
Operating loss carryforwards, amount	$ 421		$ 421

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)MMcf	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)$ / ItemMMcf	Dec. 31, 2015USD ($)
Long-term Purchase Commitment [Line Items]
Lease expiration date			2022-04
Rent expense	$ 100,000
Bankruptcy claims amount	1,500,000		$ 1,500,000
Exit Credit Facility [Member]
Long-term Purchase Commitment [Line Items]
Outstanding balance	$ 140,300,000		140,300,000
Transportation Fees [Member]
Long-term Purchase Commitment [Line Items]
Monthly payment			$ 1,241,000
Threshold for additional fees, volume of gas per day | MMcf			120,000
Contract remaining period	36 months		67 months
Transportation overage fee (per dekatherm) | $ / Item			0.34
Transportation overage fees			$ 0
Reduced threshold for additional fees, volume of gas per day | MMcf	90,000
Predecessor [Member]
Long-term Purchase Commitment [Line Items]
Rent expense		$ 800,000		$ 1,100,000

Commitments and Contingencies65

Commitments and Contingencies - Schedule of Future Minimum Annual Rental Payments which are Subject to Escalation and Include Utility Charges (Detail) $ in Thousands	Dec. 31, 2016USD ($)
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,017	$ 349
2,018	438
2,019	384
2,020	393
2,021	401
Thereafter	134
Total	$ 2,099

Oil and Gas Information - Sched

Oil and Gas Information - Schedule of Costs Related to the Oil and Gas Activities Incurred (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition-unproved	$ 0
Development costs	5,052
Total costs related to oil and gas activities	$ 5,052
Predecessor [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition-unproved		$ 0
Property acquisition-proved		18,626
Exploration costs		3
Development costs		17,359
Total costs related to oil and gas activities		$ 35,988

Oil and Gas Information - Addit

Oil and Gas Information - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Increase in asset retirement cost	$ 0.6	$ 0.1

Oil and Gas Information - Sch68

Oil and Gas Information - Schedule of Aggregate Capitalized Costs Relating to the Company's Oil and Gas Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved oil and gas properties	$ 222,655
Gross capitalized costs	222,655
Less accumulated depreciation, depletion and impairment expense	(154,292)
Total aggregate capitalized costs relating to oil and gas activities	$ 68,363
Predecessor [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties		$ 14,658
Proved oil and gas properties		1,125,297
Gross capitalized costs		1,139,955
Less accumulated depreciation, depletion and impairment expense		(977,270)
Total aggregate capitalized costs relating to oil and gas activities		$ 162,685

Oil and Gas Information - Sch69

Oil and Gas Information - Schedule of the Company's Results of operations from Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 30, 2016	Sep. 30, 2016	Dec. 31, 2015
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues	$ 16,862
Production costs	(10,678)
Accretion of asset retirement obligation	(1,277)
Impairment	(145,117)
Depreciation, depletion, amortization	(9,175)
Loss from oil and gas producing activities	$ (149,385)
Predecessor [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues		$ 39,712	$ 83,734
Production costs		(32,611)	(49,557)
Accretion of asset retirement obligation		(2,248)	(2,857)
Impairment		(87,094)	(562,151)
Depreciation, depletion, amortization		(15,128)	(59,729)
Loss from oil and gas producing activities		$ (97,369)	$ (590,560)

Oil and Gas Information - Summa

Oil and Gas Information - Summary of Warren's Oil and Gas Properties Not Subject to Amortization (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	$ 0
Exploration costs	$ 0
Predecessor [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs		$ 0
Exploration costs		0
Development costs		365
Total oil and gas properties not subject to amortization		$ 365

Oil and Gas Information - Sum71

Oil and Gas Information - Summary of Warren's Oil and Gas Properties Not Subject to Amortization (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2016
Minimum [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Expected drilling period of wells	5 years
Maximum [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Expected drilling period of wells	8 years

