Amplify Energy (AMPY) 10-K 14 Mar 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Mar. 11, 2019	Jun. 30, 2018
Document and Entity Information
Entity Registrant Name	Midstates Petroleum Company, Inc.
Entity Central Index Key	0001533924
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 176.8
Entity Common Stock, Shares Outstanding		20,413,835
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
CURRENT ASSETS:
Cash and cash equivalents	$ 11,341	$ 68,498
Accounts receivable:
Oil and gas sales	22,165	32,455
Joint interest billing	2,474	3,297
Other	1,374	166
Commodity derivative contracts	6,940	762
Other current assets	1,684	1,510
Total current assets	45,978	106,688
Oil and gas properties, on the basis of full-cost accounting
Proved properties	809,272	765,308
Unproved properties not being amortized	4,050	7,065
Other property and equipment	6,345	6,508
Less accumulated depreciation, depletion, amortization and impairment	(266,198)	(204,419)
Net property and equipment	553,469	574,462
OTHER NONCURRENT ASSETS:
Commodity derivative assets	791
Other noncurrent assets	5,257	6,978
Total other noncurrent assets	6,048	6,978
TOTAL	605,495	688,128
CURRENT LIABILITIES:
Accounts payable	6,511	11,547
Accrued liabilities	25,521	42,842
Commodity derivative contracts		3,433
Total current liabilities	32,032	57,822
LONG-TERM LIABILITIES:
Asset retirement obligations	8,087	15,506
Commodity derivative contracts	80	562
Long-term debt	23,059	128,059
Other long-term liabilities	560	592
Total long-term liabilities	31,786	144,719
COMMITMENTS AND CONTINGENCIES (Note 17)
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value, 50,000,000 shares authorized; no shares issued or outstanding at December 31, 2018 and 2017
Warrants, 6,625,554 warrants outstanding at December 31, 2018 and 2017	37,329	37,329
Common stock, $0.01 par value, 250,000,000 shares authorized; 25,520,170 shares issued and 25,345,981 shares outstanding at December 31, 2018; and 25,272,969 shares issued and 25,173,346 shares outstanding at December 31, 2017	255	253
Treasury stock	(2,455)	(1,603)
Additional paid-in-capital	531,911	524,755
Retained deficit	(25,363)	(75,147)
Total stockholders' equity	541,677	485,587
TOTAL	$ 605,495	$ 688,128

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
CONSOLIDATED BALANCE SHEETS
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Warrants outstanding	6,625,554	6,625,554
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	250,000,000	250,000,000
Common Stock, shares issued (in shares)	25,520,170	25,272,969
Common stock, shares outstanding	25,345,981	25,173,346

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2018	Dec. 31, 2017
REVENUES:
Gains on commodity derivative contracts-net			$ 3,555	$ 3,659
Revenues, Total	$ 48,525		208,637	228,753
EXPENSES:
Lease operating and workover	15,324		54,229	63,287
Gathering and transportation (Note 5)	3,194		241	14,507
Severance and other taxes	1,286		11,680	8,869
Asset retirement accretion	210		846	1,100
Depreciation, depletion, and amortization	12,974		62,000	65,832
Impairment in carrying value of oil and gas properties				125,300
General and administrative	4,864		24,540	29,352
Debt restructuring costs and advisory fees			850
Total expenses	37,852		154,386	308,247
OPERATING INCOME (LOSS)	10,673		54,251	(79,494)
OTHER INCOME (EXPENSE):
Interest income			33	9
Interest expense-net of amounts capitalized (Predecessor Period excludes interest expense of $89.5 million on senior and secured notes)	(743)		(4,500)	(5,592)
Total other income (expense)	(743)		(4,467)	(5,583)
INCOME (LOSS) BEFORE TAXES	9,930		49,784	(85,077)
NET INCOME (LOSS)	9,930		49,784	(85,077)
Participating securities-non-vested restricted stock	(280)		(1,394)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 9,650		$ 48,390	$ (85,077)
Basic and diluted net income (loss) per share attributable to common shareholders	$ 0.39		$ 1.91	$ (3.39)
Basic and diluted weighted average number of common shares outstanding (Note 15)	25,009		25,337	25,119
Revenue from contracts with customers
REVENUES:
Revenues, Total	$ 48,525		$ 205,082	$ 225,094
Oil
REVENUES:
Revenues, Total	25,549		123,945	117,083
Natural gas liquid
REVENUES:
Revenues, Total	8,391		44,747	44,112
Natural gas
REVENUES:
Revenues, Total	13,635		32,138	59,708
Other
REVENUES:
Revenues, Total	$ 950		$ 4,252	$ 4,191
Predecessor
REVENUES:
Revenues, Total		$ 193,228
EXPENSES:
Lease operating and workover		52,803
Gathering and transportation (Note 5)		14,362
Severance and other taxes		5,210
Asset retirement accretion		1,414
Depreciation, depletion, and amortization		62,302
Impairment in carrying value of oil and gas properties		232,108
General and administrative		22,362
Debt restructuring costs and advisory fees		7,590
Total expenses		398,151
OPERATING INCOME (LOSS)		(204,923)
OTHER INCOME (EXPENSE):
Interest income		81
Interest expense-net of amounts capitalized (Predecessor Period excludes interest expense of $89.5 million on senior and secured notes)		(66,360)
Reorganization items, net (Note 3)		1,594,281
Total other income (expense)		1,528,002
INCOME (LOSS) BEFORE TAXES		1,323,079
NET INCOME (LOSS)		1,323,079
Participating securities-non-vested restricted stock		(16,522)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		$ 1,306,557
Basic and diluted net income (loss) per share attributable to common shareholders		$ 122.74
Basic and diluted weighted average number of common shares outstanding (Note 15)		10,645
Predecessor | Revenue from contracts with customers
REVENUES:
Revenues, Total		$ 193,228
Predecessor | Oil
REVENUES:
Revenues, Total		112,628
Predecessor | Natural gas liquid
REVENUES:
Revenues, Total		27,473
Predecessor | Natural gas
REVENUES:
Revenues, Total		48,318
Predecessor | Other
REVENUES:
Revenues, Total		$ 4,809

CONSOLIDATED STATEMENTS OF OP_2

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) $ in Millions	10 Months Ended
	Oct. 20, 2016USD ($)
Predecessor
Interest expense on senior and secured notes	$ 89.5

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT) - USD ($) $ in Thousands	Common Stock	Warrants	Treasury Stock	Additional Paid-in-Capital	Retained Earnings (Deficit)	Total
Balance at Dec. 31, 2015	$ 110		$ (3,081)	$ 888,247	$ (2,211,342)	$ (1,326,066)
Increase (Decrease) in Stockholders' Equity
Share-based compensation	(6)			3,045		3,039
Acquisition of treasury stock | Predecessor			(53)			(53)
Net income (loss) | Predecessor					1,323,079	1,323,079
Balance (Predecessor) at Oct. 20, 2016	104		(3,134)	891,292	(888,263)	(1)
Increase (Decrease) in Stockholders' Equity
Cancellation of predecessor equity | Predecessor	(104)		3,134	(891,292)	888,263	1
Issuance of successor common stock | Predecessor	247			510,905		511,152
Issuance of successor warrants | Predecessor		$ 37,329				37,329
Balance at Oct. 21, 2016	247	37,329		510,905		548,481
Balance (Predecessor) at Oct. 20, 2016	104		(3,134)	891,292	(888,263)	(1)
Increase (Decrease) in Stockholders' Equity
Share-based compensation				3,400		3,400
Issuance of successor common stock	3					3
Net income (loss)					9,930	9,930
Balance at Dec. 31, 2016	250	37,329		514,305	9,930	561,814
Increase (Decrease) in Stockholders' Equity
Share-based compensation			(1,603)			(1,603)
Issuance of successor common stock	3			10,450		10,453
Net income (loss)					(85,077)	(85,077)
Balance at Dec. 31, 2017	253	37,329	(1,603)	524,755	(75,147)	485,587
Increase (Decrease) in Stockholders' Equity
Share-based compensation	2			7,156		7,158
Acquisition of treasury stock			(852)			(852)
Net income (loss)					49,784	49,784
Balance at Dec. 31, 2018	$ 255	$ 37,329	$ (2,455)	$ 531,911	$ (25,363)	$ 541,677

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2018	Dec. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 9,930		$ 49,784	$ (85,077)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Gains (losses) on commodity derivative contracts - net			(3,555)	(3,659)
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments			(7,328)	6,891
Asset retirement accretion	210		846	1,100
Depreciation, depletion, and amortization	12,974		62,000	65,832
Impairment in carrying value of oil and gas properties				125,300
Share-based compensation, net of amounts capitalized to oil and gas properties	2,909		5,407	9,196
Amortization of deferred financing costs	63		476	385
Change in operating assets and liabilities:
Accounts receivable - oil and gas sales	(115)		8,690	2,766
Accounts receivable - JIB and other	(1,812)		(744)	3,362
Other current and noncurrent assets	1,783		537	283
Accounts payable	(1,555)		(1,779)	2,961
Accrued liabilities	(740)		(7,145)	(8,973)
Other	(3)		(34)	(765)
Net cash provided by operating activities	23,644		107,155	119,602
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(23,346)		(112,398)	(130,199)
Proceeds from the sale of oil and gas properties			54,091	2,885
Proceeds from the sale of oil and gas equipment			355	1,350
Net cash used in investing activities	(23,346)		(57,952)	(125,964)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility			1,000
Repayment of revolving credit facility			(106,000)
Deferred financing costs			(508)	(375)
Repurchase of restricted stock for tax withholdings			(852)	(1,603)
Net cash (used in) provided by financing activities			(106,360)	(1,978)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	298		(57,157)	(8,340)
Cash and cash equivalents, beginning of period	76,540		68,498	76,838
Cash and cash equivalents, end of period	76,838	$ 76,540	$ 11,341	$ 68,498
Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		1,323,079
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Asset retirement accretion		1,414
Depreciation, depletion, and amortization		62,302
Impairment in carrying value of oil and gas properties		232,108
Share-based compensation, net of amounts capitalized to oil and gas properties		2,564
Amortization of deferred financing costs		4,587
Paid-in-kind interest expense		3,531
Amortization of deferred gain on debt restructuring		(8,246)
Operating lease abandonment		1,574
Non-cash reorganization items		(1,630,873)
Change in operating assets and liabilities:
Accounts receivable - oil and gas sales		(2,391)
Accounts receivable - JIB and other		22,002
Other current and noncurrent assets		(5,868)
Accounts payable		1,797
Accrued liabilities		55,160
Other		(743)
Net cash provided by operating activities		61,997
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment		(133,307)
Net cash used in investing activities		(133,307)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility		249,384
Repayment of long-term borrowings		(60,000)
Repayment of revolving credit facility		(121,324)
Deferred financing costs		(1,250)
Repurchase of restricted stock for tax withholdings		(53)
Net cash (used in) provided by financing activities		66,757
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(4,553)
Cash and cash equivalents, beginning of period	$ 76,540	81,093
Cash and cash equivalents, end of period		$ 76,540

Organization and Business

Organization and Business	12 Months Ended
	Dec. 31, 2018
Organization and Business
Organization and Business	1. Organization and Business Midstates Petroleum Company, Inc. engages in the business of drilling for, and the production of, oil, natural gas liquids (“NGLs”) and natural gas in Oklahoma. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”), which was previously a wholly‑owned subsidiary of Midstates Petroleum Holdings LLC (“Holdings LLC”). Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Midstates Petroleum Company, Inc.’s initial public offering, all of the interests in Midstates Petroleum Holdings LLC were exchanged for newly issued common shares of Midstates Petroleum Company, Inc., and as a result, Midstates Petroleum Company LLC became a wholly‑owned subsidiary of Midstates Petroleum Company, Inc. and Midstates Petroleum Holdings LLC ceased to exist as a separate entity. The terms “Company,” “we,” “us,” “our,” and similar terms when used in the present tense, prospectively or for historical periods since April 25, 2012, refer to Midstates Petroleum Company, Inc. and its subsidiary. On February 3, 2016, the Company received notice from the New York Stock Exchange (“NYSE”) that the Company’s common stock no longer met the NYSE continued listing requirements. As a result, the Company’s common stock was automatically delisted from the NYSE and began trading on an over the counter exchange under the symbol “MPOY”. On April 30, 2016, the Company filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code. On October 21, 2016, in connection with the Company’s emergence from Chapter 11, its existing common shares traded under the symbol MPOY were cancelled and on October 24, 2016, its new common shares issued in connection with the successful reorganization and emergence from Chapter 11 were listed and began trading on the NYSE MKT under the symbol “MPO”. On May 4, 2017, the Company’s common stock began trading on the NYSE under the symbol “MPO”. On May 31, 2018, the Company closed on the sale of its Anadarko Basin assets for $58.0 million in cash ($54.1 million, net of closing adjustments). The net proceeds were reflected as a reduction of oil and natural gas properties, with no gain or loss recognized as the sale did not result in a significant alteration of the full cost pool. The Company used $50.0 million of the net proceeds from the sale of the Anadarko Basin assets to pay down a portion of outstanding borrowings under the Company’s reserves based revolving credit facility (the “Exit Facility”) and retained the remainder for general corporate purposes.

Emergence from Voluntary Reorga

Emergence from Voluntary Reorganization under Chapter 11 Proceedings	12 Months Ended
	Dec. 31, 2018
Emergence from Voluntary Reorganization under Chapter 11 Proceedings
Emergence from Voluntary Reorganization under Chapter 11 Proceedings	2. Emergence from Voluntary Reorganization under Chapter 11 Proceedings On April 30, 2016 (the “Petition Date”), the Company filed voluntary petitions for reorganization 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”). The Company’s Chapter 11 cases (the “Chapter 11 Cases”) were jointly administered under the case styled In re Midstates Petroleum Company, Inc., et al., Case No. 16-32237 . On September 28, 2016, the Bankruptcy Court entered the Findings of Fact, Conclusions of Law, and Order Confirming Debtors’ First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate (the “Confirmation Order”), which approved and confirmed the First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate as filed on the same date (the “Plan”). On October 21, 2016 (the “Effective Date”), the Company satisfied the conditions to effectiveness set forth in the Confirmation Order and in the Plan, and, as a result, the Plan became effective in accordance with its terms and the Company emerged from the Chapter 11 Cases. Plan of Reorganization Pursuant to the confirmed Plan, the significant transactions that occurred upon the Effective Date were as follows: · Substantial Deleveraging of the Balance Sheet: (i) The permanent pay-down of $81.3 million of the Company’s RBL, with a $170.0 million Exit Facility established upon the Effective Date, (ii) the pay-down of $60.0 million of the Company’s Second Lien Notes in cash and (iii) the conversion into equity of all of the Company’s remaining debt junior to the RBL; · Credit Facility Claims: Holders of allowed claims arising under the RBL (the “Credit Facility Claims”) received their pro-rata share of approximately $81.3 million in cash and the RBL was superseded, pursuant to the Plan, by the Exit Facility, as further described below; · Second Lien Notes Claims: Holders of allowed claims arising under the Second Lien Notes (the “Second Lien Notes Claims”) received their pro-rata share of (i) 96.25% of the reorganized equity in the form of common stock and (ii) a cash payment of $60.0 million; · Third Lien Notes Claims: Holders of allowed claims arising under the Third Lien Notes (the “Third Lien Notes Claims”), pursuant to a settlement with holders of Second Lien Notes Claims on terms more fully set forth in the Plan (the “Second/Third Lien Plan Settlement”), received their pro-rata share of 2.5% of the reorganized equity in the form of common stock and warrants to acquire 4,411,765 shares of common stock at a strike price of $24.00 per common share with an expiration date 42 months after the Effective Date; · Unsecured Claims: Holders (the “Unsecured Noteholders”) of allowed claims arising under the Debtors’ 10.75% Senior Unsecured Notes due 2020 (the “2020 Notes Claims”), the holders of allowed claims arising under the 9.25% Senior Unsecured Notes due 2021 (the “2021 Notes Claims” and together with the 2020 Notes Claims, the “Unsecured Notes Claims”), and the Holders of other general unsecured claims received their pro-rata share of 1.25% of reorganized equity in the form of common stock and warrants to acquire 2,213,789 shares of common stock (the “Unencumbered Assets Equity Distribution”) at a strike price of $46.00 per common share with an expiration date 42 months after the Effective Date; · Existing Equity: All existing equity interests were extinguished and existing equity holders did not receive any consideration in respect of their equity interests; · New Equity: On the Effective Date, the Company issued 24,687,500 shares of common stock of the reorganized Company. On November 9, 2016, the Company issued an additional 294,967 shares of common stock of the reorganized Company pursuant to the Plan. At the Effective Date, the Company was obligated to issue 17,533 additional common sharespursuant to the Plan. The total authorized reorganized capital stock consists of 250,000,000 shares of common stock and 50,000,000 shares of preferred stock; · Exit Facility: The Company’s RBL, which was redetermined with a borrowing base of $170.0 million in April 2016, was superseded, pursuant to the Plan, by the Exit Facility. See “—Note 11. Debt” for further information regarding the Exit Facility; and · Long-Term Incentive Plan: A management equity incentive plan (the “2016 LTIP”) was established under which 10.0% of the reorganized equity (on a fully-diluted/fully-distributed basis) was reserved for grants to be made from time to time to the directors, officers, and other members of management.