Oil and Gas Reserve Data (Una72

Oil and Gas Reserve Data (Unaudited) - Schedule of Summary of Changes in Proved Reserves (Detail)	12 Months Ended
	Dec. 31, 2016MBoeMBblsMMcf	Dec. 31, 2015MBoeMBblsMMcf	Dec. 31, 2016MBoeMBblsMMcf	Dec. 31, 2015MBoeMBblsMMcf
Reserve Quantities [Line Items]
Beginning of year	40.2
Purchases of oil and gas reserves in place	0
Revisions of previous estimates	(10,267)
Production	(4,593)
End of year	25,368	40.2
Proved developed reserves			23,127
Proved undeveloped reserves			2,241
Proved developed and undeveloped reserves	25,368	40.2	25,368	40.2
Oil [Member]
Reserve Quantities [Line Items]
Purchases of oil and gas reserves in place | MBbls	0
Revisions of previous estimates | MBbls	(7,413)
Production | MBbls	(794)
End of year | MBbls	4,732
Proved developed reserves | MBbls			4,008
Proved undeveloped reserves | MBbls			724
Proved developed and undeveloped reserves | MBbls	4,732		4,732
Natural Gas [Member]
Reserve Quantities [Line Items]
Purchases of oil and gas reserves in place | MMcf	0
Revisions of previous estimates | MMcf	(17,124)
Production | MMcf	(22,791)
End of year | MMcf	123,816
Proved developed reserves | MMcf			114,719
Proved undeveloped reserves | MMcf			9,097
Proved developed and undeveloped reserves | MMcf	123,816		123,816
Predecessor [Member]
Reserve Quantities [Line Items]
Beginning of year	40,227	71,348
Purchases of oil and gas reserves in place		0
Discoveries and extensions		845
Revisions of previous estimates		(26,314)
Production		(5,652)
End of year		40,227
Proved developed reserves				32,339
Proved undeveloped reserves				7,888
Proved developed and undeveloped reserves	40,227	71,348		40,227
Predecessor [Member] | Oil [Member]
Reserve Quantities [Line Items]
Beginning of year | MBbls	12,939	16,794
Purchases of oil and gas reserves in place | MBbls		0
Discoveries and extensions | MBbls		69
Revisions of previous estimates | MBbls		(2,944)
Production | MBbls		(980)
End of year | MBbls		12,939
Proved developed reserves | MBbls				6,824
Proved undeveloped reserves | MBbls				6,115
Proved developed and undeveloped reserves | MBbls	12,939	16,794		12,939
Predecessor [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of year | MMcf	163,731	327,328
Purchases of oil and gas reserves in place | MMcf		0
Discoveries and extensions | MMcf		4,654
Revisions of previous estimates | MMcf		(140,218)
Production | MMcf		(28,033)
End of year | MMcf		163,731
Proved developed reserves | MMcf				153,093
Proved undeveloped reserves | MMcf				10,638
Proved developed and undeveloped reserves | MMcf	163,731	327,328		163,731