Fresh Start Accounting

Fresh Start Accounting	12 Months Ended
	Dec. 31, 2018
Fresh Start Accounting
Fresh Start Accounting	3. Fresh Start Accounting Upon emergence on the Effective Date, the Company adopted fresh start accounting as required by generally accepted accounting principles in the United States (“US GAAP”). The Company qualified for fresh start accounting because (i) the holders of existing voting shares of the pre-emergence debtor-in-possession received less than 50% of the voting shares of the post-emergence successor entity and (ii) the reorganization value of the Company’s assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims. The Company applied fresh start accounting as of October 21, 2016, the Effective Date. Adopting fresh start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit. The cancellation of all existing shares outstanding on the Effective Date and issuance of new shares in the reorganized Company caused a related change of control under US GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, the Company’s consolidated financial statements on or after October 21, 2016, are not comparable with the consolidated financial statements prior to that date. References to “Successor Period” relate to the financial position and results of operations for the period October 21, 2016 through December 31, 2016 and references to “Predecessor Period” refer to the financial position and results of operations of the Company from January 1, 2016 through October 20, 2016. Reorganization Value Reorganization value represents the fair value of the Company’s total assets prior to the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the Company’s assets immediately after restructuring. The reorganization value was allocated to the Company’s individual assets based on their estimated fair values. The Company's reorganization value was derived from its enterprise value. Enterprise value represents the estimated fair value of an entity's long-term debt and equity. The enterprise value of the Company on the Effective Date, as approved by the Bankruptcy Court in support of the Plan, was estimated to be within a range of $500.0 million to $700.0 million, with a mid-point value of $600.0 million. Based upon the various estimates and assumptions necessary for fresh start accounting, as further discussed below, the estimated enterprise value was determined to be $600.0 million before consideration of cash and cash equivalents and outstanding debt at the Effective Date. As a result, the reorganization value was determined to be $751.3 million at the Effective Date, as reconciled below. Valuation of Oil and Gas Properties The Company’s principal assets are its oil and gas properties, which the Company accounts for under the full cost accounting method as described in “—Note 4. Summary of Significant Accounting Policies”. With the assistance of valuation experts, the Company determined the fair value of its oil and gas properties based on the discounted net cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the Effective Date. The foundation for the computation of the fair value of the Company was a reserves report prepared by its independent reserve auditors. The engineering assumptions contained within this reserves report were consistent with both (i) previous engineering assumptions made by the Company when preparing reserve reports in prior years and (ii) assumptions promulgated by the Securities and Exchange Commission (“SEC”). These assumptions include type curves and analogous reservoir characteristics determined utilizing electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data, among others. Upon completion of the Company’s reserves report, it utilized outside third-party experts to assist management in the preparation of a valuation report utilizing assumptions consistent with a market participant. This valuation report utilized the income approach in determining the fair value of the Company’s oil and gas reserves, excluding possible reserves, for which the market approach was utilized. The income approach involves the projection of cash flows a market participant would expect an asset or business to generate over its remaining useful life. Cash flows are projected on an annual basis for a discrete period of time and then converted to their present value using a rate of return that captures the relevant risk of achieving the projected cash flows. Finally, the present value of the residual value, or terminal value, is added to these discrete cash flows to arrive at the estimate of total value. The market approach measures value through the use of prices, market multiples and other relevant information involving identical or comparable assets or business interests. The significant assumptions utilized within the valuation report included the following: · Pricing — The Company utilized pricing based on the six year New York Mercantile Exchange strip as of the Effective Date. NGL prices were based upon a historical percentage correlation of the price of West Texas Intermediate to the price of a Y-grade barrel. Prices beyond six years were escalated at 2.0% to account for inflation. Price differentials that have been calculated utilizing historical results were applied to account for quality and transportation differentials. · Weighted-Average Cost of Capital (“WACC”)—The WACC reflects the required return of capital providers, both debt and equity. Eight guideline companies were selected that had operations in the Mid-Continent area and were organized as C-corporations. A cost of equity was calculated using a capital asset pricing model, in which the cost of equity equals a risk-free rate plus a risk premium that is reflective of the asset or business interest. The risk free rate utilized was 2.2% based upon the normalized 20-year U.S. Treasury Bond rate as of the Effective Date. The risk premium was calculated utilizing three primary inputs. First, a beta was determined based upon the respective two-year weekly betas for each guideline company, adjusted for debt of their capital structures and then re-levered using the selected Company capital structure. Next, a market risk premium of 6.0% was utilized based upon industry data. Finally, a size premium of 3.6% was applied based upon the size of the interest in the assets of the Company utilizing industry data. A cost of debt was then calculated to be approximately 7.0% based upon the weighted average energy yield of the guideline companies at the Effective Date and then adjusted for a 35.0% tax effective to arrive at an estimated after-tax cost of debt of 4.6%. Based upon these inputs, the capital asset pricing model arrived at a WACC of 11.0%, which was utilized by the Company in its determination of fair value. · Operating and Other Costs—Operating costs from the reserves report prepared by the Company were escalated by 2.0% to account for inflation. Ad valorem and production taxes were estimated as a percentage of revenue and applied to the forward price adjusted revenues. Corporate general and administrative costs were estimated based a blend of historical general and administrative expenses and forecasts of such expenses for the next five years. Corporate general and administrative expenses were escalated at 2.0% after five years to account for inflation. · Capital Expenditures—Capital expenditures were based upon the average historical capital expended by the Company in the development of its wells and were escalated by 2.0% to account for inflation. · Possible Reserves—The Company utilized the guideline transaction method to determine the value of possible reserve acreage. In determining the value of possible reserve acreage, the Company utilized data from widely utilized industry sources as well as data from other relevant transactions in the area. These industry sources publish oil and gas lease data compiled from private transactions, federal oil and gas lease sales as well as state oil and gas lease sales. The Company then utilized this data to arrive at a range of acreage values for each county. Based upon the analysis completed by the Company with the assistance of outside third-party valuation experts, it concluded the fair value of its proved reserves was $539.0 million and the value of its probable and possible reserves, characterized as unproved properties, was $66.2 million as of the Effective Date. The following table presents the estimated fair value of the Company’s stock as of the Effective Date (in thousands, except per share value): As of October 21, 2016 Enterprise value $ 600,000 Plus: Cash and cash equivalents 76,540 Less: Fair value of debt (128,059) Less: Fair value of warrants (37,329) Fair value of stock on the Effective Date $ 511,152 Total shares issuable under the Plan 25,000 Restricted shares granted under 2016 LTIP at October 21, 2016 686 Total shares 25,686 Per share value (1) $ 19.90 (1) The per share value shown above was calculated based upon the financial information determined using US GAAP at the Effective Date. The fair value per share agreed upon by the parties to the Chapter 11 Cases at the Effective Date was determined to be $19.66 per common share. On the Effective Date, the Company entered into (i) a warrant agreement with holders of Allowed Third Lien Notes Claims (the “Third Lien Notes Warrant Agreement”) with respect to third lien warrants (the “Third Lien Notes Warrants”) and (ii) a warrant agreement with holders of Allowed Unsecured Notes Claims and Allowed General Unsecured Claims (the “Unsecured Creditor Warrant Agreement”, and together with the Third Lien Notes Warrant Agreement, the “Warrant Agreements”) with respect to warrants (the “Unsecured Creditor Warrants”, and together with the Third Lien Notes Warrants, the “Warrants”). At the Effective Date, the Company issued 4,411,765 Third Lien Notes Warrants allowing for the purchase of up to an aggregate of 4,411,765 shares of common stock at an initial exercise price of $24.00 per share, and 2,213,789 Unsecured Creditor Warrants allowing for the purchase of up to an aggregate of 2,213,789 shares of common stock at an initial exercise price of $46.00 per share. The Warrants expire on April 21, 2020. The Company utilized the Black-Scholes-Merton option pricing model to determine the fair value of the Warrants. Determining the fair value of the Warrants required judgment, including estimating the expected term and the associated volatility. The assumptions used to estimate the fair value the Warrants are as follows: Third Lien Notes Unsecured Warrants Creditor Warrants Risk-free interest rate (1) 1.04 % 1.04 % Dividend yield — — Expected life (2) 3.50 3.50 Expected volatility (3) 55.0 % 55.0 % Strike Price $ 24.00 $ 46.00 Calculated fair value $ 6.74 $ 3.42 (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the expected life of the option. (2) The expected life assumption was based upon the years until expiration of the Warrants. (3) The Company utilized six peer companies of comparable size and industry to estimate asset volatility utilizing a period that is commensurate with the expected Warrant life. The Company weighted historical volatility and implied volatility 50/50 for those peer companies where both were available, with asset volatility ranging in the peer companies from 30.1% to 54.2%. The derived asset volatility was selected based upon the midpoint of the average and the third quartile of the peer group, and then relevered the utilizing the Company’s asset and equity information as of the Effective Date. The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date (in thousands): As of October 21, 2016 Enterprise value $ 600,000 Plus: cash and cash equivalents 76,540 Plus: other working capital liabilities 60,118 Plus: other long-term liabilities 14,600 Reorganization value $ 751,258 Consolidated Balance Sheet The following consolidated balance sheet is as of October 21, 2016. This consolidated balance sheet includes adjustments that reflect the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”) as of the Effective Date (in thousands): Predecessor Reorganization Fresh Start Successor ASSETS CURRENT ASSETS: Cash and cash equivalents $ 274,530 $ (197,990) {a} $ — $ 76,540 Accounts receivable: Oil and gas sales 33,895 — — 33,895 Joint interest billing 4,739 — — 4,739 Other 26 — — 26 Other current assets 8,425 (2,748) {b} — 5,677 Total current assets 321,615 (200,738) — 120,877 PROPERTY AND EQUIPMENT: Oil and gas properties, on the basis of full-cost accounting 3,795,943 — (3,176,723) {h} 619,220 Other property and equipment 12,175 — (5,965) {h} 6,210 Less accumulated depreciation, depletion, amortization and impairment (3,449,241) — 3,449,241 {h} — Net property and equipment 358,877 — 266,553 625,430 OTHER NONCURRENT ASSETS 3,701 1,250 {c} {a} — 4,951 TOTAL $ 684,193 $ (199,488) $ 266,553 $ 751,258 LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT) CURRENT LIABILITIES: Accounts payable $ 10,294 $ — $ — $ 10,294 Accrued liabilities 65,240 (15,416) {a} — 49,824 Debt classified as current 249,384 (249,384) {a}{d} — — Total current liabilities 324,918 (264,800) — 60,118 ASSET RETIREMENT OBLIGATIONS 20,368 — (6,385) {h} 13,983 OTHER LONG-TERM LIABILITIES 617 128,059 {d} — 128,676 LIABILITIES SUBJECT TO COMPROMISE 1,882,187 (1,882,187) {e}{a} — — COMMITMENTS AND CONTINGENCIES STOCKHOLDERS’ EQUITY/(DEFICIT): Preferred stock — — — — Warrants — 37,329 {e} — 37,329 Common stock - predecessor 104 (104) {f} — — Common stock - successor — 247 {f} — 247 Treasury stock (3,134) 3,134 {f} — — Additional paid-in-capital - predecessor 891,292 (891,292) {f} — — Additional paid-in-capital - successor — 510,905 {f} — 510,905 Retained deficit (2,432,159) 2,159,221 {g} 272,938 {i} — Total stockholders’ equity/(deficit) (1,543,897) 1,819,440 272,938 548,481 TOTAL $ 684,193 $ (199,488) $ 266,553 $ 751,258 Reorganization Adjustments {a} Adjustments reflect the following net cash payments recorded as of the Effective Date from implementation of the Plan (in thousands): Uses: Cash pay down of RBL $ 81,324 Cash payment to holders of Second Lien Notes Claims 60,000 Cash payment to the RBL lenders in consideration of a temporary reduction in the amount available to be drawn under the Exit Facility 40,000 Payment to escrow for professional fees related to the Plan incurred through the Effective Date 15,416 Debt issuance costs associated with the Exit Facility 1,250 Total uses $ 197,990 {b} Adjustment reflects the write off of unamortized debt issuance costs associated with the RBL. {c} Adjustment reflects the debt issuance costs associated with the Exit Facility. {d} Adjustment represents the establishment of Exit Facility, which superceded the RBL. {e} As part of the Plan, the Bankruptcy Court approved the settlement of certain allowable claims, reported as liabilities subject to compromise in the Company’s historical consolidated balance sheet. As a result, a gain of $1.3 billion was recognized on the settlement of liabilities subject to compromise. The gain was calculated as follows (in thousands): Predecessor Liabilities subject to compromise $ 1,882,187 Cash paid to holders of Second Lien Notes Claims (60,000) Warrants issued to holders of Third Lien Notes Claims (29,753) Warrants issued to holders of Unsecured Notes Claims (7,575) Write-off of unamortized debt costs associated with RBL (2,748) Common stock issued (511,152) Gain on settlement $ 1,270,959 {f} Adjustments represent (i) the cancellation of predecessor stock that was authorized and outstanding prior to the Effective Date and (ii) the issuance of 24,687,500 shares of new common stock upon emergence on the Effective Date. {g} This adjustment reflects the cumulative impact of the following reorganization adjustments (in thousands): Predecessor Gain on settlement of liabilities subject to compromise $ 1,270,959 Common stock - predecessor 104 Treasury stock (3,134) Additional paid-in-capital - predecessor 891,292 Net impact to Predecessor accumulated deficit $ 2,159,221 Fresh Start Adjustments {h} The adjustments primarily represent (i) the removal of $3.4 billion of accumulated depreciation, depletion, amortization and impairment due to fresh start accounting, (ii) the $269.7 million increase in oil and gas properties due to the application of fresh start accounting, (iii) the $6.4 million decrease in the asset retirement obligation due to the application of fresh start accounting and (iv) an increase in other property and equipment. {i} This adjustment reflects the cumulative impact of the fresh start adjustments discussed herein. Reorganization Items Reorganization items represent the direct and incremental costs of being in bankruptcy, such as professional fees, pre-petition liability claim adjustments and losses related to terminated contracts that are probable and can be estimated. Unamortized deferred financing costs as well as unamortized gains on the May 2015 troubled debt restructuring associated with debt classified as liabilities subject to compromise were also reclassified to reorganization items in order to reflect the expected amounts of allowed claims. The following table summarizes the gain on reorganization items, net, in the consolidated statements of operations (in thousands): Predecessor For the Period January 1, 2016 through October 20, 2016 Professional fees incurred $ (38,835) Adjustment to unamortized debt issuance costs associated with 2020 Senior Notes (10,738) Adjustment to unamortized debt issuance costs associated with 2021 Senior Notes (12,671) Adjustment to unamortized gain on troubled debt restructuring associated with Second Lien Notes 39,599 Adjustment to unamortized gain on troubled debt restructuring associated with Third Lien Notes 71,808 Gain on settlement of liabilities subject to compromise 1,270,959 Fresh start adjustments 272,938 Other reorganization items (1) 1,221 Gain on reorganization items, net $ 1,594,281 (1) Other reorganization items primarily included $0.2 million related to Houston office fixed assets, which were abandoned, as well as a $1.6 million decrease in the liability previously recorded for the abandonment of the Houston office lease.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies	4. Summary of Significant Accounting Policies Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared pursuant to the rules and regulations of the SEC and have been prepared in accordance with US GAAP. All intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the period October 21, 2016 through December 31, 2016 are referred to as the Successor Period, and the period January 1, 2016 through October 20, 2016 is referred to as the Predecessor Period. The Company’s management evaluates performance based on one reportable segment as all its operations are located in the United States and therefore it maintains one cost center. As a result of the adoption of Accounting Standards Update 2014-09, “ Revenue from Contracts with Customers (Topic 606) ” (“ASU 2014-09”), certain balances included in the consolidated statements of operations for prior periods have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on net income, cash flows or stockholders’ equity for any period presented. Fresh Start Accounting Upon emergence from bankruptcy, the Company adopted fresh start accounting. Adopting fresh start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, the Company's consolidated financial statements on or after October 21, 2016, are not comparable with the Company's consolidated financial statements prior to that date. Use of Estimates The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company utilizes historical experience as well as other assumptions that are believed to be reasonable under the circumstances in preparing its estimates. The Company evaluates estimates and assumptions on a regular basis. Actual results could differ from those estimates and assumptions used in the preparation of the Company’s financial statements. Significant estimates include, but are not limited to the estimates of reorganization value, enterprise value and fair value of assets and liabilities upon emergence from bankruptcy and application of fresh start accounting, the estimate of revenue recognition, the estimate of recoverable oil and natural gas reserves and related present value estimates of future net cash flows derived therefrom, legal and environmental risks and exposures, the fair value of share-based compensation, income taxes and the valuation of future asset retirement obligations. Cash and Cash Equivalents The Company considers all short-term investments with an original maturity of three months or less to be cash equivalents. The Company’s total cash balances are insured by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 per bank per depositor. The Company had cash balances on deposit at December 31, 2018 and 2017, that exceeded the balance insured by the FDIC in the amount of $12.8 million and $70.4 million, respectively. Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are stated at the historical carrying amount net of any allowance for uncollectible accounts. The carrying amount of the Company’s accounts receivable approximate fair value because of the short-term nature of the instruments. Many of the Company’s receivables are from joint interest owners in properties in which the Company is the operator. The Company may withhold future revenue disbursements to recover any non-payment of these joint interest billings under certain circumstances. The Company routinely assesses the collectability of all material trade and other receivables and the Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2018 and 2017, the Company had no allowance for doubtful accounts. Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, debt, and commodity derivative contracts. Commodity derivative contracts are recorded at fair value; see “— Note 6. Fair Value Measurements of Financial Instruments”. The fair value of the Company’s long-term debt is disclosed, see “— Note 11. Debt”. The carrying amount of the Company’s other financial instruments approximate fair value because of the short-term nature of the items or variable pricing. Derivative financial instruments, if held by the Company, are presented in the consolidated balance sheets as either an asset or liability measured at estimated fair value. Changes in the derivative’s fair value are recognized in the consolidated statement of operations as gains and losses in the period of change. The gains or losses are recorded in “Gains on commodity derivative contracts—net.” The related cash flow impact is reflected within cash flows from operating activities. Property and Equipment Oil and Gas Properties The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, costs of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company’s reserve quantities are sold such that it results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income. Unevaluated Property Oil and gas unevaluated properties and properties under development include costs that are not being depleted or amortized. These costs represent investments in unproved properties. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are transferred to proved properties, become part of our depletion base and become subject to the full cost ceiling limitation. During the year ended December 31, 2018 and 2017, the Company transferred $3.0 million and $58.0 million,respectively, of unevaluated property to the full cost pool. As discussed below under “—Note 9. Acquisition and Divestitures of Oil and Gas Properties”, the Company divested its Anadarko Basin assets in the second quarter of 2018. As part of that divestiture, all remaining unevaluated property, or approximately $3.0 million was allocated to the full cost pool. As discussed below under “Impairment of Oil and Gas Properties/Ceiling Test” the Company’s strategy was refined during 2017 to focus on optimizing free cash flow, keeping leverage to a minimum and drilling only those locations that had the best probability of a reasonable rate of return. Therefore, unevaluated property value not associated with the Company’s refined drilling focus were allocated to the full cost pool at December 31, 2017. Oil and Gas Reserves Proved oil, NGLs and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company depletes its oil and gas properties using the units-of-production method. Capitalized costs of oil and natural gas properties subject to amortization are depleted over proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. Impairment of Oil and Gas Properties/Ceiling Test The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit, or ceiling, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization (“DD&A”) and the related deferred income taxes, may not exceed this ceiling. The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales prices received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations. For the year ended December 31, 2017,and the Predecessor Period, the Company recorded impairments of oil and gas properties of $125.3 million and $232.1 million, respectively. The Company recorded an impairment of oil and gas properties of $125.3 million primarily as a result of the exclusion of proved undeveloped reserves not associated with infill drilling in the Carmen and Dacoma areas from its December 31, 2017, reserve report. During the Predecessor Period, a significant and sustained decline in the average oil and natural gas sales price utilized in calculating the present value of estimated future net revenues from projected production of oil and gas reserves was the primary factor that led to the full-cost ceiling impairments. The Company did not record an impairment of oil and gas properties for the year ended December 31, 2018. Depletion Depletion of oil and gas properties is calculated using the units of production method (“UOP”). The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reserves are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated depletion, estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value. Capitalized Interest Interest is capitalized for certain unevaluated oil and gas properties with ongoing development activities using the weighted-average cost of outstanding borrowings, which also includes the amortization of debt costs. Capitalized interest is depleted over the useful lives of the assets in the same manner as the depletion of the underlying assets. Other Property and Equipment Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and is carried at cost. Depreciation is provided principally using the straight‑line method over the estimated useful lives of the assets, which primarily range from two to ten years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized. Accrued Liabilities At December 31, 2018 and 2017, accrued liabilities consisted of the following (in thousands): December 31, 2018 December 31, 2017 Accrued oil and gas capital expenditures $ 1,534 $ 9,081 Accrued revenue and royalty distributions 13,302 18,701 Accrued lease operating and workover expense 2,843 5,150 Accrued interest 209 108 Accrued taxes 1,813 2,758 Compensation and benefit related accruals 2,855 4,520 Other 2,965 2,524 Accrued liabilities $ 25,521 $ 42,842 Asset Retirement Obligations The legal obligations associated with the retirement of long‑lived assets are recognized at the time that the obligation is incurred. Oil and gas producing companies incur such a liability upon drilling or acquiring a well. The Company estimates the amount of an asset retirement obligation in the period in which the obligation is incurred and can be reliably measured. The corresponding asset retirement cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depleted over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, any adjustment is recorded to the full cost pool. See “-Note 10. Asset Retirement Obligations”. Share‑Based Compensation The Company measures share-based compensation cost at fair value and generally recognizes the corresponding compensation expense on a straight-line basis over the service period during which awards are expected to vest for periods prior to the Effective Date. For periods subsequent to the Effective Date, the Company recognizes compensation expense on graded and straight-line vesting basis. Share-based compensation expense, net of amounts capitalized to oil and gas properties, is included in “General and administrative” expense in our consolidated statements of operations and “Accrued liabilities” in our consolidated balance sheets. See “—Note 13. Equity and Share-Based Compensation”. Revenue Recognition On January 1, 2018, we adopted ASC 606, using the modified retrospective method of transition. The primary impact to our revenues as a result of the adoption of ASC 606 is the netting of certain deductions and costs against revenue instead of the historical practice of presenting such expenses gross in gathering and transportation. Oil, NGLs and natural gas revenues are recognized at the point in time that control of the product is transferred to the customer and collectability is reasonably assured. Other revenue consists of iodine royalty income, which are point in time sales, and salt water disposal income, which is recognized over time. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company’s share of remaining proved oil and gas reserves. The Company had no significant imbalances at December 31, 2018 and 2017. Acquisition and Transaction Costs Acquisition and transaction related costs are expensed as incurred and as services are received. Such costs include finders’ fees, advisory, legal, accounting, valuation and other professional and consulting fees, and acquisition related general and administrative costs. See “—Note 9. Acquisition and Divestitures of Oil and Gas Properties”. Income Taxes Income taxes are recorded for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates. The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-than-likely-than-not recognition threshold are recognized. In December of 2017, the U.S. government enacted comprehensive tax legislation that includes significant changes to the taxation of business entities, including, among other provisions, a permanent reduction to the corporate income tax rate. See “—Note 14. Income Taxes” for further information. Income (Loss) Per Share Net income (loss) per common share is calculated utilizing the two-class method by dividing net income (loss) available to common shareholders by the weighted-average number of common shares outstanding during each period. Diluted net income (loss) per common share is calculated under the two-class method and the treasury stock method by dividing net income (loss) available to common shareholders by the weighted-average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted net income (loss) per share calculations consist of unvested restricted stock awards, warrants and outstanding stock options for the years ended December 31, 2018 and 2017, and the Successor Period. Potentially dilutive securities for the diluted net income (loss) per share calculations consist of the Company’s Series A Preferred Stock using the if-converted method (in periods prior to the Preferred Stock’s mandatory conversion date) and unvested restricted stock awards for the Predecessor Period. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted net income (loss) per share. See “—Note 15. Income (Loss) Per Share.” Recent Accounting Pronouncements Adopted During the Period In March 2018, the FASB issued Accounting Standards Update 2018-05, “Income Taxes (Topic 740), Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118”. ASU 2018-05 amends certain SEC paragraphs pursuant to the issuance of the December 2017 SEC SAB 118, which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act’s enactment date for companies to complete its accounting under ASC 740. In accordance with SAB 118, to the extent a company has not completed its analysis of the Tax Act but can provide a reasonable estimate, it must record a provisional estimate in its financial statements. The Company has completed its accounting for certain tax effects of the Tax Act under the guidance of SAB 118. See “—Note 14. Income Taxes” for further information. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”. ASU 2014-09 provides guidance concerning the recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09 is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The Company adopted ASU 2014-09 using the modified retrospective approach. The adoption of this guidance did not have a material impact on the Company’s financial statements. See “— Note 5. Impact of ASC 606 Adoption” for further information. Recent Accounting Pronouncements Issued But Not Yet Adopted In June 2018, the FASB issued ASU 2018-07, “ Compensation - Stock Compensation (Topic 718) — Improvements to Nonemployee Share-Based Payment Accounting ”. ASU 2018-07 expands the scope of Topic 718 to include share-based payments issued to nonemployees for goods and services. Consequently, the accounting for share-based payments to nonemployees and employees will be substantially aligned. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company does not believe the adoption of ASU 2018-07 will have a material impact on its financial position, results of operations or cash flows. In July 2017, the FASB issued ASU 2017-11, “Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815)”. ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present EPS in accordance with Topic 260 to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company does not believe the adoption of ASU 2017-11 will have a material impact on its financial position, results of operations or cash flows. In February 2016, the FASB issued ASU 2016-02, “ Leases (Topic 842) ”. ASU 2016-02 establishes a ROU model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. All leases create an asset and a liability for the lessee and therefore recognition of those lease assets and lease liabilities is required by ASU 2016-02. When measuring lease assets and liabilities, payments to be made in optional extension periods should be included if the lessee is reasonably certain to exercise the option. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 will not impact the accounting or financial presentation of the our mineral leases. For finance leases, the Company will recognize a ROU asset and liability, initially measured at the present value of the lease payments. Interest expense will be recognized on the lease liability separately from the amortization of the ROU asset. The Company will recognize payments of principal on the lease liability within financing activities in the consolidated statement of cash flows and payments of interest within operating activities in the consolidated statement of cash flows. For operating leases, the Company will recognize a ROU asset and liability, initially measured at the present value of the lease payments. The Company will recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis and all cash payments will be recognized in operating activities within the consolidated statement of cash flows. In January 2018, the FASB issued Accounting Standards Update 2018-01, “ Leases (Topic 842)-Land Easement Practical Expedient for Transition to Topic 842 ” (“ASU 2018-01”). ASU 2018-01 permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expired prior to a company’s adoption of ASU 2016-02 and that were not accounted for as leases under previous lease guidance. Additionally, in July 2018, the FASB issued Accounting Standards Update 2018-11,” Leases (Topic 842):Targeted Improvements , which included the option to implement the standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings, as opposed to the modified retrospective transition method required when ASU 2016-02 was issued. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company has analyzed and categorized its contracts to determine if they meet the definition of a lease under ASU 2016-02. The Company plans to adopt the new standard using the simplified transition method described in ASU 2018-11. Consequently, financial information will not be updated and the disclosures required under the new standard will not be provided for the dates and periods before January 1, 2019. Additionally, the Company plans to elect the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases, but does not plan to elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. The Company also plans to elect the practical expedient under ASU 2018-01 and not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. The Company is working to complete its evaluation of the impact of ASU 2016-02 on its financial statements, accounting policies and internal controls, including implementation of systems and processes to capture, classify and account for leases within the scope of the new guidance and to provide the related disclosures. At this time, the impact upon adoption of ASU 2016-02 and other related ASUs is expected to result in recognition of additional operating liabilities ranging from $4.0 million to $7.0 million, with corresponding right-of-use assets of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing leases. The new standard also provides practical expedients for an entity’s ongoing accounting. The Company currently expects to elect the short-term lease recognition exemption for all leases that qualify. The Company also currently expects to elect the practical expedient to not separate lease and non-lease components for the majority of classes of underlying assets.

Impact of ASC 606 Adoption

Impact of ASC 606 Adoption	12 Months Ended
	Dec. 31, 2018
Impact of ASC 606 Adoption
Impact of ASC 606 Adoption	5. Impact of ASC 606 Adoption On January 1, 2018, the Company adopted ASC 606 using the modified retrospective method of transition. ASC 606 supersedes previous revenue recognition requirements in Accounting Standards Codification 605, Revenue Recognition (“ASC 605”) and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The impact of adoption on the Company’s results is as follows for the periods presented (in thousands): December 31, 2018 Under ASC 606 Under ASC 605 Decrease Oil sales $ 123,945 $ 124,006 $ (61) Natural gas liquid sales 44,747 44,818 (71) Natural gas sales 32,138 44,651 (12,513) Gathering and transportation 241 12,646 (12,405) Lease operating and workover expense 54,229 54,469 (240) Net income $ 49,784 $ 49,784 $ — Retained deficit $ (25,363) $ (25,363) $ — The primary impact to the Company’s revenues as a result of the adoption of ASC 606 is the netting of certain deductions and costs against revenue instead of its historical practice of presenting such expenses gross in gathering and transportation. These changes are due to analysis of the control model in ASC 606. Further discussion of the Company’s revenue recognition under ASC 606 is included below. Revenue Recognition Oil, NGLs and natural gas revenues are recognized at the point in time that control of the product is transferred to the customer and collectability is reasonably assured. Other revenue consists of iodine royalty income, which are point in time sales, and salt water disposal income, which is recognized over time. A more detailed summary of the underlying contracts that give rise to revenue and the method of recognition is included below. Natural Gas and NGLs Sales Under the Company’s gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas, sells the resulting NGLs and residue gas to third-parties and pays the Company for the NGLs and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts that the Company concluded that it was the principal, the ultimate third-party is the customer, and it recognizes revenue on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Alternatively, for those contracts that the Company has concluded that it is the agent, the purchaser is its customer, and it recognizes revenue based on the net amount of the proceeds received from the purchaser. Oil Sales Under the Company’s oil sales contracts, it delivers all or a specified percentage of the crude oil production from specified leases to the purchaser at the wellhead. The Company sells oil production at the wellhead and collects an agreed-upon index price, net of applicable transport costs. The Company recognizes revenue when control transfers to the purchaser at the wellhead at the net price received. Other Revenue Other revenue consists of fees charged to outside working interest owners for salt water disposal as well as royalties received from a third-party for iodine extracted from the Company’s salt water. Salt water disposal revenue is recognized over time because the customer simultaneously receives and consumes the benefit of the salt water disposal service as the service is provided. For salt water disposal income the Company utilized the practical expedient in ASC 606-10-55-18 which states that if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date, the entity may recognize revenue in the amount to which the entity has a right to invoice. Iodine royalty revenue is recognized point-in-time when control transfers to the customer. Imbalances The Company recognizes revenue for all oil, NGLs and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company’s share of remaining proved oil and gas reserves. The Company had no significant imbalances at December 31, 2018. Significant Judgments Principal versus agent The Company engages in various types of transactions in which midstream entities process its wet gas and, in some scenarios, subsequently market resulting NGLs and residue gas to third-party customers on its behalf, such as its percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. The Company analyzed control under ASC 606 and determined for those contracts where control passes at the wellhead, the Company acts as agent and revenue should be recognized net of amounts paid after such control passed for costs such as gathering, compression, processing and transportation, among others. The determination of control and the presentation of revenues was completed for ASC 606 purposes only. Amounts paid by the Company for royalties are calculated under a different methodology and may differ from the amount of revenues recognized under ASC 606. Transaction price allocated to remaining performance obligations A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in ASC 606-10-50-14A that states it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For salt water disposal income, the Company has utilized the practical expedient in ASC 606-10-50-14 that states that if it recognizes revenue from the satisfaction of the performance obligation in accordance with the right to invoice practical expedient then it is exempted from disclosure of the transaction price allocated to remaining performance obligations. Prior-period performance obligations The Company records revenue in the month production is delivered and control passes to the customer. However, settlement statements and payment may not be received for 30 to 90 days after the date production occurs, and as a result, the Company is required to estimate the amount of production that was delivered and the price that will be received for the sale of the product. The Company utilizes its knowledge of the properties, its historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices and other pertinent factors as the basis for these estimates. The Company records the variances between its estimates and the actual amounts received in the month payment is received and such variances have historically not been significant. For the year ended December 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	12 Months Ended
	Dec. 31, 2018
Fair Value Measurements of Financial Instruments
Fair Value Measurements of Financial Instruments	6. Fair Value Measurements of Financial Instruments The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further divided into the following fair value input hierarchy: · Level 1 —Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. · Level 2 —Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are commodity derivative contracts. Commodity derivative contract fair values are determined using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. · Level 3 —Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative Instruments Commodity derivative contracts reflected in the consolidated balance sheets are recorded at estimated fair value. At December 31, 2018, all of the Company's commodity derivative contracts were with four bank counterparties and were classified as Level 2 in the fair value input hierarchy. Derivative instruments listed below are presented gross and include swaps and collars that are carried at fair value. The Company records the net change in the fair value of these positions in "Gains on commodity derivative contracts - net" in the Company's consolidated statements of operations. Fair Value Measurements at December 31, 2018 Significant Other Significant Quoted Prices in Active Observable Inputs Unobservable Inputs Markets (Level 1) (Level 2) (Level 3) Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ 3,806 $ — $ 3,806 Commodity derivative gas swaps $ — $ 236 $ — $ 236 Commodity derivative oil collars $ — $ 9,306 $ — $ 9,306 Commodity derivative gas collars $ — $ 577 $ — $ 577 Total assets $ — $ 13,925 $ — $ 13,925 Derivative Liabilities: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps $ — $ (443) $ — $ (443) Commodity derivative oil collars $ — $ (5,199) $ — $ (5,199) Commodity derivative gas collars $ — $ (632) $ — $ (632) Total liabilities $ — $ (6,274) $ — $ (6,274) Fair Value Measurements at December 31, 2017 Significant Other Significant Quoted Prices in Active Observable Inputs Unobservable Inputs Markets (Level 1) (Level 2) (Level 3) Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps $ — $ 821 $ — $ 821 Commodity derivative oil collars $ — $ 952 $ — $ 952 Commodity derivative gas collars $ — $ 2,611 $ — $ 2,611 Total assets $ — $ 4,384 $ — $ 4,384 Derivative Liabilities: Commodity derivative oil swaps $ — $ (3,679) $ — $ (3,679) Commodity derivative gas swaps $ — $ — $ — $ — Commodity derivative oil collars $ — $ (2,605) $ — $ (2,605) Commodity derivative gas collars $ — $ (1,333) $ — $ (1,333) Total liabilities $ — $ (7,617) $ — $ (7,617)

Risk Management and Derivative

Risk Management and Derivative Instruments	12 Months Ended
	Dec. 31, 2018
Risk Management and Derivative Instruments
Risk Management and Derivative Instruments	7. Risk Management and Derivative Instruments The Company’s production is exposed to fluctuations in crude oil, NGLs and natural gas prices. The Company believes it is prudent to manage the variability in cash flows by, at times, entering into derivative financial instruments to economically hedge a portion of its crude and natural gas production. The Company utilizes various types of derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. · Swaps: The Company receives or pays a fixed price for the commodity and pays or receives a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. · Three-way collars: A three-way collar contains a fixed floor price (long put), fixed sub-floor price (short put), and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, the Company receives the ceiling strike price and pays the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the sub-floor price, the Company receives the floor strike price and pays the market price. If the market price is below the sub-floor price, the Company receives the market price plus the difference between the floor and the sub-floor strike prices and pays the market price. These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The crude oil and natural gas reference prices upon which the commodity derivative contracts are based reflect various market indices that management believes correlates with actual prices received by the Company for its crude and natural gas production. Inherent in the Company's portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company's counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties of its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Due to the netting arrangements, had the Company's counterparties failed to perform under existing commodity derivative contracts, the maximum loss at December 31, 2018, would have been $7.7 million. Commodity Derivative Contracts The Company has entered into various oil and natural gas derivative contracts that extend through December 2020, summarized as follows: NYMEX WTI Fixed Swaps Three-Way Collars Weighted Weighted Weighted Hedge Avg Hedge Avg Weighted Avg Position Strike Position Ceiling Avg Floor Sub-Floor (Bbls) Price (Bbls) Price Price Price Quarter Ended: December 31, 2018 313,720 $ 58.59 46,000 $ 56.70 $ 50.00 $ 40.00 March 31, 2019(1) 74,800 $ 66.48 180,000 $ 63.14 $ 53.75 $ 43.75 June 30, 2019(1) 57,650 $ 64.69 182,000 $ 63.14 $ 53.75 $ 43.75 September 30, 2019(1) 46,000 $ 62.96 184,000 $ 63.14 $ 53.75 $ 43.75 December 31, 2019(1) 46,000 $ 61.43 184,000 $ 63.14 $ 53.75 $ 43.75 March 31, 2020(1) — $ — 91,000 $ 65.75 $ 50.00 $ 40.00 June 30, 2020(1) — $ — 91,000 $ 65.75 $ 50.00 $ 40.00 September 30, 2020(1) — $ — 92,000 $ 65.75 $ 50.00 $ 40.00 December 31, 2020(1) — $ — 92,000 $ 65.75 $ 50.00 $ 40.00 NYMEX HENRY HUB Fixed Swaps Three-Way Collars Weighted Weighted Weighted Hedge Avg Hedge Avg Weighted Avg Position Strike Position Ceiling Avg Floor Sub-Floor (MMBtu) Price (MMBtu) Price Price Price Quarter Ended: December 31, 2018 2,055,000 $ 2.95 1,380,000 $ 3.40 $ 3.00 $ 2.50 March 31, 2019(1) 1,980,000 $ 3.01 1,350,000 $ 3.40 $ 3.00 $ 2.50 June 30, 2019(1) 1,365,000 $ 2.75 — $ — $ — $ — September 30, 2019(1) 1,380,000 $ 2.75 — $ — $ — $ — December 31, 2019(1) 465,000 $ 2.75 610,000 $ 3.45 $ 2.65 $ 2.15 March 31, 2020(1) — — 910,000 $ 3.45 $ 2.65 $ 2.15 (1) Positions shown represent open commodity derivative contract positions as of December 31, 2018. Balance Sheet Presentation The following table summarizes the net fair values of commodity derivative instruments by the appropriate balance sheet classification in the Company's consolidated balance sheets for the periods presented (in thousands): Type Balance Sheet Location (1) December 31, 2018 December 31, 2017 Oil swaps Derivative financial instruments — current assets $ 3,806 $ — Gas swaps Derivative financial instruments — current assets (207) 821 Oil collars Derivative financial instruments — current assets 3,316 (760) Gas collars Derivative financial instruments — current assets 25 701 Total derivative financial instruments — current assets $ 6,940 $ 762 Oil collars Derivative financial instruments — noncurrent assets $ 791 — Total derivative financial instruments — noncurrent assets $ 791 $ — Oil swaps Derivative financial instruments — current liabilities $ — $ (3,679) Oil collars Derivative financial instruments — current liabilities — (370) Gas collars Derivative financial instruments — current liabilities — 616 Total derivative financial instruments — current liabilities $ — $ (3,433) Oil collars Derivative financial instruments — noncurrent liabilities $ — $ (523) Gas collars Derivative financial instruments — noncurrent liabilities (80) (39) Total derivative financial instruments — noncurrent liabilities $ (80) $ (562) Total derivative fair value at period end $ 7,651 $ (3,233) (1) The fair values of commodity derivative instruments reported in the Company’s consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table summarizes the location and fair value amounts of all commodity derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets for the periods presented (in thousands): December 31, 2018 Net Recognized Not Designated as Gross Recognized Gross Amounts Fair Value ASC 815 Hedges Balance Sheet Location Classification Assets/ Liabilities Offset Assets/ Liabilities Derivative Assets: Commodity contracts Derivative financial instruments — current $ 11,066 $ (4,126) $ 6,940 Commodity contracts Derivative financial instruments — noncurrent 2,859 (2,068) 791 $ 13,925 $ (6,194) $ 7,731 Derivative Liabilities: Commodity contracts Derivative financial instruments — current $ (4,126) $ 4,126 $ — Commodity contracts Derivative financial instruments — noncurrent (2,148) 2,068 (80) $ (6,274) $ 6,194 $ (80) December 31, 2017 Not Designated as Net Recognized Gross Recognized Gross Amounts Fair Value ASC 815 Hedges Balance Sheet Location Classification Assets/Liabilities Offset Assets/Liabilities Derivative Assets: Commodity contracts Derivative financial instruments — current $ 3,479 $ (2,717) $ 762 Commodity contracts Derivative financial instruments — noncurrent 905 (905) — $ 4,384 $ (3,622) $ 762 Derivative Liabilities: Commodity contracts Derivative financial instruments — current $ (6,150) $ 2,717 $ (3,433) Commodity contracts Derivative financial instruments — noncurrent (1,467) 905 (562) $ (7,617) $ 3,622 $ (3,995) Gains/Losses on Commodity Derivative Contracts The Company does not designate its commodity derivative contracts as hedging instruments for financial reporting purposes. Accordingly, commodity derivative contracts are marked-to-market each quarter with the change in fair value during the periodic reporting period recognized currently as a gain or loss in “Gains on commodity derivative contracts —net” within revenues in the consolidated statements of operations. The following table presents net cash received for commodity derivative contracts and unrealized net (losses) gains recorded by the Company related to the change in fair value of the derivative instruments in “Gains on commodity derivative contracts—net” for the periods presented (in thousands): Successor Predecessor For the Period For the Period October 21,2016 January 1, 2016 For the Year Ended December 31, through through 2018 2017 December 31,2016 October 20,2016 Net cash (paid) received for commodity derivative contracts $ (7,328) $ 6,891 $ — $ — Unrealized net gains (losses) 10,883 (3,232) — — Gains on commodity derivative contracts—net $ 3,555 $ 3,659 $ — $ — Cash settlements, as presented in the table above, represent realized gains related to the Company’s derivative instruments. In addition to cash settlements, the Company also recognizes fair value changes on its derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.

Property and Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2018
Property and Equipment
Property and Equipment	8. Property and Equipment The Company’s property and equipment as of the dates presented was as follows (in thousands): December 31, 2018 December 31, 2017 Oil and gas properties, on the basis of full-cost accounting: Proved properties $ 809,272 $ 765,308 Unproved properties not being amortized 4,050 7,065 Other property and equipment 6,345 6,508 Less accumulated depreciation, depletion, amortization and impairment (266,198) (204,419) Net property and equipment $ 553,469 $ 574,462 For the years ended December 31, 2018, 2017, the Successor Period and the Predecessor Period, depletion expense related to oil and gas properties was $60.0 million, $63.4 million, $12.6 million, and $59.9 million, respectively, and $9.00, $7.85, $7.00, and $6.84 per Boe, respectively. For the year ended December 31, 2018, 2017, Successor Period, and Predecessor Period, depreciation expense related to other property and equipment was $2.0 million, $2.4 million, $0.4 million and $2.4 million, respectively. For the years ended December 31, 2018, 2017, and the Successor Period, interest capitalized to unevaluated properties was $0.5 million, $2.4 million and $0.7 million, respectively. For the year ended December 31, 2018,2017, Successor Period, and Predecessor Period, the Company capitalized $2.8 million, $5.3 million, $1.4 million and $3.4 million, respectively, of internal costs to oil and gas properties, including $0.9 million, $2.0 million, $0.6 million and $0.5 million, respectively, of qualifying share-based compensation expense, see “— Note 13. Equity and Share-Based Compensation”.