Oil and Gas Reserve Data (Una73

Oil and Gas Reserve Data (Unaudited) - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MBoe$ / bbl$ / McfBcfMMBbls	Dec. 31, 2015USD ($)MBoeMMBoe$ / bbl$ / McfBcfMMBbls
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves (Energy) | MBoe	25,368	40.2
Maximum period proved reserves to be drilled		5 years
Undeveloped reserves transferred to developed reserves | MMBoe		0.8
Capital costs of conversion of proved undeveloped reserves to proved developed reserves		$ 12.9
Oil prices weighted by production over lives of proved reserves | $ / bbl	33.39	42.81
Gas prices weighted by production over lives of proved reserves | $ / Mcf	1.59	1.74
Future cash flows estimated to be spent to develop proved undeveloped properties	$ 25.2
Wyoming [Member]
Reserve Quantities [Line Items]
Percentage of proved reserves	10.00%
Increase (decrease) in total value of proved reserves	$ (7.4)
Total value of the proved reserves	$ 8	$ 15.4
Pennsylvania [Member]
Reserve Quantities [Line Items]
Percentage of proved reserves	10.00%
Increase (decrease) in total value of proved reserves	$ 12.6
Total value of the proved reserves	$ 7	(5.6)
California [Member]
Reserve Quantities [Line Items]
Percentage of proved reserves	10.00%
Increase (decrease) in total value of proved reserves	$ (73)
Total value of the proved reserves	$ 12.9	$ 85.9
Oil [Member]
Reserve Quantities [Line Items]
Year-end net upward (downward) revision | MMBbls	7.4	(2.9)
Year-end upward (downward) revision due to pricing | MMBbls		(2.2)
Year-end upward (downward) revision due to performance | MMBbls		(0.7)
Year-end upward (downward) revision due to discoveries and extensions | MMBbls		0.07
Oil [Member] | California [Member]
Reserve Quantities [Line Items]
Percentage of increase (decrease) in total proved reserves	(58.00%)
Natural Gas [Member]
Reserve Quantities [Line Items]
Year-end net upward (downward) revision | Bcf	16.9	(140)
Year-end upward (downward) revision due to pricing | Bcf		(124)
Year-end upward (downward) revision due to performance | Bcf		(16)
Natural Gas [Member] | Marcellus Shale in Pennsylvania [Member]
Reserve Quantities [Line Items]
Discoveries and extensions | Bcf		4.7
Natural Gas [Member] | Wyoming [Member]
Reserve Quantities [Line Items]
Percentage of increase (decrease) in total proved reserves	(53.00%)
Proved Developed and Producing Reserves [Member] | Wyoming [Member]
Reserve Quantities [Line Items]
Percentage of increase (decrease) in total proved reserves	(10.00%)
Proved Developed and Producing Reserves [Member] | Pennsylvania [Member]
Reserve Quantities [Line Items]
Percentage of increase (decrease) in total proved reserves	17.00%
Proved Developed and Producing Reserves [Member] | California [Member]
Reserve Quantities [Line Items]
Percentage of increase (decrease) in total proved reserves	(33.00%)
Proved Developed Non Producing Reserves [Member] | Wyoming [Member]
Reserve Quantities [Line Items]
Percentage of increase (decrease) in total proved reserves	(20.00%)
Proved Developed Non Producing Reserves [Member] | California [Member]
Reserve Quantities [Line Items]
Percentage of increase (decrease) in total proved reserves	(25.00%)
Proved Undeveloped Category [Member] | Wyoming [Member]
Reserve Quantities [Line Items]
Percentage of increase (decrease) in total proved reserves	(100.00%)
Proved Undeveloped Category [Member] | California [Member]
Reserve Quantities [Line Items]
Percentage of increase (decrease) in total proved reserves	(88.00%)

Oil and Gas Reserve Data (Una74

Oil and Gas Reserve Data (Unaudited) - Schedule of Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 354,611
Future production costs and taxes	(264,246)
Future development costs	(66,605)
Future income tax expenses	0
Net future cash flows	23,760
Discounted at 10% for estimated timing of cash flows	4,595
Standardized measure of discounted future net cash flows	$ 28,355	$ 96,023
Predecessor [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows		862,751
Future production costs and taxes		(503,702)
Future development costs		(180,790)
Future income tax expenses		0
Net future cash flows		178,259
Discounted at 10% for estimated timing of cash flows		(82,236)
Standardized measure of discounted future net cash flows		$ 96,023	$ 555,067

Oil and Gas Reserve Data (Una75

Oil and Gas Reserve Data (Unaudited) - Schedule of Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Asset retirement obligations	$ 53.6	$ 55.8

Oil and Gas Reserve Data (Una76

Oil and Gas Reserve Data (Unaudited) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Sales, net of production costs and taxes	$ (13,286)
Purchases of reserves in place	0
Changes in prices and production costs	(108,350)
Revisions of quantity estimates	(51,108)
Development costs incurred	1,807
Net changes in development costs	74,142
Interest factor-accretion of discount	12,632
Changes in production rates (timing) and other	16,495
Net (decrease) increase	(67,668)
Balance at beginning of year	96,023
Balance at end of year	28,355	$ 96,023
Predecessor [Member]
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Sales, net of production costs and taxes		(34,176)
Discoveries and extensions		2,540
Purchases of reserves in place		0
Changes in prices and production costs		(342,650)
Revisions of quantity estimates		(202,716)
Development costs incurred		12,869
Net changes in development costs		131,919
Interest factor-accretion of discount		55,506
Net change in income taxes		(54,059)
Changes in production rates (timing) and other		(28,277)
Net (decrease) increase		(459,044)
Balance at beginning of year	$ 96,023	555,067
Balance at end of year		$ 96,023