Acquisition and Divestitures of

Acquisition and Divestitures of Oil and Gas Properties	12 Months Ended
	Dec. 31, 2018
Acquisition and Divestitures of Oil and Gas Properties
Acquisition and Divestitures of Oil and Gas Properties	9. Acquisition and Divestitures of Oil and Gas Properties Lincoln Divestiture On July 26, 2017, the Company closed on the sale of certain oil and gas properties in Lincoln County, Oklahoma, for $7.0 million in cash ($2.9 million, net after assumption of liabilities). The net proceeds from the sale were retained for general corporate purposes. Anadarko Divestiture On May 31, 2018, the Company closed on the sale of its Anadarko Basin assets for $58.0 million in cash ($54.1 million, net of closing adjustments). The net proceeds were reflected as a reduction of oil and natural gas properties, with no gain or loss recognized as the sale did not result in a significant alteration of the full cost pool. The Company used $50.0 million of the net proceeds from the sale of the Anadarko Basin assets to pay down a portion of outstanding borrowings under the Company’s Exit Facility and retained the remainder for general corporate purposes. Acquisition and Transaction Expenses For the year ended December 31, 2018, acquisition and transaction costs of $0.9 million relate to the execution of the Anadarko Divestiture. We did not have acquisition and transactions costs for the year ended December 31, 2017.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligations
Asset Retirement Obligations	10. Asset Retirement Obligations For the Company, asset retirement obligations (“AROs”) represent the future abandonment costs of tangible assets, such as wells, service assets and other facilities. The fair value of the AROs at inception are capitalized as part of the carrying amount of the related long-lived asset. AROs approximated $8.1 million and $15.5 million as of December 31, 2018 and 2017, respectively. At December 31, 2018 and 2017, all AROs represent long‑term liabilities and are classified as such. The following table details the change in the AROs for the periods presented (in thousands): For the Year Ended December 31, 2018 2017 Asset retirement obligations at beginning of period $ 15,506 $ 14,200 Liabilities incurred 435 571 Revisions — 1,832 Liabilities settled (1) (744) Liabilities eliminated through asset sale (1)(2) (8,699) (1,453) Current period accretion expense 846 1,100 Asset retirement obligations at end of year $ 8,087 $ 15,506 (1) Liabilities eliminated through asset sales for the year ended December 31, 2017 primarily relate to the sale of Lincoln County. See discussion of the sale in “—Note 8. Property and Equipment”. (2) Liabilities eliminated through asset sales for the year ended December 31, 2018 primarily relate to the sale of Anadarko Basin assets. See discussion of the sale in “—Note 8. Property and Equipment”.

Debt

Debt	12 Months Ended
	Dec. 31, 2018
Debt
Debt	11. Debt Exit Facility At December 31, 2018 and 2017, the Company maintained the Exit Facility with a borrowing base of $170.0 million. During the twelve months ended December 31, 2018, the Company paid down $105.0 million, net of its Exit Facility utilizing $55.0 million of available cash on hand and $50.0 million of the net proceeds from the sale of its Anadarko Basin assets. At December 31, 2018 and 2017, the Company had $23.1 million and $128.1 million, respectively, drawn on the Exit Facility and had outstanding letters of credit obligations totaling $1.9 million. At December 31, 2018, the Company had $145.0 million of availability on the Exit Facility. The Exit Facility matures on September 30, 2020 and bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. At December 31, 2018 and 2017, the weighted average interest rate was 7.3% and 6.3%, respectively, excluding amortization expense of deferred financing costs. Unamortized debt issuance costs of $1.2 million, respectively, associated with the Exit Facility are included in “Other noncurrent assets” on the consolidated balance sheets at December 31, 2018 and 2017. In addition to interest expense, the Exit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of 0.50% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter. The Exit Facility, as amended, includes certain financial maintenance covenants that are required to be calculated on a quarterly basis for compliance purposes. These financial maintenance covenants include EBITDA to interest expense for the trailing four fiscal quarters of not less than 2.50:1.00 and a limitation of Total Net Indebtedness (as defined in the Exit Facility) to EBITDA for the trailing four fiscal quarters of not more than 4.00:1.00. On November 15, 2018, the Company entered into a Second Amendment to the Exit Facility. The Second Amendment provides the Company with the ability to make dividends and distributions, including repurchases of its equity interests in cash, in each case, so long as both before and after giving effect to any such repurchase (i) the Company and its subsidiaries maintain liquidity of at least $50.0 million, (ii) no default or event of default exists under the Exit Facility, (iii) the ratio of total net indebtedness to adjusted EBITDA for the most recent period of four fiscal quarters for which financial statements have been delivered pursuant to the Exit Facility shall not exceed 1.50:1.00 and (iv) all repurchased equity interests of the Company must be immediately retired. In addition, the Exit Facility contains various other covenants that, among other things, may restrict the Company's ability to: (i) incur additional indebtedness or guarantee indebtedness; (ii) make loans and investments; (iii) pay dividends on capital stock and make other restricted payments, including the prepayment or redemption of other indebtedness; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with the Company's affiliates; (vii) acquire, consolidate or merge with another entity upon certain terms and conditions; (viii) sell all or substantially all of the Company's assets; (ix) prepay, redeem or repurchase certain debt; (x) alter the business the Company conducts and make amendments to the Company’s organizational documents; (xi) enter into certain derivative transactions; and (xii) enter into certain marketing agreements and take-or-pay arrangements. In February 2019, we partially funded the stock buyback by drawing down $39.0 million from our Exit Facility, with the remainder funded by cash on hand. On October 24, 2018, the Company’s borrowing base was redetermined at the existing amount of $170.0 million. The Company was in compliance with all debt covenants at December 31, 2018. The Company believes the carrying amount of the Exit Facility at December 31, 2018, approximates its fair value (Level 2) due to the variable nature of the Exit Facility interest rate. 2016 Reorganization On the Effective Date, the Company satisfied the conditions to effectiveness set forth in the Confirmation Order and in the Plan, and, as a result, the Plan became effective in accordance with its terms and the Company emerged from the Chapter 11 Cases. Pursuant to the confirmed Plan, the significant transactions impacting the Company’s outstanding debt balances as of the Effective Date were as follows: · Credit Facility: (i) The permanent pay-down of $81.3 million of the Company’s RBL with a $170.0 million Exit Facility established upon the Effective Date, (ii) the pay-down of $60.0 million of our Second Lien Notes in cash, and (iii) the conversion into equity of all of the Company’s remaining debt junior to the RBL; · Credit Facility Claims: Holders of allowed claims arising under the RBL (the “Credit Facility Claims”) received their pro-rata share of approximately $81.3 million in cash and the RBL was superseded, pursuant to the Plan, by the Exit Facility, as further described below; · Second Lien Notes Claims: Holders of allowed claims arising under the Second Lien Notes (the “Second Lien Notes Claims”) received their pro-rata share of (i) 96.25% of the reorganized equity in the form of common stock and (ii) a cash payment of $60.0 million; · Third Lien Notes Claims: Holders of Third Lien Notes Claims, pursuant to the Second/Third Lien Plan Settlement, received their pro-rata share of 2.5% of the reorganized equity in the form of common stock and warrants to acquire 4,411,765 shares of common stock at a strike price of $24.00 per common share with an expiration date 42 months after the Effective Date; · Unsecured Claims: Unsecured Notes Claims and the Holders of other general unsecured claims received their pro-rata share of 1.25% of reorganized equity in the form of common stock and warrants to acquire 2,213,789 shares of common stock at a strike price of $46.00 per common share with an expiration date 42 months after the Effective Date; and · Exit Facility: The Company’s RBL, which was redetermined with a borrowing base of $170.0 million in April 2016, was superseded, pursuant to the Plan, by the Exit Facility as further described above. RBL Prior to the Effective Date, the Company maintained the $750.0 million RBL with a borrowing base of $252.0 million. In February 2016, the Company borrowed approximately $249.2 million under the RBL, which represented the remaining undrawn availability. As a result of the semiannual redetermination on April 1, 2016, the borrowing base was reduced by $82.0 million to $170.0 million from the previous borrowing base of $252.0 million. Borrowing under the RBL bore interest at LIBOR plus an applicable margin, depending upon the Company's borrowing base utilization, between 2.00% and 3.00% per annum. In addition to interest expense, the RBL required the payment of a commitment fee each quarter at the rate of either 0.375% or 0.500% per annum based on the average daily amount by which the borrowing base exceeded the outstanding borrowings during each quarter. The RBL was superseded and replaced by the Exit Facility on the Effective Date. On the Effective Date, $121.3 million of outstanding borrowings on the RBL were repaid, with the remaining outstanding balance carried over to the Exit Facility. 2020 Senior Notes On October 1, 2012, the Company issued $600.0 million in aggregate principal amount of 2020 Senior Notes, conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. On May 21, 2015 and June 2, 2015, a total of approximately $306.4 million aggregate principal amount of 2020 Senior Notes were exchanged for Third Lien Notes. The 2020 Senior Notes had an interest rate of 10.75%. On the Effective Date, the obligations of the Company with respect to the 2020 Senior Notes were cancelled and holders of the 2020 Senior Notes received their agreed upon pro-rata share of the Unencumbered Assets Equity Distribution. See “—Note 2. Emergence from Voluntary Reorganization under Chapter 11 Proceedings” for further discussion. 2021 Senior Notes On May 31, 2013, the Company issued $700.0 million in aggregate principal amount of 2021 Senior Notes. In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. On May 21, 2015 and June 2, 2015, a total of approximately $352.3 million aggregate principal amount of 2021 Senior Notes were exchanged for Third Lien Notes. The 2021 Senior Notes had an interest rate of 9.25%. On the Effective Date, the obligations of the Company with respect to the 2021 Senior Notes were cancelled and holders of the 2021 Senior Notes received their agreed-upon pro-rata share of the Unencumbered Assets Equity Distribution. See “—Note 2. Emergence from Voluntary Reorganization under Chapter 11 Proceedings” for further discussion. Second Lien Notes On May 21, 2015, the Company and Midstates Sub issued and sold $625.0 million aggregate principal amount of Second Lien Notes, in a private placement conducted pursuant to Rule 144A under the Securities Act. In November 2015, these notes were exchanged for an equal principal amount of identical registered notes. The Second Lien Notes had an interest rate of 10.0%. On the Effective Date, the obligations of the Company with respect to the Second Lien Notes were cancelled and holders of the Second Lien Notes received a cash payment of $60.0 million as well as their agreed-upon pro-rata share of equity in the reorganized Company. See “—Note 2. Emergence from Voluntary Reorganization under Chapter 11 Proceedings” for further discussion. Third Lien Notes On May 21, 2015 and June 2, 2015, the Company issued approximately $504.1 million and $20.0 million, respectively, in aggregate principal amount of Third Lien Notes in a private placement and in exchange for an aggregate $306.4 million of the 2020 Senior Notes and $352.3 million of the 2021 Senior Notes. In November 2015, these notes were exchanged for an equal principal amount of identical registered notes. The Third Lien Notes had an interest rate of 12.0%, consisting of cash interest of 10.0% and paid-in-kind interest of 2.0%, per annum. On the Effective Date, the obligations of the Company with respect to the Third Lien Notes were cancelled and holders of the Third Lien Notes received their agreed upon pro-rata share of equity and warrants in the reorganized Company as set forth in the Second/Third Lien Plan Settlement embodied in the Plan. See “—Note 2. Emergence from Voluntary Reorganization under Chapter 11 Proceedings” for further discussion.

Preferred Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2018
Preferred Stock
Preferred Stock	12. Preferred Stock Series A Preferred Stock On October 1, 2012, the Company issued 325,000 shares of Series A Mandatorily Convertible Preferred Stock (“Series A Preferred Stock”) with an initial liquidation preference of $1,000 per share and an 8.0% per annum dividend, payable semiannually at the Company’s option in cash or through an increase in the liquidation preference. Based on the liquidation preference at September 30, 2015, each Series A Preferred Share converted into approximately 11.5 shares of the Company’s Predecessor common stock pursuant to the Certificate of Designation, which governed the Series A Preferred Stock. As a result, the Company issued 3,738,424 shares of Predecessor common stock upon conversion of the Series A Preferred Stock during 2015. At the Effective Date, the Company’s then existing common stock was cancelled and new common stock of the reorganized Company was issued. See “—Note 2. Emergence from Voluntary Reorganization under Chapter 11 Proceedings” for further discussion.

Equity and Share-Based Compensa

Equity and Share-Based Compensation	12 Months Ended
	Dec. 31, 2018
Equity and Share-Based Compensation
Equity and Share-Based Compensation	13. Equity and Share‑Based Compensation Emergence from Bankruptcy On the Effective Date, the Company’s then existing common stock was canceled and new common stock in the reorganized Company was issued. In addition, Company's previous share-based compensation awards were either vested or canceled upon the Company's emergence from bankruptcy. Common Shares Successor Period At December 31, 2018, the Company had 25,520,170 and 25,345,981 shares of its common stock issued and outstanding, respectively. On the Effective Date, the Company issued 24,687,500 shares of Successor common stock in the reorganized Company. On November 8, 2016, the Company issued 12,400 shares of common stock to employees and non-employee directors, which vested immediately upon issuance. On November 9, 2016, the Company issued an additional 294,967 shares of common stock of the reorganized Company pursuant to the Plan. At the Effective Date, the Company was obligated to issue 17,533 additional common shares pursuant to the Plan. The total authorized common stock of the reorganized Company consists of 250,000,000 shares of common stock and 50,000,000 shares of preferred stock, par value $0.01 per share. Holders of the Company's common shares are entitled to one vote for each share held of record on all matters submitted to a vote of stockholders and to receive ratably in proportion to the shares of common stock held by them any dividends declared from time to time by the board of directors. The common shares have no preferences or rights of conversion, exchange, pre-exemption or other subscription rights. Share Activity The following table summarizes changes in the number of shares of common stock and treasury stock since January 1, 2016: Common Treasury Stock Stock(1) Share count as of December 31, 2015 (Predecessor) 10,962,105 (96,291) Grants of restricted stock — — Forfeitures of restricted stock (47,325) — Acquisition of treasury stock — (52,358) Share count as of October 21, 2016 (Predecessor) 10,914,780 (148,649) Cancellation of common stock (10,914,780) — Cancellation of treasury stock — 148,649 Share count as of October 21, 2016 (Predecessor) — — Issuance of successor common stock 24,687,500 — Share count as of October 21, 2016 (Successor) 24,687,500 — Issuance of successor common stock 307,367 — Acquisition of treasury stock — — Share count as of December 31, 2016 (Successor) 24,994,867 — Issuance of successor common stock 278,102 — Acquisition of treasury stock — (99,623) Share count as of December 31, 2017 (Successor) 25,272,969 (99,623) Issuance of successor common stock 247,201 — Acquisition of treasury stock — (74,566) Share count as of December 31, 2018 (Successor) 25,520,170 (174,189) (1) Treasury stock represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory withholding requirements. Warrants At the Effective Date, the Company issued 4,411,765 Third Lien Notes Warrants to purchase up to an aggregate of 4,411,765 shares of common stock at an initial exercise price of $24.00 per share and 2,213,789 Unsecured Creditor Warrants to purchase up to an aggregate of 2,213,789 shares of common stock at an initial exercise price of $46.00 per share. The Warrants expire on April 21, 2020. Holders of the Warrants do not have the right to vote, to consent, to receive any cash dividends, stock dividends, allotments or rights or other distributions paid, allotted or distributed or distributable to the holders of shares of common stock, or to exercise any rights whatsoever as a stockholder of the Company unless, until and only to the extent such holder of Warrants becomes a holder of record of shares of common stock issued upon settlement of Warrants. The number of shares of common stock for which the Warrants is exercisable, and the exercise price per share of the Warrants are subject to adjustment from time to time upon the occurrence of certain events, including the issuance of common stock as a dividend or distribution to all holders of shares of common stock, a pro-rata repurchase offer of common stock or a subdivision, combination, split, reverse split or reclassification of outstanding common stock into a greater or smaller number of shares of common stock. Upon the occurrence of certain events constituting an organic change (as defined in the Warrant Agreements), holders of the Warrants will have the right to receive, upon exercise of the Warrants, the amount of securities, cash or other property received in connection with such event with respect to or in exchange for the number of shares of common stock for which such Warrants are exercisable immediately prior to such event. The Warrants permit a holder to elect to exercise such that no payment of cash will be required (a "Net Share Settlement"). If Net Share Settlement is elected, the Company is authorized to withhold and not issue in payment of the exercise price, a number of shares of common stock equal to (i) the number of shares of common stock for which the Warrants are being exercised, multiplied by (ii) the exercise price, and divided by (iii) the current sale price (as defined in the Warrant Agreements) on the exercise date. Share-Based Compensation Emergence from Bankruptcy The Company's share-based compensation awards that remained unvested at the Effective Date were cancelled upon the Company's emergence from the Chapter 11 Cases. The cancellation of these share-based compensation awards resulted in the recognition of $1.3 million of expense in the Predecessor Period to record any previously unamortized expense related to such awards. Also, at the Effective Date, the Company's 2012 Long Term Incentive Plan (the "2012 LTIP") was replaced by the Company's 2016 LTIP. The types of awards that may be granted under the 2016 LTIP include stock options, restricted stock units (“RSUs”), restricted stock, performance and market awards and other forms of awards granted or denominated in shares of common stock of the reorganized Company, as well as certain cash-based awards (the "Awards"). The terms of each award are as determined by the Compensation Committee of the Board of Directors. 2016 Long Term Incentive Plan On the Effective Date, the Company established the 2016 LTIP and filed a Form S-8 with the SEC, registering 3,513,950 shares for issuance under the terms of the 2016 LTIP to employees, directors and certain other persons (the "Award Shares"). Subject to certain limitations as defined in the 2016 LTIP, the terms of each Award are to be determined by the Compensation Committee of the Board of Directors. Awards that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future issuance under the 2016 LTIP. At December 31, 2018, 2,100,933 Award Shares remain available for issuance under the terms of the 2016 LTIP. 2012 Long Term Incentive Plan On April 20, 2012, the Company established the 2012 LTIP and filed a Form S‑8 with the SEC. The 2012 LTIP provided for the granting of Options (Incentive and other), Restricted Stock Awards, RSUs, Stock Appreciation Rights, Dividend Equivalents, Bonus Stock, Other Stock‑Based Awards, Annual Incentive Awards, Performance Awards, or any combination of the foregoing. Subject to certain limitations as defined in the 2012 LTIP, the terms of each Award were determined by the Compensation Committee of the Board of Directors. The 2012 LTIP was cancelled upon the Company's emergence on the Effective Date. Restricted Stock Units As of December 31, 2018, the Company had 251,522 shares of RSUs outstanding to employees and non-employee directors pursuant to the 2016 LTIP, excluding RSUs issued to non-employee directors containing a market condition, RSUs issued to the Chief Executive Officer ("CEO") containing a market condition and performance stock units issued to certain members of executive management containing a market condition which are discussed below. Restricted stock units granted to employees in 2018 under the 2016 LTIP vest ratably over a period of three years: one-third will vest on December 31, 2018, an additional one-third will vest on December 31, 2019, and the final one-third will vest on December 31, 2020. Restricted stock units granted to non-employee directors during 2018 vest on the first to occur of (i) December 31, 2018, (ii) the date the non-employee director ceases to be a director of the Board (other than for cause), (iii) the director’s death, (iv) the director’s disability or (v) a change in control of the Company. If an employee terminates employment prior to the vesting date, the outstanding award is forfeited. RSUs are subject to accelerated vesting in the event a recipient's employment is terminated prior to the vesting date by the Company without "Cause" or by the participant with "Good Reason" (each, as defined in the 2016 LTIP) or due to the participant's death or disability. The fair value of RSUs was based on grant date fair value of the Company’s common stock. Compensation expense is recognized ratably over the requisite service period. The following table summarizes the Company’s non‑vested restricted stock unit award activity for the year ended December 31, 2018, 2017, the Successor Period and the Predecessor Period: Weighted Average Grant Date Restricted Stock Fair Value Non-vested shares outstanding at December 31, 2015 (Predecessor) 318,031 $ 21.46 Granted — $ — Vested (162,393) $ 23.09 Forfeited (47,325) $ 19.02 Non-vested shares outstanding at October 20, 2016 (Predecessor) 108,313 $ 20.08 Cancellation of non-vested shares (108,313) $ 20.08 Non-vested shares outstanding at October 20, 2016 (Predecessor) — $ — Granted at Effective Date 686,324 $ 19.66 Non-vested shares outstanding at October 21, 2016 (Successor) 686,324 $ 19.66 Granted 2,035 $ 20.97 Forfeited (2,697) $ 19.66 Non-vested shares outstanding at December 31, 2016 (Successor) 685,662 $ 19.66 Granted 85,389 $ 16.50 Vested (1) (335,958) $ 19.65 Forfeited (110,109) $ 19.66 Non-vested shares outstanding at December 31, 2017 (Successor) 324,984 $ 18.84 Granted 271,968 $ 14.24 Vested (2) (323,927) $ 17.57 Forfeited (21,503) $ 15.52 Non-vested shares outstanding at December 31, 2018 (Successor) 251,522 $ 15.79 (1) Vested RSUs include 109,820 awards in which vesting was accelerated to October 21, 2017, as a result of the former CEO’s amended employment agreement, as well as, 57,856 director awards that vested at December 31, 2017, but receipt/issuance of the vested shares was deferred until 2020. (2) Vested RSUs include 102,092 shares in which vesting was accelerated as a result of a reduction in workforce, as well as, 26,223 director awards in which vesting was accelerated as certain directors departed during the twelve months ended December 31,2018. On August 22, 2017, the Company amended the employment agreement of Fredric F. Brace, former President and Chief Executive Officer (the “Executive Employment Amendment”). Among other provisions, the Executive Employment Amendment accelerated the vesting of all outstanding equity awards of Mr. Brace to October 21, 2017. As a result, approximately $1.2 million of compensation expense associated with Mr. Brace’s non-vested restricted stock was accelerated into the third and fourth quarters of 2017. On November 7, 2018, Frederic Brace, Michael Reddin and Bruce Vincent resigned from the Board. As a result, approximately $0.1 million of compensation expenses associated with Mr. Brace, Mr. Reddin and Mr. Vincent’s non-vested restricted stock was accelerated into the fourth quarter of 2018. The share-based compensation costs (net of amounts capitalized to oil and gas properties) related to RSUs recognized as general and administrative expense by the Company for the year ended December 31, 2018, 2017, the Successor Period and the Predecessor Period, was $4.5 million, $5.8 million, $1.7 million and $2.6 million, respectively. For the year ended December 31, 2018, 2017, the Successor Period and Predecessor Period, the Company capitalized $0.7 million, $1.3 million, $0.4 million and $0.5 million, respectively, of qualifying restricted stock unit share-based compensation costs to oil and gas properties. Unrecognized expense as of December 31, 2018, for all outstanding RSUs under the 2016 LTIP Plan was $1.9 million and will be recognized over a weighted average period of 1.3 years. Stock Options On December 31, 2018, the Company had 70,102 options outstanding pursuant to the 2016 LTIP. Stock Option Awards granted under the 2016 LTIP vest ratably over a period of three years: one-sixth will vest on the six-month anniversary of the grant date, an additional one-sixth will vest on the twelve-month anniversary of the grant date, an additional one-third will vest on the twenty-four month anniversary of the grant date and the final one-third will vest on the thirty-six month anniversary of the grant date. Stock Option Awards expire 10 years from the grant date. If an employee terminates employment prior to the vesting date, the outstanding award is forfeited. Stock options are subject to accelerated vesting in the event a recipient’s employment is terminated prior to the vesting date by the Company without “Cause” or by the participant with “Good Reason” (each, as defined in the 2016 LTIP) or due to the participant’s death or disability. The Company utilizes the Black-Scholes-Merton option pricing model to determine the fair value of stock option awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated volatility. The weighted average assumptions used to estimate the fair value of stock option awards granted in 2017 and 2016 are as follows: Awards Issued in Awards Issued in 2017 2016 Weighted-average assumptions used: Risk-free interest rate (1) 2.11 % 1.38 % Dividend yield — — Expected option life (2) 5.96 Expected volatility (3) 65.0 % 60.0 % Calculated fair value per stock option $ 11.43 $ 10.88 (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the expected life of the option. (2) As the Company does not have significant history associated with stock options, expected option life assumptions were developed using the simplified method in accordance with US GAAP. A change in the expected option life of +/- 2 years would impact expense by $0.1 million and $(0.2) million for the Successor Period and $0.9 million and $(1.1) million over the vesting period of three years. Stock options granted during the year ended December 31, 2017 were not significant. (3) As the Company does not have significant stock option history, it utilized six peer companies of comparable size and industry to estimate volatility utilizing a period that is commensurate with the expected option life. The Company weighted historical volatility and implied volatility 50/50 for those peer companies where both were available, with volatility ranging in the peer companies from 36.9% to 68.2% in 2017 and 38.5% to 65.9% in 2016. The following table summarizes the Company’s 2016 LTIP non-vested stock option activity for the year ended December 31,2018 and 2017: Weighted Average Weighted Remaining Range of Average Contractual Options Exercise Prices Exercise Price Term (Years) Stock options outstanding at December 31, 2016 627,806 $ 19.66 8.8 Granted 4,000 $ 19.08 $ 19.08 9.2 Vested (253,678) $ 19.08 - 20.97 $ 19.66 — Forfeited (132,283) $ 19.66 $ 19.66 — Stock options outstanding at December 31, 2017 245,845 $ 19.66 8.9 Granted — $ — $ — — Vested (1) (170,173) $ 19.08 - 20.97 $ 19.66 7.8 Forfeited (5,570) $ 19.66 $ 19.66 — Stock options outstanding at December 31, 2018 70,102 $ 19.65 7.8 Vested and exercisable at end of period (1)(2) 136,161 $ 19.08 - 20.97 $ 19.67 7.8 (1) Vested stock options include 102,092 options in which vesting was accelerated as a result of a reduction in workforce that occurred during the twelve months ended December 31, 2018. Per the 2016 LTIP Plan, these vested options had to be exercised within 180 days of employees termination or they would expire and be returned to the Plan for future reissuance. All options expired on July 31, 2018, thereby reducing the total options vested and exercisable at December 31, 2018. (2) Vested and exercisable options at December 31, 2018, had no aggregate intrinsic value. The share-based compensation costs (net of amounts capitalized to oil and gas properties) related to stock options recognized as general and administrative expense by the Company for the years ended December 31, 2018, 2017 and 2016 was $0.9 million, $2.6 million and $0.8 million, respectively. For the years ended December 31, 2018, 2017 and 2016, the Company capitalized $0.2 million, $0.7 million and $0.2 million, respectively, of qualifying stock option share-based compensation costs to oil and gas properties. Unrecognized expense as of December 31, 2018 for all outstanding stock options was $0.2 million and will be recognized over a weighted average period of 0.8 years. Non-Employee Director Restricted Stock Units Containing a Market Condition On November 23, 2016, the Company issued 76,296 RSUs to its non-employee directors that contain a market vesting condition. These RSUs will vest (i) on the first business day following the date on which the trailing 60-day average share price (including any dividends paid) of the Company’s common stock is equal to or greater than $30.00 or (ii) upon a change in control of the Company. Additionally, all unvested RSUs containing a market vesting condition will be immediately forfeited upon the first to occur of (i) the fifth (5th) anniversary of the grant date or (ii) any participant’s termination for any reason (except for a termination as part of a change in control of the Company). These restricted stock awards are accounted for as liability awards under FASB Accounting Standards Codification (“ASC”) 718 as the awards allow for the withholding of taxes at the discretion of the non-employee director. The liability is re-measured, with a corresponding adjustment to earnings, at each fiscal quarter-end during the performance cycle. The derived service period related to these awards ended in November of 2017. As such, changes in the fair value of the liability and related compensation expense of these awards are no longer recognized pro-rata over the period for which service has already been provided but rather are compensation cost in the period in which the changes occur. As there are inherent uncertainties related to these factors and the Company's judgment in applying them to the fair value determinations, there is risk that the recorded compensation may not accurately reflect the amount ultimately earned by the non-employee directors. A Monte Carlo simulation was used in order to determine the fair value of these awards as of December 31, 2018 and 2017. The assumptions used to estimate the fair value of restricted stock unit awards with a market condition at December 31, 2018 and 2017 are as follows: December 31, 2018 December 31, 2017 Risk-free interest rate (1) 2.43 % 2.06 % Dividend yield — — Expected volatility (2) 39.0 % 54.8 % Market Price Hurdle $ 30.00 $ 30.00 Calculated fair value per restricted stock unit $ 0.41 $ 11.54 (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the expected life of the restricted stock unit. (2) As the Company did not have a significant stock trading history during the year ended December 31, 2017, it utilized six peer companies of comparable size and industry to estimate volatility utilizing a period that is commensurate with the expected option life. The Company weighted historical volatility and implied volatility 50/50 for those peer companies where both were available, with volatility ranging in the peer companies from 55.1% to 89.0%. The restricted stock unit awards issued to non-employee directors containing a market condition had a derived service period of one year. At December 31, 2018 and 2017, the Company recorded $0.1 million and $0.9 million, respectively, of liabilities included within accrued liabilities on the consolidated balance sheets related to the market condition awards. As of December 31, 2018, there was no unrecognized stock-based compensation related to director market condition awards. On November 7, 2018, Michael Reddin and Bruce Vincent resigned from the Board. Among other provisions, the Director’s forfeited all outstanding non-employee director restricted stock units containing a market condition. The following table reflects the outstanding non-employee director restricted stock unit awards containing a market condition for the year ended December 31, 2018 and 2017: Weighted Average Shares Fair Value Outstanding at December 31, 2017 76,296 $ 17.71 Granted — $ — Vested — $ — Forfeited(1) (25,432) $ — Outstanding at December 31, 2018 50,864 $ 17.71 (1) On November 7, 2018, Michael Reddin and Bruce Vincent resigned from the Board and forfeited all outstanding equity awards on November 12, 2018 Chief Executive Officer Restricted Stock Units Containing a Market Condition On November 1, 2017, the Company issued certain RSUs to our CEO that contain a market vesting condition. These RSUs will vest, if at all, based on the Company’s total stockholder return for the performance period of October 25, 2017 through October 31, 2020. Market conditions under this grant are (i) with respect to 50% of the RSUs granted, the Company’s cumulative total shareholder return (“TSR”) which is defined as the change in the value of the stock over the performance period with the beginning and ending stock price based on a 20-day average stock price and (ii) with respect to the remaining 50% of the RSUs granted, the Company’s “Relative TSR” as follows: Vesting as % of Vesting as % of 50% of RSUs 50% of RSUs Actual TSR for the Performance Period Granted Relative TSR for the Performance Period Granted Maximum 25% or greater compounded annual growth (“CAGR”) 120 % Top 5% or better Relative TSR to Peer Group 120 % Target 20% or greater CAGR 100 % Top 33.3% or better Relative TSR to Peer Group 100 % Threshold 15% or greater CAGR 50 % Top 50% or better Relative TSR to Peer Group 50 % Below Threshold Less than 15% CAGR % Less than 50% of Relative TSR to Peer Group % To the extent that actual TSR or Relative TSR for the performance period is between specified vesting levels, the portion of the RSUs that shall become vested based on actual and relative TSR performance shall be determined on a pro-rata basis using straight-line interpolation; provided that the maximum portion of the RSUs that may become vested based on actual cumulative TSR or relative TSR for the performance period shall not exceed 120% of the awards granted. If the CEO terminates employment prior to vesting, the outstanding award is forfeited. The CEO RSUs with a market condition are subject to accelerated vesting in the event the CEO’s employment is terminated prior to vesting by the Company without “Cause” or by the participant with “Good Reason” (each, as defined in the 2016 LTIP) or due to the participant’s death or disability. Upon a change in control, the compensation committee of the board of directors could (i) accelerate all or a portion of the award, (ii) cancel all of the award and pay cash, stock or combination equal to the change in control price, (iii) provide for the assumption or substitution or continuation by the successor company, (iv) certify to the extent to which the vesting conditions had been achieved prior to the conclusion of the performance period or (v) adjust RSUs to reflect the change in control. Upon a qualifying termination of employment within twelve months following a change in control, all unvested RSUs with a market condition immediately and fully vest at the Target Number of RSUs. These restricted stock awards are accounted for as equity awards under FASB ASC 718 as the awards are settled in shares of the Company with no additional settlement options permitted. At the grant date, the Company estimated the fair value of this equity award. The compensation expense of this award each period is recognized by dividing the fair value of the total award by the requisite service period and recording the pro-rata share for the period for which service has already been provided. As there are inherent uncertainties related to these factors and the Company's judgment in applying them to the fair value determinations, there is risk that the recorded compensation may not accurately reflect the amount ultimately earned by the CEO. A Monte Carlo simulation was used in order to determine the fair value of these awards at the grant date. The assumptions used to estimate the fair value of CEO’s restricted stock unit awards with a market condition are as follows: Awards Issued November 1, 2017 Risk-free interest rate (1) 1.74 % Dividend yield — Expected volatility 41.0% - 130.0 % Calculated fair value per unit $ (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the life of the CEO restricted stock unit award with a market condition. The RSUs issued to the CEO containing a market condition have a service period of three years. The share-based compensation costs related to the CEO RSUs containing a market condition recognized as general and administrative expense by the Company was $0.5 million at December 31, 2018. As of December 31, 2018, unrecognized stock-based compensation related to CEO RSUs containing a market condition was $0.9 million and will be recognized over a weighted-average period of 1.8 years. The following table reflects the outstanding CEO RSUs containing a market condition for the year ended December 31, 2018: Weighted Average Shares Fair Value Outstanding at December 31, 2017 135,778 $ 10.92 Granted — $ — Vested — $ — Forfeited — $ — Outstanding at December 31, 2018 135,778 $ 10.92 Performance Stock Units Issued to Certain Members of Executive Management Containing a Market Condition On March 1, 2018, the Company issued 96,305 restricted stock units to certain members of executive management that contain a market vesting condition. These restricted stock units will vest, if at all, based on the Company’s total stockholder return for the performance period of January 1, 2018 through December 31, 2020. Market conditions under this grant relate to the Company’s Relative TSR as follows: Relative TSR for the Performance Period Vesting as % of RSUs Granted Maximum Top 35% or better Relative TSR to Peer Group 150 % Target Top 50% or better Relative TSR to Peer Group 100 % Threshold Top 60% or better Relative TSR to Peer Group 50 % Below Threshold Less than 60% of Relative TSR to Peer Group 0 % To the extent that the Relative TSR for the performance period is between specified vesting levels, the portion of the restricted stock units that become vested based on the Relative TSR performance shall be determined on a pro-rata basis using straight-line interpolation; provided that the maximum portion of the restricted stock units that may become vested based on the Relative TSR for the performance period shall not exceed 150% of the awards granted. In addition, if the Relative TSR for the Company is negative over the performance period, vesting of these performance stock units is limited to no more than 100%. If a member of executive management terminates employment prior to vesting, the outstanding award is forfeited. Executive management restricted stock units with a market condition are subject to accelerated vesting in the event the executive’s employment is terminated prior to vesting by the Company without “Cause” or by the participant with “Good Reason” (each, as defined in the 2016 LTIP) or due to the executive’s death or disability. Upon a “Change in Control” (as defined in the 2016 LTIP), the compensation committee of the board of directors could (i) accelerate all or a portion of the award, (ii) cancel all of the award and pay cash, stock or combination equal to the change in control price, (iii) provide for the assumption or substitution or continuation by the successor company, (iv) certify to the extent to which the vesting conditions had been achieved prior to the conclusion of the performance period or (v) adjust restricted stock units to reflect the change in control. Upon a qualifying termination of employment within twelve months following a change in control, all unvested RSUs with a market condition immediately and fully vest at the Target Number of RSUs. These restricted stock awards are accounted for as equity awards under ASC 718 as the awards are settled in shares of the Company with no additional settlement options permitted. At the grant date, the Company estimated the fair value of this equity award. The compensation expense of this award each period is recognized by dividing the fair value of the total award by the requisite service period and recording the pro-rata share for the period for which service has already been provided. As there are inherent uncertainties related to these factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded compensation may not accurately reflect the amount ultimately earned by the executives. A Monte Carlo simulation was used in order to determine the fair value of these awards at the grant date. The assumptions used to estimate the fair value of the executive management restricted stock unit awards with a market condition are as follows: Awards Issued March 1, 2018 Risk-free interest rate (1) 2.34 % Dividend yield — Expected volatility 40.0% - 127.2 % Calculated fair value per unit $ 13.34 (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the life of the executives restricted stock unit award with a market condition. The share-based compensation costs (net of amounts capitalized to oil and gas properties) related to PSUs recognized as general and administrative expense by the Company for the year ended December 31, 2018 was $0.3 million. For the year ended December 31, 2018, the Company capitalized $0.1 million, of qualifying performance stock unit share-based compensation costs to oil and gas properties. The restricted stock units issued to executive management containing a market condition have a service period of three years. The share-based compensation costs related to executive management’s restricted stock units containing a market condition recognized as general and administrative expense by the Company was $0.4 million for the year ended December 31, 2018. As of December 31, 2018, unrecognized stock-based compensation related to executive management’s restricted stock units containing a market condition was $0.9 million and will be recognized over a weighted-average period of 2.0 years. The following table reflects the outstanding Executive Management restricted stock units containing a market condition for the year ended December 31, 2018: Weighted Average Shares Fair Value Outstanding at December 31, 2017 — $ — Granted 96,305 $ 13.34 Vested — $ — Forfeited — $ — Outstanding at December 31, 2018 96,305 $ 13.34 Unrestricted Common Share Awards On November 7, 2016, 12,400 shares of unrestricted stock were issued to employees and non-employee directors, which vested immediately upon issuance. For the Successor Period, total expense associated with these unrestricted vested common shares was $0.2 million. There was no unrecognized expense associated with these awards at December 31, 2018 or 2017. Stock-Based Compensation Expense Summary The following summarizes stock-based compensation expense for the periods presented (in thousands): Successor Predecessor For the For the Period Period October 21, January 1, 2016 2016 through through For the Year Ended December 31, December October 20, 2018 2017 31, 2016 2016 Restricted stock units (Predecessor) $ — $ — $ — $ 3,040 Restricted stock units (Successor) 5,207 7,083 2,114 — Stock options (Successor) 1,078 3,289 1,046 — Non-employee director restricted stock units with a market condition (Successor) (860) 736 142 — CEO restricted stock units with a market condition (Successor) 493 83 — — Performance Stock Units Issued to Certain Members of Executive Management Containing a Market Condition (Successor) 379 — — — Unres

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Taxes
Income Taxes	14. Income Taxes On December 22, 2017, the Tax Cuts and Jobs Act (“the Tax Act”) was enacted into law and the new legislation contains several key tax provisions that affected the Company, primarily a reduction of the corporate income tax rate to 21% effective January 1, 2018. The Company is required to recognize the effect of the tax law changes in the period of enactment, such as re-measuring our U.S. deferred tax assets and liabilities as well as reassessing the net realizability of our deferred tax assets and liabilities. In December 2017, the SEC staff issued Staff Accounting Bulletin (“SAB”) No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act, which allows the Company to record provisional amounts during a measurement period not to extend beyond one year of the enactment date. Therefore, the Company considered its accounting of certain items, as discussed below, to be incomplete as of December 31, 2017 due to forthcoming guidance and the ongoing analysis of final year-end data and tax positions. The Company had estimated deductions of $10.9 million associated with the full expensing of the costs of qualified property that were incurred and placed in service during the period from September 27, 2017 to December 31, 2017. The Company analyzed assets placed in service after September 27, 2017, but not qualifying for full expensing as a result of being acquired under an agreement entered into prior to that date. In addition, further guidance and analysis was required in order to review the terms of our compensation plans and agreements and assess the impact of transitional guidance related to IRC Section 162(m) on awards granted prior to November 2, 2017, subject to the grandfather provisions. As a result, the Company had not adjusted certain tax items previously reported on its financial statements for IRC Section 162(m) until it was able to obtain sufficient information to make a reasonable estimate of the effects of the Tax Act. During the three months ended December 31, 2018, the Company’s accounting for the income tax effects of the Tax Act was completed without material changes to the previously provided estimates and no change to its income tax expense previously reported. For the year ended December 31, 2018, the Company recorded no income tax expense or benefit. The significant difference between its effective tax rate and the federal statutory income tax rate of 21% is primarily due to the effect of changes in the Company’s valuation allowance. During the year ended December 31, 2018, the Company’s valuation allowance decreased by $10.5 million from December 31, 2017, bringing the total valuation allowance to $109.6 million at December 31, 2018. A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its deferred tax assets are realizable. As of December 31, 2018, the Company has not recorded a reserve for any uncertain tax positions. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. No federal income tax payments are expected in the upcoming four quarterly reporting periods. Successor Predecessor For the Period For the Period October 21, 2016 January 1, 2016 For the Year Ended December 31, through through 2018 2017 December 31, 2016 October 20,2016 (in thousands) (in thousands) Current United States $ — $ — $ — $ — State — — — — Total current — — — — Deferred United States — — — — State — — — — Total deferred — — — — Total income tax provision (benefit) $ — $ — $ — $ — The Company’s estimated income tax expense differs from the amount derived by applying the statutory federal rate to pretax income principally due the effect of the following items: Successor Predecessor For the Period For the Period October 21, 2016 January 1, 2016 For the Year Ended December 31, through through October 20, 2018 2017 December 31, 2016 2016 (in thousands) (in thousands) Income (loss) before taxes $ 49,784 $ (85,077) $ 9,930 $ 1,323,079 Statutory rate 21 % 35 % 35 % 35 % Income tax provision (benefit) computed at statutory rate 10,455 (29,777) 3,475 463,078 Reconciling items: State income taxes, net of federal benefit 2,157 (2,864) 296 39,424 Change in valuation allowance (10,515) (40,700) (3,876) (528,706) Adjustment to deferred tax assets and liabilities for enacted change in federal tax rate — 73,182 — — Parking expenses 35 — — — Change in state rate 28 (606) (1) (153) Bankruptcy items — — — 12,262 Deferred tax true-ups (1,520) (140) 74 9,891 Other, net (640) 905 32 4,204 Total income tax provision (benefit) $ — $ — $ — $ — Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of our deferred taxes are detailed in the table below (in thousands): As of As of December 31, December 31, 2018 2017 Deferred tax assets Federal tax loss carryforwards $ 60,874 $ 36,429 Derivative instruments and other — 813 State tax loss carryforwards 13,087 7,195 Employee benefit plans 3,086 3,053 Oil and gas properties and equipment 33,186 72,568 Disallowed interest expense 1,231 — Other 33 33 Less valuation allowance (109,574) (120,091) Total deferred tax assets $ 1,923 $ — Deferred tax liabilities Derivative instruments and other $ (1,923) $ — Oil and gas properties and equipment — — Total deferred tax liabilities $ (1,923) $ — Reflected in the accompanying balance sheet as: Net deferred tax asset (liability) $ — $ —

Income (Loss) Per Share

Income (Loss) Per Share	12 Months Ended
	Dec. 31, 2018
Income (Loss) Per Share
Income (Loss) Per Share	15. Income (Loss) Per Share Successor The following table provides a reconciliation of net income (loss) attributable to common shareholders and weighted-average common shares outstanding for basic and diluted income (loss) per share for the year ended December 31, 2018, 2017 and the Successor Period: For the Period October 21, 2016 Year Ended December 31, through 2018 2017 December 31, 2016 (in thousands, except per share amounts) Net Income (Loss): Net income (loss) $ 49,784 $ (85,077) $ 9,930 Participating securities-non-vested restricted stock (1,394) — (280) Basic and diluted income (loss) $ 48,390 $ (85,077) $ 9,650 Common Shares: Common shares outstanding - basic (1) 25,337 25,119 25,009 Dilutive effect of potential common shares — — — Common shares outstanding - diluted 25,337 25,119 25,009 Net Income (Loss) Per Share: Basic $ 1.91 $ (3.39) $ 0.39 Diluted $ 1.91 $ (3.39) $ 0.39 Antidilutive stock options (2) 206 466 627 Antidilutive warrants (3) 6,626 6,626 6,626 (1) Weighted-average common shares outstanding for basic and diluted income per share purposes includes 9,407 and 17,533, shares of common stock that, while not issued and outstanding at December 31, 2018 and 2017, respectively, are required by the Plan to be issued. Weighted-average common shares outstanding for basic and diluted income (loss) per share purposes also includes 40,054 director shares that vested at December 31, 2017, and 39,335 director shares that vested at December 31, 2018, but final issuance of the vested shares was deferred until 2020 and 2021, respectively. (2) Amount represents options to purchase common stock that are excluded from the diluted net income (loss) per share calculations because the options are antidilutive. (3) Amount represents warrants to purchase common stock that are excluded from the diluted net income (loss) per share calculations because the warrants are antidilutive. Predecessor The following table provides a reconciliation of net income (loss) to preferred shareholders, common shareholders, and participating securities for purposes of computing net income (loss) per share for the Predecessor Period: For the Period January 1, 2016 through October 20, 2016 (in thousands, except per share amounts) Net income (loss) $ 1,323,079 Preferred dividend (1) — Net income (loss) attributable to shareholders $ 1,323,079 Participating securities-Series A preferred stock(2) — Participating securities-Non-vested restricted stock(2) (16,522) Net income (loss) attributable to common shareholders $ 1,306,557 Weighted average shares outstanding 10,645 Basic and diluted net income (loss) per share $ 122.74 (1) Calculation of the preferred stock dividend is discussed in "- Note 12. Preferred Stock". (2) As these shares are participating securities that participate in earnings, but are not required to participate in losses, this calculation demonstrates that there is not an allocation of the loss to the non‑vested restricted stockholders.

Concentrations of Credit Risk

Concentrations of Credit Risk	12 Months Ended
	Dec. 31, 2018
Concentrations of Credit Risk
Concentrations of Credit Risk	16. Concentrations of Credit Risk Financial instruments which potentially subject the Company to credit risk consist primarily of cash balances, accounts receivable and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company normally sells production to a relatively small number of purchasers, as is customary in the exploration, development and production business. The Company typically sells a substantial portion of production under short‑term (usually one-month) contracts tied to a local index. The Company does not have any long‑term, fixed‑price sales contracts. For the year ended December 31, 2018, three purchasers accounted for 35%, 32% and 23%, respectively, of the Company's revenue. For the year ended December 31, 2017, three purchasers accounted for 37%, 25% and 14%, respectively, of the Company's revenue. For the Successor Period, two purchasers accounted for 40% and 29%, respectively, of the Company's revenue. For the Predecessor Period, two purchasers accounted for 46% and 29%, respectively, of the Company’s revenue. Substantially all of the Company’s accounts receivable result from the sale of oil, NGLs and natural gas. At December 31, 2018, two purchasers accounted for approximately 71% and 26%, respectively, of the accounts receivable balance. At December 31, 2017, three purchasers accounted for approximately 42%, 35% and 10%, respectively, of the accounts receivable balance. Derivative financial instruments are generally executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. The Company also has netting arrangements in place with counterparties to reduce credit exposure. The Company has not experienced any losses from such instruments. The Company had commodity derivative contract positions in place at December 31, 2018 and 2017. The Company did not have any open commodity derivative contract positions at December 31, 2016.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies
Commitments and Contingencies	17. Commitments and Contingencies Contractual Obligations At December 31, 2018, contractual obligations for drilling contracts, long‑term operating leases and other contracts are as follows (in thousands): 2023 and Total 2019 2020 2021 2022 beyond Drilling contracts $ — $ — $ — $ — $ — $ — Non-cancellable office lease commitments 5,335 665 678 690 702 2,600 Net minimum commitments $ 5,335 $ 665 $ 678 $ 690 $ 702 $ 2,600 For the year ended December 31, 2018, 2017, the Successor Period and the Predecessor Period, the Company expensed $0.6 million, $0.6 million, $0.1 million and $4.3 million, respectively, for office rent. In addition to the commitments noted in the above table, the Company is party to a gas purchase, gathering and processing contract in the Mississippian Lime region, which includes certain minimum NGL volume commitments. To the extent the Company does not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLs, it would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee. The Company is currently delivering at least the minimum volumes required under these contractual provisions. However, decreased drilling activity could result in the inability to meet these commitments in the future. Commitments related to ARO’s are not included in the table above. For additional information, please see “—Note 10. Asset Retirement Obligations” for further discussion. Litigation The Company is involved in various matters incidental to its operations and business that might give rise to a loss contingency. These matters may include legal and regulatory proceedings, commercial disputes, claims from royalty, working interest and surface owners, property damage and personal injury claims and environmental authorities or other matters. In addition, the Company may be subject to customary audits by governmental authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as compliance with unclaimed property (escheatment) requirements and other laws. Further, other parties with an interest in wells operated by the Company have the ability under various contractual agreements to perform audits of its joint interest billing practices. The Company vigorously defends itself in these matters. If the Company determines that an unfavorable outcome or loss of a particular matter is probable and the amount of loss can be reasonably estimated, it accrues a liability for the contingent obligation. As new information becomes available or as a result of legal or administrative rulings in similar matters or a change in applicable law, the Company’s conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. The impact of subsequent changes to the Company’s accruals could have a material effect on its results of operations. As of December 31, 2018 and 2017, the Company’s total accrual for all loss contingencies was $1.1 million. During the year ended December 31, 2017, the Company received an insurance reimbursement in the amount of $1.9 million, which was reflected as a reduction of “Lease operating and workover” expenses in the consolidated statements of operations.

Supplemental Information to Con

Supplemental Information to Consolidated Statement of Cash Flows	12 Months Ended
	Dec. 31, 2018
Supplemental Information to Consolidated Statement of Cash Flows
Supplemental Information to Consolidated Statement of Cash Flows	18. Supplemental Information to Consolidated Statement of Cash Flows The following table summarizes interest and income taxes paid for the periods presented and supplemental non-cash investing and financing activities (in thousands): Successor Predecessor Period Period October 21, January 1, 2016 through 2016 through Year Ended December 31, December 31, October 20, 2018 2017 2016 2016 SUPPLEMENTAL INFORMATION: Non-cash investment in property and equipment $ 6,092 $ 17,164 $ 8,135 $ 12,995 Non-cash exchange of common equity of the reorganized Company for second lien notes $ — $ — $ — $ 591,042 Non-cash exchange of common equity and warrants of the reorganized Company for third lien notes $ — $ — $ — $ 556,136 Non-cash exchange of common equity and warrants of the reorganized Company for 2020 senior notes $ — $ — $ — $ 312,039 Non-cash exchange of common equity and warrants of the reorganized Company for 2021 senior notes $ — $ — $ — $ 361,050 Cash paid for interest, net of capitalized interest for the year ended December 31, 2018, December 31, 2017, and the Successor Period of $0.5 million, $2.4 million and $0.7 million, respectively (no capitalized interest for the Predecessor Period) $ 4,128 $ 5,353 $ 426 $ 6,709 Cash paid for reorganization items $ — $ — $ — $ 36,325

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2018
Related Party Transactions
Related Party Transactions	19. Related Party Transactions During the year ended December 31, 2017, the Company entered into an arrangement with EcoStim Energy Solutions, Inc. ("EcoStim") for well stimulation and completion services. EcoStim is an affiliate of Fir Tree Inc. For the year ended December 31, 2017, the Company paid approximately $11.6 million to EcoStim for services provided. The Company had $2.1 million included in accounts payable at December 31, 2017, to EcoStim in the consolidated balance sheets that was paid during the year ended December 31, 2018. No transactions with EcoStim occurred in the Successor Period or the Predecessor Period. During the Predecessor Period, First Reserve Corporation, which owned an economic interest in the Company through FR Midstates Interholding LP, also owned an economic interest in Dixie Electric. For the Predecessor Period, the Company paid approximately $1.7 million for electrical equipment and related services from Dixie Electric. No transactions with Dixie Electric occurred in any other reported period.

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2018
Subsequent Event
Subsequent Event	20. Subsequent Event On January 14, 2019, we announced the commencement of a tender offer to repurchase up to 5,000,000 shares of common stock at the offer price of $10.00 per share in the first quarter of 2019. On February 14, 2019, the tender offer was completed with 5,000,000 shares of common stock purchased at a purchase price of $10.00 per share. The Company partially funded the stock buyback by drawing down $39.0 million from our Exit Facility, with the remainder funded by cash on hand. The outstanding warrants of the Company were also adjusted as a result of the completion of the tender offer. The exercise price of the Third Lien Notes Warrants were adjusted from $24.00 per share to $22.78 per share and the exercise price of the Unsecured Creditor Warrants were adjusted from $46.00 per share to $43.67 per share. Further, the number of shares eligible to be received upon exercise of each warrant was adjusted by a factor of 1.05. The Third Lien Notes Warrants and the Unsecured Creditor Warrants may be exercised for up to an aggregate of 4,647,520 and 2,332,089 shares of common stock, respectively. On January 30, 2019, the Company had a reduction in workforce resulting in severance costs of $1.2 million, excluding accelerated vesting of shares granted to employees under the 2016 LTIP.

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Dec. 31, 2018
Supplemental Oil and Gas Disclosures (Unaudited)
Supplemental Oil and Gas Disclosures (Unaudited)	21. Supplemental Oil and Gas Disclosures (Unaudited) The supplemental data presented herein reflects information for all of the Company’s oil and natural gas producing activities. Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the year ended December 31, 2018, 2017, the Successor Period and the Predecessor Period (in thousands): Successor Predecessor For the Period For the Period October 21, 2016 January 1, 2016 For the Year Ended December 31, through December 31, through October 20, 2018 2017 2016 2016 Acquisition costs: Proved properties $ — $ — $ — $ — Unproved properties 6,711 11,964 1,430 6,869 Exploration costs — — — — Development costs 93,965 128,424 17,708 121,668 Total costs incurred $ 100,676 $ 140,388 $ 19,138 $ 128,537 The Company capitalizes certain of its general and administrative expenses that are incurred as a result of acquisition, exploration and development activities. These amounts are included in the above table under development costs and totaled $2.8 million, $5.3 million, $1.4 million and $3.4 million for the year ended December 31, 2018, 2017, the Successor Period and the Predecessor Period, respectively. In addition, the Company capitalizes interest costs incurred and attributable to unproved oil and gas properties as well as major development projects of oil and gas properties. Capitalized interest expenses, which are included in the development costs in the above table, were $0.5 million, $2.4 million and $0.7 million for the year ended December 31, 2018, 2017 and Successor Period. Capitalized Costs The following table sets forth the capitalized costs related to the Company's oil and natural gas producing activities as of December 31, 2018 and 2017 (in thousands): December 31, 2018 December 31, 2017 Proved properties $ 809,272 $ 765,308 Unproved properties not being amortized 4,050 7,065 Gross capitalized costs 813,322 772,373 Less: Accumulated depreciation, depletion, amortization and impairment (261,705) (201,722) Net capitalized costs $ 551,617 $ 570,651 At December 31, 2018, the Company had $4.1 million of oil and gas property costs that are not being amortized. The value of the Company’s oil and gas properties not being amortized are associated with the Company’s Mississippian Lime area. We expect the majority of these costs will be evaluated and either impaired or become subject to depletion within five years. Estimated Quantities of Proved Oil and Natural Gas Reserves The reserve estimates at December 31, 2018, 2017 and 2016 for Company were based on reports prepared by Cawley, Gillespie & Associates, Inc., independent reserve engineers. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. The following table sets forth the Company’s net proved, proved developed and proved undeveloped reserves at December 31, 2018, 2017 and 2016: Oil NGL Gas Total (MBbl) (MBbl) (MMcf) (MBoe) 2016 (Predecessor) Proved Reserves Beginning Balance 24,713 16,245 195,492 73,540 Revision of previous estimates (3,089) (459) (946) (3,706) Extensions, discoveries and other additions 1,566 840 11,052 4,249 Sales of reserves in place — — — — Purchases of reserves in place — — — — Production (2,964) (1,932) (23,215) (8,765) Net proved reserves at October 20, 2016 20,226 14,694 182,383 65,318 Proved developed reserves, October 20, 2016 20,226 14,694 182,383 65,318 Proved undeveloped reserves, October 20, 2016 — — — — 2016 (Successor) Proved Reserves Beginning Balance 20,226 14,694 182,383 65,318 Revision of previous estimates 19,137 11,421 147,688 55,172 Extensions, discoveries and other additions 22,571 11,186 147,236 58,296 Sales of reserves in place — — — — Purchases of reserves in place — — — — Production (544) (429) (4,948) (1,798) Net proved reserves at December 31, 2016 61,390 36,872 472,359 176,988 Proved developed reserves, December 31, 2016 19,698 16,349 201,454 69,622 Proved undeveloped reserves, December 31, 2016 41,692 20,523 270,905 107,366 2017 Proved Reserves Beginning Balance 61,390 36,872 472,359 176,988 Revision of previous estimates (33,608) (13,010) (178,388) (76,350) Extensions, discoveries and other additions 5,819 4,003 51,849 18,464 Sales of reserves in place (99) (723) (7,495) (2,071) Purchases of reserves in place — — — — Production (2,368) (1,949) (22,606) (8,084) Net proved reserves at December 31, 2017 31,134 25,193 315,719 108,947 Proved developed reserves, December 31, 2017 17,268 15,464 190,550 64,490 Proved undeveloped reserves, December 31, 2017 13,866 9,729 125,169 44,457 2018 Proved Reserves Beginning Balance 31,134 25,193 315,719 108,947 Revision of previous estimates (13,765) (6,347) (114,092) (39,127) Extensions, discoveries and other additions 5,454 4,462 48,382 17,979 Sales of reserves in place (2,838) (2,414) (20,778) (8,714) Purchases of reserves in place — — — — Production (1,920) (1,623) (18,718) (6,663) Net proved reserves at December 31, 2018 18,065 19,271 210,513 72,422 Proved developed reserves, December 31, 2018 10,995 13,425 147,248 48,962 Proved undeveloped reserves, December 31, 2018 7,070 5,846 63,265 23,460 Revision of Previous Estimates For the year ended December 31, 2018, the Company had net negative revisions of 39,127 MBoe. These negative revisions were driven by several factors. First, the Company has prioritized development of two-mile laterals along with certain one-mile laterals with higher working interests. To accomplish this development schedule, the Company currently anticipates drilling to occur no later than 2020 and continue for approximately three years after than date. The Company’s updated development plan resulted in an overall decrease in proved undeveloped locations and associated volumes. All undeveloped locations not able to be drilled utilizing the Company’s anticipated development schedule were excluded from the December 31, 2018 reserve report but continue to meet the definition of a proved undeveloped location from an engineering standpoint. Additionally, the Company undertakes a process to update the various assumptions inherent in the preparation of its proved reserves. For the year ended December 31, 2018, the primary updates to its assumptions that impacted the revision of proved reserves were downward revisions to forecasted production offset partially by upward revisions to the Company’s forecasted operating expenses. The development of production curves requires an analysis of historical production by well, and trends in that production are utilized for forecasting purposes. The Company’s expectations of forecasted lease operating expenses are also based upon historical costs and for 2018 are primarily allocated based upon forecasted water production by well for the Mississippian Lime asset. For the year ended December 31, 2017, the Company had net negative revisions of 76,350 MBoe primarily as a result of updates to the Company’s anticipated five-year development schedule. On November 1, 2017, David Sambrooks was appointed President and Chief Executive Officer of the Company. Upon David’s appointment, the Company began a strategic review of all areas of operations. This review was completed during the fourth quarter of 2017 and the Company’s strategy was refined to add further focus to optimizing free cash flows and keeping leverage to a minimum. The Company’s five-year development plan was revised from a two-rig program to a one rig program, which lead to a reduction in the Company’s undeveloped proved inventory under SEC guidelines from 274 locations at year end 2016 to 139 locations at year end 2017. All undeveloped locations not able to be drilled utilizing the Company’s anticipated five-year development schedule were excluded from the December 31, 2017 reserve report. For the Successor Period, the Company had positive revisions of 55,172 MBoe. Upon the Company’s emergence on the Effective Date, it undertook a process to review its five-year development schedule in light of improved commodity pricing and the significant improvement in the Company’s liquidity and outstanding long-term debt. In developing the Company’s updated five-year development schedule, the Company considered the forward pricing curve, the returns expected of its drilling program and cash available during this time period, which would include cash on hand, cash generated by operations and cash from borrowings. Based upon these factors, the Company developed an updated five-year development plan and booked proved undeveloped reserves based upon its strategy to capture additional acreage through drilling. Proved undeveloped reserves that were removed from proved category in prior years but subsequently reinstated after this review were classified as a revision in the above tables. For the year ended December 31, 2015, the Company had net negative revisions of 75,700 MBoe related to proved undeveloped reserves, of which approximately 98% related to reductions in the Mississippian Lime area due to the transfer of 77,362 MBoe of proved undeveloped reserves comprising $179.0 million of PV‑10 value (at SEC pricing) to the probable reserves category due to uncertainty around financing the development of our proved undeveloped reserves within a five year period. Extensions, Discoveries and Other Additions For the year ended December 31, 2018 and 2017, the Company had 17,979 MBoe and 18,464 MBoe, respectively, of extensions and discoveries, all of which occurred in the Mississippian Lime area. For the Successor Period, the Company had For the Predecessor Period, the Company had 4,249 MBoe of additions from extensions and discoveries, all of which related to the Mississippian Lime area. Sales of Reserves in Place For the year ended December 31, 2017, the Company had 8,714 MBoe in sales of reserves of place, all of which was associated with the divestiture of its Anadarko Basin assets, which occurred on May 31, 2018. For the year ended December 31, 2017, the Company had 2,071 MBoe in sales of reserves in place, all of which was associated with the divestiture of its oil and gas properties in Lincoln County, Oklahoma, which occurred during July 2017. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs. The Company’s estimated proved reserves and related future net revenues and standardized measure were determined using the unweighted arithmetic average first-of-the-month price for the preceding 12-month period, without giving effect to derivative transactions, and were held constant throughout the life of the properties. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. The following table sets forth the benchmark prices used to determine estimated proved reserves for the periods indicated: At December 31, 2018 2017 2016 Oil and Natural Gas Prices: Oil (per barrel) $ 65.56 $ 51.34 $ 42.75 Natural gas (per million British thermal units) $ 3.10 $ 2.98 $ 2.48 The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s oil and natural gas reserves at December 31, 2018, 2017, and 2016 (in thousands): At December 31, 2018 2017 2016 Future cash inflows $ 2,131,791 $ 3,023,929 $ 4,186,389 Future production costs (695,677) (1,536,332) (2,078,640) Future development costs (159,400) (370,972) (692,533) Future income tax expense (52,778) (16,289) (106,563) Future net cash flows 1,223,936 1,100,336 1,308,653 10% annual discount for estimated timing of cash flows (657,660) (551,093) (778,703) Standardized measure of discounted future net cash flows $ 566,276 $ 549,243 $ 529,950 The following table sets forth the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the year ended December 31, 2018, 2017, the Successor Period and the Predecessor Period (in thousands): Successor Predecessor For the Period October For the Period January Year Ended December 31, 21, 2016 through 1, 2016 through 2018 2017 December 31, 2016 October 20, 2016 Standardized measure, beginning of period $ 549,243 $ 529,950 $ 349,905 $ 512,819 Net changes in prices and production costs 182,133 173,991 78,103 (113,313) Net changes in future development costs (639) (29,711) 2,022 175 Sales of oil and natural gas, net (134,681) (148,746) (27,292) (116,043) Extensions 134,496 92,776 102,087 29,871 Discoveries — — — — Purchases of reserves in place — — — — Divestiture of reserves (52,952) (8,079) — — Revisions of previous quantity estimates (162,513) (152,517) 102,623 (22,194) Previously estimated development costs incurred 28,443 7,909 — 29,975 Accretion of discount 55,813 57,816 5,832 42,735 Net change in income taxes (4,483) 39,316 (48,206) — Changes in timing, other (28,584) (13,462) (35,124) (14,120) Standardized measure, end of period $ 566,276 $ 549,243 $ 529,950 $ 349,905

Selected Quarterly Financial Da

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2018
Selected Quarterly Financial Data
Selected Quarterly Financial Data	22. Selected Quarterly Financial Data (Unaudited) The following table presents selected quarterly financial data derived from the Company’s unaudited interim financial statements. The following data is only a summary and should be read with the Company’s historical consolidated financial statements and related notes contained in this document. First Second Third Fourth Quarter Quarter Quarter Quarter (in thousands, except per share amounts) 2018 Total revenues $ 48,905 $ 42,324 $ 47,765 $ 69,643 Operating income (loss) 5,812 (245) 12,170 36,514 Net income (loss) 4,004 (1,542) 11,516 35,806 Net income (loss) available to common shareholders 3,905 (1,542) 11,165 34,862 Net income (loss) per share: Basic and Diluted $ 0.15 $ (0.06) $ 0.44 $ 1.38 Shares used in computation: Basic and Diluted 25,299 25,332 25,332 25,385 2017 Total revenues $ 65,015 $ 60,679 $ 49,715 $ 53,344 Operating income (loss) 19,462 14,970 5,312 (119,238) Net income (loss) 18,485 13,742 3,663 (120,967) Net income (loss) available to common shareholders 17,939 13,382 3,581 (120,967) Net income (loss) per share: Basic and Diluted $ 0.72 $ 0.53 $ 0.14 $ (4.78) Shares used in computation: Basic and Diluted 25,012 25,093 25,116 25,253

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Summary of Significant Accounting Policies
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared pursuant to the rules and regulations of the SEC and have been prepared in accordance with US GAAP. All intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the period October 21, 2016 through December 31, 2016 are referred to as the Successor Period, and the period January 1, 2016 through October 20, 2016 is referred to as the Predecessor Period. The Company’s management evaluates performance based on one reportable segment as all its operations are located in the United States and therefore it maintains one cost center. As a result of the adoption of Accounting Standards Update 2014-09, “ Revenue from Contracts with Customers (Topic 606) ” (“ASU 2014-09”), certain balances included in the consolidated statements of operations for prior periods have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on net income, cash flows or stockholders’ equity for any period presented.
Fresh Start Accounting	Fresh Start Accounting Upon emergence from bankruptcy, the Company adopted fresh start accounting. Adopting fresh start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, the Company's consolidated financial statements on or after October 21, 2016, are not comparable with the Company's consolidated financial statements prior to that date.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company utilizes historical experience as well as other assumptions that are believed to be reasonable under the circumstances in preparing its estimates. The Company evaluates estimates and assumptions on a regular basis. Actual results could differ from those estimates and assumptions used in the preparation of the Company’s financial statements. Significant estimates include, but are not limited to the estimates of reorganization value, enterprise value and fair value of assets and liabilities upon emergence from bankruptcy and application of fresh start accounting, the estimate of revenue recognition, the estimate of recoverable oil and natural gas reserves and related present value estimates of future net cash flows derived therefrom, legal and environmental risks and exposures, the fair value of share-based compensation, income taxes and the valuation of future asset retirement obligations.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company considers all short-term investments with an original maturity of three months or less to be cash equivalents. The Company’s total cash balances are insured by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 per bank per depositor. The Company had cash balances on deposit at December 31, 2018 and 2017, that exceeded the balance insured by the FDIC in the amount of $12.8 million and $70.4 million, respectively.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are stated at the historical carrying amount net of any allowance for uncollectible accounts. The carrying amount of the Company’s accounts receivable approximate fair value because of the short-term nature of the instruments. Many of the Company’s receivables are from joint interest owners in properties in which the Company is the operator. The Company may withhold future revenue disbursements to recover any non-payment of these joint interest billings under certain circumstances. The Company routinely assesses the collectability of all material trade and other receivables and the Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2018 and 2017, the Company had no allowance for doubtful accounts.
Financial Instruments	Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, debt, and commodity derivative contracts. Commodity derivative contracts are recorded at fair value; see “— Note 6. Fair Value Measurements of Financial Instruments”. The fair value of the Company’s long-term debt is disclosed, see “— Note 11. Debt”. The carrying amount of the Company’s other financial instruments approximate fair value because of the short-term nature of the items or variable pricing. Derivative financial instruments, if held by the Company, are presented in the consolidated balance sheets as either an asset or liability measured at estimated fair value. Changes in the derivative’s fair value are recognized in the consolidated statement of operations as gains and losses in the period of change. The gains or losses are recorded in “Gains on commodity derivative contracts—net.” The related cash flow impact is reflected within cash flows from operating activities.
Property and Equipment	Property and Equipment Oil and Gas Properties The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, costs of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company’s reserve quantities are sold such that it results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income. Unevaluated Property Oil and gas unevaluated properties and properties under development include costs that are not being depleted or amortized. These costs represent investments in unproved properties. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are transferred to proved properties, become part of our depletion base and become subject to the full cost ceiling limitation. During the year ended December 31, 2018 and 2017, the Company transferred $3.0 million and $58.0 million,respectively, of unevaluated property to the full cost pool. As discussed below under “—Note 9. Acquisition and Divestitures of Oil and Gas Properties”, the Company divested its Anadarko Basin assets in the second quarter of 2018. As part of that divestiture, all remaining unevaluated property, or approximately $3.0 million was allocated to the full cost pool. As discussed below under “Impairment of Oil and Gas Properties/Ceiling Test” the Company’s strategy was refined during 2017 to focus on optimizing free cash flow, keeping leverage to a minimum and drilling only those locations that had the best probability of a reasonable rate of return. Therefore, unevaluated property value not associated with the Company’s refined drilling focus were allocated to the full cost pool at December 31, 2017. Oil and Gas Reserves Proved oil, NGLs and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company depletes its oil and gas properties using the units-of-production method. Capitalized costs of oil and natural gas properties subject to amortization are depleted over proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. Impairment of Oil and Gas Properties/Ceiling Test The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit, or ceiling, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization (“DD&A”) and the related deferred income taxes, may not exceed this ceiling. The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales prices received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations. For the year ended December 31, 2017,and the Predecessor Period, the Company recorded impairments of oil and gas properties of $125.3 million and $232.1 million, respectively. The Company recorded an impairment of oil and gas properties of $125.3 million primarily as a result of the exclusion of proved undeveloped reserves not associated with infill drilling in the Carmen and Dacoma areas from its December 31, 2017, reserve report. During the Predecessor Period, a significant and sustained decline in the average oil and natural gas sales price utilized in calculating the present value of estimated future net revenues from projected production of oil and gas reserves was the primary factor that led to the full-cost ceiling impairments. The Company did not record an impairment of oil and gas properties for the year ended December 31, 2018. Depletion Depletion of oil and gas properties is calculated using the units of production method (“UOP”). The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reserves are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated depletion, estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value. Capitalized Interest Interest is capitalized for certain unevaluated oil and gas properties with ongoing development activities using the weighted-average cost of outstanding borrowings, which also includes the amortization of debt costs. Capitalized interest is depleted over the useful lives of the assets in the same manner as the depletion of the underlying assets. Other Property and Equipment Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and is carried at cost. Depreciation is provided principally using the straight‑line method over the estimated useful lives of the assets, which primarily range from two to ten years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.
Accrued Liabilities	Accrued Liabilities At December 31, 2018 and 2017, accrued liabilities consisted of the following (in thousands): December 31, 2018 December 31, 2017 Accrued oil and gas capital expenditures $ 1,534 $ 9,081 Accrued revenue and royalty distributions 13,302 18,701 Accrued lease operating and workover expense 2,843 5,150 Accrued interest 209 108 Accrued taxes 1,813 2,758 Compensation and benefit related accruals 2,855 4,520 Other 2,965 2,524 Accrued liabilities $ 25,521 $ 42,842
Asset Retirement Obligations	Asset Retirement Obligations The legal obligations associated with the retirement of long‑lived assets are recognized at the time that the obligation is incurred. Oil and gas producing companies incur such a liability upon drilling or acquiring a well. The Company estimates the amount of an asset retirement obligation in the period in which the obligation is incurred and can be reliably measured. The corresponding asset retirement cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depleted over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, any adjustment is recorded to the full cost pool. See “-Note 10. Asset Retirement Obligations”.
Share-Based Compensation	Share‑Based Compensation The Company measures share-based compensation cost at fair value and generally recognizes the corresponding compensation expense on a straight-line basis over the service period during which awards are expected to vest for periods prior to the Effective Date. For periods subsequent to the Effective Date, the Company recognizes compensation expense on graded and straight-line vesting basis. Share-based compensation expense, net of amounts capitalized to oil and gas properties, is included in “General and administrative” expense in our consolidated statements of operations and “Accrued liabilities” in our consolidated balance sheets. See “—Note 13. Equity and Share-Based Compensation”.
Revenue recognition	Revenue Recognition On January 1, 2018, we adopted ASC 606, using the modified retrospective method of transition. The primary impact to our revenues as a result of the adoption of ASC 606 is the netting of certain deductions and costs against revenue instead of the historical practice of presenting such expenses gross in gathering and transportation. Oil, NGLs and natural gas revenues are recognized at the point in time that control of the product is transferred to the customer and collectability is reasonably assured. Other revenue consists of iodine royalty income, which are point in time sales, and salt water disposal income, which is recognized over time. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company’s share of remaining proved oil and gas reserves. The Company had no significant imbalances at December 31, 2018 and 2017.
Acquisition and Transaction Costs	Acquisition and Transaction Costs Acquisition and transaction related costs are expensed as incurred and as services are received. Such costs include finders’ fees, advisory, legal, accounting, valuation and other professional and consulting fees, and acquisition related general and administrative costs. See “—Note 9. Acquisition and Divestitures of Oil and Gas Properties”.
Income Taxes	Income Taxes Income taxes are recorded for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates. The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-than-likely-than-not recognition threshold are recognized. In December of 2017, the U.S. government enacted comprehensive tax legislation that includes significant changes to the taxation of business entities, including, among other provisions, a permanent reduction to the corporate income tax rate. See “—Note 14. Income Taxes” for further information.
Income (Loss) Per Share	Income (Loss) Per Share Net income (loss) per common share is calculated utilizing the two-class method by dividing net income (loss) available to common shareholders by the weighted-average number of common shares outstanding during each period. Diluted net income (loss) per common share is calculated under the two-class method and the treasury stock method by dividing net income (loss) available to common shareholders by the weighted-average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted net income (loss) per share calculations consist of unvested restricted stock awards, warrants and outstanding stock options for the years ended December 31, 2018 and 2017, and the Successor Period. Potentially dilutive securities for the diluted net income (loss) per share calculations consist of the Company’s Series A Preferred Stock using the if-converted method (in periods prior to the Preferred Stock’s mandatory conversion date) and unvested restricted stock awards for the Predecessor Period. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted net income (loss) per share. See “—Note 15. Income (Loss) Per Share.”
Recent Accounting Pronouncements Adopted and Not Yet Adopted During the Period	Recent Accounting Pronouncements Adopted During the Period In March 2018, the FASB issued Accounting Standards Update 2018-05, “Income Taxes (Topic 740), Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118”. ASU 2018-05 amends certain SEC paragraphs pursuant to the issuance of the December 2017 SEC SAB 118, which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act’s enactment date for companies to complete its accounting under ASC 740. In accordance with SAB 118, to the extent a company has not completed its analysis of the Tax Act but can provide a reasonable estimate, it must record a provisional estimate in its financial statements. The Company has completed its accounting for certain tax effects of the Tax Act under the guidance of SAB 118. See “—Note 14. Income Taxes” for further information. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”. ASU 2014-09 provides guidance concerning the recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09 is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The Company adopted ASU 2014-09 using the modified retrospective approach. The adoption of this guidance did not have a material impact on the Company’s financial statements. See “— Note 5. Impact of ASC 606 Adoption” for further information. Recent Accounting Pronouncements Issued But Not Yet Adopted In June 2018, the FASB issued ASU 2018-07, “ Compensation - Stock Compensation (Topic 718) — Improvements to Nonemployee Share-Based Payment Accounting ”. ASU 2018-07 expands the scope of Topic 718 to include share-based payments issued to nonemployees for goods and services. Consequently, the accounting for share-based payments to nonemployees and employees will be substantially aligned. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company does not believe the adoption of ASU 2018-07 will have a material impact on its financial position, results of operations or cash flows. In July 2017, the FASB issued ASU 2017-11, “Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815)”. ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present EPS in accordance with Topic 260 to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company does not believe the adoption of ASU 2017-11 will have a material impact on its financial position, results of operations or cash flows. In February 2016, the FASB issued ASU 2016-02, “ Leases (Topic 842) ”. ASU 2016-02 establishes a ROU model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. All leases create an asset and a liability for the lessee and therefore recognition of those lease assets and lease liabilities is required by ASU 2016-02. When measuring lease assets and liabilities, payments to be made in optional extension periods should be included if the lessee is reasonably certain to exercise the option. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 will not impact the accounting or financial presentation of the our mineral leases. For finance leases, the Company will recognize a ROU asset and liability, initially measured at the present value of the lease payments. Interest expense will be recognized on the lease liability separately from the amortization of the ROU asset. The Company will recognize payments of principal on the lease liability within financing activities in the consolidated statement of cash flows and payments of interest within operating activities in the consolidated statement of cash flows. For operating leases, the Company will recognize a ROU asset and liability, initially measured at the present value of the lease payments. The Company will recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis and all cash payments will be recognized in operating activities within the consolidated statement of cash flows. In January 2018, the FASB issued Accounting Standards Update 2018-01, “ Leases (Topic 842)-Land Easement Practical Expedient for Transition to Topic 842 ” (“ASU 2018-01”). ASU 2018-01 permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expired prior to a company’s adoption of ASU 2016-02 and that were not accounted for as leases under previous lease guidance. Additionally, in July 2018, the FASB issued Accounting Standards Update 2018-11,” Leases (Topic 842):Targeted Improvements , which included the option to implement the standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings, as opposed to the modified retrospective transition method required when ASU 2016-02 was issued. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company has analyzed and categorized its contracts to determine if they meet the definition of a lease under ASU 2016-02. The Company plans to adopt the new standard using the simplified transition method described in ASU 2018-11. Consequently, financial information will not be updated and the disclosures required under the new standard will not be provided for the dates and periods before January 1, 2019. Additionally, the Company plans to elect the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases, but does not plan to elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. The Company also plans to elect the practical expedient under ASU 2018-01 and not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. The Company is working to complete its evaluation of the impact of ASU 2016-02 on its financial statements, accounting policies and internal controls, including implementation of systems and processes to capture, classify and account for leases within the scope of the new guidance and to provide the related disclosures. At this time, the impact upon adoption of ASU 2016-02 and other related ASUs is expected to result in recognition of additional operating liabilities ranging from $4.0 million to $7.0 million, with corresponding right-of-use assets of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing leases. The new standard also provides practical expedients for an entity’s ongoing accounting. The Company currently expects to elect the short-term lease recognition exemption for all leases that qualify. The Company also currently expects to elect the practical expedient to not separate lease and non-lease components for the majority of classes of underlying assets.

Fresh Start Accounting (Tables)

Fresh Start Accounting (Tables)	12 Months Ended
	Dec. 31, 2018
Fresh Start Accounting
Schedule of Enterprise value to estimated fair value per share	The following table presents the estimated fair value of the Company’s stock as of the Effective Date (in thousands, except per share value): As of October 21, 2016 Enterprise value $ 600,000 Plus: Cash and cash equivalents 76,540 Less: Fair value of debt (128,059) Less: Fair value of warrants (37,329) Fair value of stock on the Effective Date $ 511,152 Total shares issuable under the Plan 25,000 Restricted shares granted under 2016 LTIP at October 21, 2016 686 Total shares 25,686 Per share value (1) $ 19.90 (1) The per share value shown above was calculated based upon the financial information determined using US GAAP at the Effective Date. The fair value per share agreed upon by the parties to the Chapter 11 Cases at the Effective Date was determined to be $19.66 per common share.
Schedule of assumptions used to estimate the fair value of the Warrants	Third Lien Notes Unsecured Warrants Creditor Warrants Risk-free interest rate (1) 1.04 % 1.04 % Dividend yield — — Expected life (2) 3.50 3.50 Expected volatility (3) 55.0 % 55.0 % Strike Price $ 24.00 $ 46.00 Calculated fair value $ 6.74 $ 3.42 (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the expected life of the option. (2) The expected life assumption was based upon the years until expiration of the Warrants. (3) The Company utilized six peer companies of comparable size and industry to estimate asset volatility utilizing a period that is commensurate with the expected Warrant life. The Company weighted historical volatility and implied volatility 50/50 for those peer companies where both were available, with asset volatility ranging in the peer companies from 30.1% to 54.2%. The derived asset volatility was selected based upon the midpoint of the average and the third quartile of the peer group, and then relevered the utilizing the Company’s asset and equity information as of the Effective Date.
Schedule of Enterprise value to reorganization value	The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date (in thousands): As of October 21, 2016 Enterprise value $ 600,000 Plus: cash and cash equivalents 76,540 Plus: other working capital liabilities 60,118 Plus: other long-term liabilities 14,600 Reorganization value $ 751,258
Schedule of reorganization balance sheet and fresh start accounting adjustments	Predecessor Reorganization Fresh Start Successor ASSETS CURRENT ASSETS: Cash and cash equivalents $ 274,530 $ (197,990) {a} $ — $ 76,540 Accounts receivable: Oil and gas sales 33,895 — — 33,895 Joint interest billing 4,739 — — 4,739 Other 26 — — 26 Other current assets 8,425 (2,748) {b} — 5,677 Total current assets 321,615 (200,738) — 120,877 PROPERTY AND EQUIPMENT: Oil and gas properties, on the basis of full-cost accounting 3,795,943 — (3,176,723) {h} 619,220 Other property and equipment 12,175 — (5,965) {h} 6,210 Less accumulated depreciation, depletion, amortization and impairment (3,449,241) — 3,449,241 {h} — Net property and equipment 358,877 — 266,553 625,430 OTHER NONCURRENT ASSETS 3,701 1,250 {c} {a} — 4,951 TOTAL $ 684,193 $ (199,488) $ 266,553 $ 751,258 LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT) CURRENT LIABILITIES: Accounts payable $ 10,294 $ — $ — $ 10,294 Accrued liabilities 65,240 (15,416) {a} — 49,824 Debt classified as current 249,384 (249,384) {a}{d} — — Total current liabilities 324,918 (264,800) — 60,118 ASSET RETIREMENT OBLIGATIONS 20,368 — (6,385) {h} 13,983 OTHER LONG-TERM LIABILITIES 617 128,059 {d} — 128,676 LIABILITIES SUBJECT TO COMPROMISE 1,882,187 (1,882,187) {e}{a} — — COMMITMENTS AND CONTINGENCIES STOCKHOLDERS’ EQUITY/(DEFICIT): Preferred stock — — — — Warrants — 37,329 {e} — 37,329 Common stock - predecessor 104 (104) {f} — — Common stock - successor — 247 {f} — 247 Treasury stock (3,134) 3,134 {f} — — Additional paid-in-capital - predecessor 891,292 (891,292) {f} — — Additional paid-in-capital - successor — 510,905 {f} — 510,905 Retained deficit (2,432,159) 2,159,221 {g} 272,938 {i} — Total stockholders’ equity/(deficit) (1,543,897) 1,819,440 272,938 548,481 TOTAL $ 684,193 $ (199,488) $ 266,553 $ 751,258
Schedule of net cash payments recorded from implementation of the Plan	{a} Adjustments reflect the following net cash payments recorded as of the Effective Date from implementation of the Plan (in thousands): Uses: Cash pay down of RBL $ 81,324 Cash payment to holders of Second Lien Notes Claims 60,000 Cash payment to the RBL lenders in consideration of a temporary reduction in the amount available to be drawn under the Exit Facility 40,000 Payment to escrow for professional fees related to the Plan incurred through the Effective Date 15,416 Debt issuance costs associated with the Exit Facility 1,250 Total uses $ 197,990
Schedule of Liabilities subject to compromise, settled	The gain was calculated as follows (in thousands): Predecessor Liabilities subject to compromise $ 1,882,187 Cash paid to holders of Second Lien Notes Claims (60,000) Warrants issued to holders of Third Lien Notes Claims (29,753) Warrants issued to holders of Unsecured Notes Claims (7,575) Write-off of unamortized debt costs associated with RBL (2,748) Common stock issued (511,152) Gain on settlement $ 1,270,959
Schedule of cumulative effect of the reorganization adjustments	{g} This adjustment reflects the cumulative impact of the following reorganization adjustments (in thousands): Predecessor Gain on settlement of liabilities subject to compromise $ 1,270,959 Common stock - predecessor 104 Treasury stock (3,134) Additional paid-in-capital - predecessor 891,292 Net impact to Predecessor accumulated deficit $ 2,159,221
Schedule of the gain on reorganization items, net in the consolidated statements of operations	The following table summarizes the gain on reorganization items, net, in the consolidated statements of operations (in thousands): Predecessor For the Period January 1, 2016 through October 20, 2016 Professional fees incurred $ (38,835) Adjustment to unamortized debt issuance costs associated with 2020 Senior Notes (10,738) Adjustment to unamortized debt issuance costs associated with 2021 Senior Notes (12,671) Adjustment to unamortized gain on troubled debt restructuring associated with Second Lien Notes 39,599 Adjustment to unamortized gain on troubled debt restructuring associated with Third Lien Notes 71,808 Gain on settlement of liabilities subject to compromise 1,270,959 Fresh start adjustments 272,938 Other reorganization items (1) 1,221 Gain on reorganization items, net $ 1,594,281 (1) Other reorganization items primarily included $0.2 million related to Houston office fixed assets, which were abandoned, as well as a $1.6 million decrease in the liability previously recorded for the abandonment of the Houston office lease.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Summary of Significant Accounting Policies
Schedule of accrued liabilities	At December 31, 2018 and 2017, accrued liabilities consisted of the following (in thousands): December 31, 2018 December 31, 2017 Accrued oil and gas capital expenditures $ 1,534 $ 9,081 Accrued revenue and royalty distributions 13,302 18,701 Accrued lease operating and workover expense 2,843 5,150 Accrued interest 209 108 Accrued taxes 1,813 2,758 Compensation and benefit related accruals 2,855 4,520 Other 2,965 2,524 Accrued liabilities $ 25,521 $ 42,842

Impact of ASC 606 Adoption (Tab

Impact of ASC 606 Adoption (Tables)	12 Months Ended
	Dec. 31, 2018
Impact of ASC 606 Adoption
Impact of adoption on the Company's results	The impact of adoption on the Company’s results is as follows for the periods presented (in thousands): December 31, 2018 Under ASC 606 Under ASC 605 Decrease Oil sales $ 123,945 $ 124,006 $ (61) Natural gas liquid sales 44,747 44,818 (71) Natural gas sales 32,138 44,651 (12,513) Gathering and transportation 241 12,646 (12,405) Lease operating and workover expense 54,229 54,469 (240) Net income $ 49,784 $ 49,784 $ — Retained deficit $ (25,363) $ (25,363) $ —

Fair Value Measurements of Fi_2

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Measurements of Financial Instruments
Schedule of derivative instruments measured at fair value	Fair Value Measurements at December 31, 2018 Significant Other Significant Quoted Prices in Active Observable Inputs Unobservable Inputs Markets (Level 1) (Level 2) (Level 3) Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ 3,806 $ — $ 3,806 Commodity derivative gas swaps $ — $ 236 $ — $ 236 Commodity derivative oil collars $ — $ 9,306 $ — $ 9,306 Commodity derivative gas collars $ — $ 577 $ — $ 577 Total assets $ — $ 13,925 $ — $ 13,925 Derivative Liabilities: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps $ — $ (443) $ — $ (443) Commodity derivative oil collars $ — $ (5,199) $ — $ (5,199) Commodity derivative gas collars $ — $ (632) $ — $ (632) Total liabilities $ — $ (6,274) $ — $ (6,274) Fair Value Measurements at December 31, 2017 Significant Other Significant Quoted Prices in Active Observable Inputs Unobservable Inputs Markets (Level 1) (Level 2) (Level 3) Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps $ — $ 821 $ — $ 821 Commodity derivative oil collars $ — $ 952 $ — $ 952 Commodity derivative gas collars $ — $ 2,611 $ — $ 2,611 Total assets $ — $ 4,384 $ — $ 4,384 Derivative Liabilities: Commodity derivative oil swaps $ — $ (3,679) $ — $ (3,679) Commodity derivative gas swaps $ — $ — $ — $ — Commodity derivative oil collars $ — $ (2,605) $ — $ (2,605) Commodity derivative gas collars $ — $ (1,333) $ — $ (1,333) Total liabilities $ — $ (7,617) $ — $ (7,617)

Risk Management and Derivativ_2

Risk Management and Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Risk Management and Derivative Instruments
Schedule of commodity derivative contracts	NYMEX WTI Fixed Swaps Three-Way Collars Weighted Weighted Weighted Hedge Avg Hedge Avg Weighted Avg Position Strike Position Ceiling Avg Floor Sub-Floor (Bbls) Price (Bbls) Price Price Price Quarter Ended: December 31, 2018 313,720 $ 58.59 46,000 $ 56.70 $ 50.00 $ 40.00 March 31, 2019(1) 74,800 $ 66.48 180,000 $ 63.14 $ 53.75 $ 43.75 June 30, 2019(1) 57,650 $ 64.69 182,000 $ 63.14 $ 53.75 $ 43.75 September 30, 2019(1) 46,000 $ 62.96 184,000 $ 63.14 $ 53.75 $ 43.75 December 31, 2019(1) 46,000 $ 61.43 184,000 $ 63.14 $ 53.75 $ 43.75 March 31, 2020(1) — $ — 91,000 $ 65.75 $ 50.00 $ 40.00 June 30, 2020(1) — $ — 91,000 $ 65.75 $ 50.00 $ 40.00 September 30, 2020(1) — $ — 92,000 $ 65.75 $ 50.00 $ 40.00 December 31, 2020(1) — $ — 92,000 $ 65.75 $ 50.00 $ 40.00 NYMEX HENRY HUB Fixed Swaps Three-Way Collars Weighted Weighted Weighted Hedge Avg Hedge Avg Weighted Avg Position Strike Position Ceiling Avg Floor Sub-Floor (MMBtu) Price (MMBtu) Price Price Price Quarter Ended: December 31, 2018 2,055,000 $ 2.95 1,380,000 $ 3.40 $ 3.00 $ 2.50 March 31, 2019(1) 1,980,000 $ 3.01 1,350,000 $ 3.40 $ 3.00 $ 2.50 June 30, 2019(1) 1,365,000 $ 2.75 — $ — $ — $ — September 30, 2019(1) 1,380,000 $ 2.75 — $ — $ — $ — December 31, 2019(1) 465,000 $ 2.75 610,000 $ 3.45 $ 2.65 $ 2.15 March 31, 2020(1) — — 910,000 $ 3.45 $ 2.65 $ 2.15 (1) Positions shown represent open commodity derivative contract positions as of December 31, 2018.
Schedule of fair value of commodity derivative instruments by balance sheet classification	The following table summarizes the net fair values of commodity derivative instruments by the appropriate balance sheet classification in the Company's consolidated balance sheets for the periods presented (in thousands): Type Balance Sheet Location (1) December 31, 2018 December 31, 2017 Oil swaps Derivative financial instruments — current assets $ 3,806 $ — Gas swaps Derivative financial instruments — current assets (207) 821 Oil collars Derivative financial instruments — current assets 3,316 (760) Gas collars Derivative financial instruments — current assets 25 701 Total derivative financial instruments — current assets $ 6,940 $ 762 Oil collars Derivative financial instruments — noncurrent assets $ 791 — Total derivative financial instruments — noncurrent assets $ 791 $ — Oil swaps Derivative financial instruments — current liabilities $ — $ (3,679) Oil collars Derivative financial instruments — current liabilities — (370) Gas collars Derivative financial instruments — current liabilities — 616 Total derivative financial instruments — current liabilities $ — $ (3,433) Oil collars Derivative financial instruments — noncurrent liabilities $ — $ (523) Gas collars Derivative financial instruments — noncurrent liabilities (80) (39) Total derivative financial instruments — noncurrent liabilities $ (80) $ (562) Total derivative fair value at period end $ 7,651 $ (3,233) (1) The fair values of commodity derivative instruments reported in the Company’s consolidated balance sheets are subject to netting arrangements and qualify for net presentation.
Summary of location and fair values amounts of all commodity derivative instruments as well as the gross recognized derivative assets, liabilities and amounts offset in the condensed consolidated balance sheet	The following table summarizes the location and fair value amounts of all commodity derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets for the periods presented (in thousands): December 31, 2018 Net Recognized Not Designated as Gross Recognized Gross Amounts Fair Value ASC 815 Hedges Balance Sheet Location Classification Assets/ Liabilities Offset Assets/ Liabilities Derivative Assets: Commodity contracts Derivative financial instruments — current $ 11,066 $ (4,126) $ 6,940 Commodity contracts Derivative financial instruments — noncurrent 2,859 (2,068) 791 $ 13,925 $ (6,194) $ 7,731 Derivative Liabilities: Commodity contracts Derivative financial instruments — current $ (4,126) $ 4,126 $ — Commodity contracts Derivative financial instruments — noncurrent (2,148) 2,068 (80) $ (6,274) $ 6,194 $ (80) December 31, 2017 Not Designated as Net Recognized Gross Recognized Gross Amounts Fair Value ASC 815 Hedges Balance Sheet Location Classification Assets/Liabilities Offset Assets/Liabilities Derivative Assets: Commodity contracts Derivative financial instruments — current $ 3,479 $ (2,717) $ 762 Commodity contracts Derivative financial instruments — noncurrent 905 (905) — $ 4,384 $ (3,622) $ 762 Derivative Liabilities: Commodity contracts Derivative financial instruments — current $ (6,150) $ 2,717 $ (3,433) Commodity contracts Derivative financial instruments — noncurrent (1,467) 905 (562) $ (7,617) $ 3,622 $ (3,995)
Schedule of net cash received for commodity derivative contracts and unrealized net gains or unrealized net losses related to the change in fair value of derivative instruments in gains (losses) on commodity derivative contracts - net for the periods	The following table presents net cash received for commodity derivative contracts and unrealized net (losses) gains recorded by the Company related to the change in fair value of the derivative instruments in “Gains on commodity derivative contracts—net” for the periods presented (in thousands): Successor Predecessor For the Period For the Period October 21,2016 January 1, 2016 For the Year Ended December 31, through through 2018 2017 December 31,2016 October 20,2016 Net cash (paid) received for commodity derivative contracts $ (7,328) $ 6,891 $ — $ — Unrealized net gains (losses) 10,883 (3,232) — — Gains on commodity derivative contracts—net $ 3,555 $ 3,659 $ — $ —

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
Property and Equipment
Schedule of property and equipment	The Company’s property and equipment as of the dates presented was as follows (in thousands): December 31, 2018 December 31, 2017 Oil and gas properties, on the basis of full-cost accounting: Proved properties $ 809,272 $ 765,308 Unproved properties not being amortized 4,050 7,065 Other property and equipment 6,345 6,508 Less accumulated depreciation, depletion, amortization and impairment (266,198) (204,419) Net property and equipment $ 553,469 $ 574,462

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligations
Schedule of change in the AROs	The following table details the change in the AROs for the periods presented (in thousands): For the Year Ended December 31, 2018 2017 Asset retirement obligations at beginning of period $ 15,506 $ 14,200 Liabilities incurred 435 571 Revisions — 1,832 Liabilities settled (1) (744) Liabilities eliminated through asset sale (1)(2) (8,699) (1,453) Current period accretion expense 846 1,100 Asset retirement obligations at end of year $ 8,087 $ 15,506 (1) Liabilities eliminated through asset sales for the year ended December 31, 2017 primarily relate to the sale of Lincoln County. See discussion of the sale in “—Note 8. Property and Equipment”. (2) Liabilities eliminated through asset sales for the year ended December 31, 2018 primarily relate to the sale of Anadarko Basin assets. See discussion of the sale in “—Note 8. Property and Equipment”.

Equity and Share-Based Compen_2

Equity and Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Summary of changes in the number of shares of common stock and treasury stock	Common Treasury Stock Stock(1) Share count as of December 31, 2015 (Predecessor) 10,962,105 (96,291) Grants of restricted stock — — Forfeitures of restricted stock (47,325) — Acquisition of treasury stock — (52,358) Share count as of October 21, 2016 (Predecessor) 10,914,780 (148,649) Cancellation of common stock (10,914,780) — Cancellation of treasury stock — 148,649 Share count as of October 21, 2016 (Predecessor) — — Issuance of successor common stock 24,687,500 — Share count as of October 21, 2016 (Successor) 24,687,500 — Issuance of successor common stock 307,367 — Acquisition of treasury stock — — Share count as of December 31, 2016 (Successor) 24,994,867 — Issuance of successor common stock 278,102 — Acquisition of treasury stock — (99,623) Share count as of December 31, 2017 (Successor) 25,272,969 (99,623) Issuance of successor common stock 247,201 — Acquisition of treasury stock — (74,566) Share count as of December 31, 2018 (Successor) 25,520,170 (174,189) (1) Treasury stock represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory withholding requirements.
Summary of non-vested restricted stock unit award activity	Weighted Average Grant Date Restricted Stock Fair Value Non-vested shares outstanding at December 31, 2015 (Predecessor) 318,031 $ 21.46 Granted — $ — Vested (162,393) $ 23.09 Forfeited (47,325) $ 19.02 Non-vested shares outstanding at October 20, 2016 (Predecessor) 108,313 $ 20.08 Cancellation of non-vested shares (108,313) $ 20.08 Non-vested shares outstanding at October 20, 2016 (Predecessor) — $ — Granted at Effective Date 686,324 $ 19.66 Non-vested shares outstanding at October 21, 2016 (Successor) 686,324 $ 19.66 Granted 2,035 $ 20.97 Forfeited (2,697) $ 19.66 Non-vested shares outstanding at December 31, 2016 (Successor) 685,662 $ 19.66 Granted 85,389 $ 16.50 Vested (1) (335,958) $ 19.65 Forfeited (110,109) $ 19.66 Non-vested shares outstanding at December 31, 2017 (Successor) 324,984 $ 18.84 Granted 271,968 $ 14.24 Vested (2) (323,927) $ 17.57 Forfeited (21,503) $ 15.52 Non-vested shares outstanding at December 31, 2018 (Successor) 251,522 $ 15.79 (1) Vested RSUs include 109,820 awards in which vesting was accelerated to October 21, 2017, as a result of the former CEO’s amended employment agreement, as well as, 57,856 director awards that vested at December 31, 2017, but receipt/issuance of the vested shares was deferred until 2020. (2) Vested RSUs include 102,092 shares in which vesting was accelerated as a result of a reduction in workforce, as well as, 26,223 director awards in which vesting was accelerated as certain directors departed during the twelve months ended December 31,2018.
Schedule of assumptions used to estimate fair value of stock option awards	Awards Issued in Awards Issued in 2017 2016 Weighted-average assumptions used: Risk-free interest rate (1) 2.11 % 1.38 % Dividend yield — — Expected option life (2) 5.96 Expected volatility (3) 65.0 % 60.0 % Calculated fair value per stock option $ 11.43 $ 10.88 (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the expected life of the option. (2) As the Company does not have significant history associated with stock options, expected option life assumptions were developed using the simplified method in accordance with US GAAP. A change in the expected option life of +/- 2 years would impact expense by $0.1 million and $(0.2) million for the Successor Period and $0.9 million and $(1.1) million over the vesting period of three years. Stock options granted during the year ended December 31, 2017 were not significant. (3) As the Company does not have significant stock option history, it utilized six peer companies of comparable size and industry to estimate volatility utilizing a period that is commensurate with the expected option life. The Company weighted historical volatility and implied volatility 50/50 for those peer companies where both were available, with volatility ranging in the peer companies from 36.9% to 68.2% in 2017 and 38.5% to 65.9% in 2016.
Summary of non-vested stock option activity	Weighted Average Weighted Remaining Range of Average Contractual Options Exercise Prices Exercise Price Term (Years) Stock options outstanding at December 31, 2016 627,806 $ 19.66 8.8 Granted 4,000 $ 19.08 $ 19.08 9.2 Vested (253,678) $ 19.08 - 20.97 $ 19.66 — Forfeited (132,283) $ 19.66 $ 19.66 — Stock options outstanding at December 31, 2017 245,845 $ 19.66 8.9 Granted — $ — $ — — Vested (1) (170,173) $ 19.08 - 20.97 $ 19.66 7.8 Forfeited (5,570) $ 19.66 $ 19.66 — Stock options outstanding at December 31, 2018 70,102 $ 19.65 7.8 Vested and exercisable at end of period (1)(2) 136,161 $ 19.08 - 20.97 $ 19.67 7.8 (1) Vested stock options include 102,092 options in which vesting was accelerated as a result of a reduction in workforce that occurred during the twelve months ended December 31, 2018. Per the 2016 LTIP Plan, these vested options had to be exercised within 180 days of employees termination or they would expire and be returned to the Plan for future reissuance. All options expired on July 31, 2018, thereby reducing the total options vested and exercisable at December 31, 2018. (2) Vested and exercisable options at December 31, 2018, had no aggregate intrinsic value.
Schedule of assumptions used to estimate fair value of restricted stock units with market condition	December 31, 2018 December 31, 2017 Risk-free interest rate (1) 2.43 % 2.06 % Dividend yield — — Expected volatility (2) 39.0 % 54.8 % Market Price Hurdle $ 30.00 $ 30.00 Calculated fair value per restricted stock unit $ 0.41 $ 11.54 (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the expected life of the restricted stock unit. (2) As the Company did not have a significant stock trading history during the year ended December 31, 2017, it utilized six peer companies of comparable size and industry to estimate volatility utilizing a period that is commensurate with the expected option life. The Company weighted historical volatility and implied volatility 50/50 for those peer companies where both were available, with volatility ranging in the peer companies from 55.1% to 89.0%.
Schedule of outstanding restricted stock unit awards containing market condition	Weighted Average Shares Fair Value Outstanding at December 31, 2017 76,296 $ 17.71 Granted — $ — Vested — $ — Forfeited(1) (25,432) $ — Outstanding at December 31, 2018 50,864 $ 17.71 (1) On November 7, 2018, Michael Reddin and Bruce Vincent resigned from the Board and forfeited all outstanding equity awards on November 12, 2018
Schedule of executive officer restricted stock units containing a market condition with respect to RSUs granted	Vesting as % of Vesting as % of 50% of RSUs 50% of RSUs Actual TSR for the Performance Period Granted Relative TSR for the Performance Period Granted Maximum 25% or greater compounded annual growth (“CAGR”) 120 % Top 5% or better Relative TSR to Peer Group 120 % Target 20% or greater CAGR 100 % Top 33.3% or better Relative TSR to Peer Group 100 % Threshold 15% or greater CAGR 50 % Top 50% or better Relative TSR to Peer Group 50 % Below Threshold Less than 15% CAGR % Less than 50% of Relative TSR to Peer Group %
Schedule of executive officer restricted stock units with market condition valuation assumptions	Awards Issued November 1, 2017 Risk-free interest rate (1) 1.74 % Dividend yield — Expected volatility 41.0% - 130.0 % Calculated fair value per unit $ (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the life of the CEO restricted stock unit award with a market condition.
Schedule of executive officer restricted stock units with market condition award activity	Weighted Average Shares Fair Value Outstanding at December 31, 2017 135,778 $ 10.92 Granted — $ — Vested — $ — Forfeited — $ — Outstanding at December 31, 2018 135,778 $ 10.92
Summary of share-based compensation expense	The following summarizes stock-based compensation expense for the periods presented (in thousands): Successor Predecessor For the For the Period Period October 21, January 1, 2016 2016 through through For the Year Ended December 31, December October 20, 2018 2017 31, 2016 2016 Restricted stock units (Predecessor) $ — $ — $ — $ 3,040 Restricted stock units (Successor) 5,207 7,083 2,114 — Stock options (Successor) 1,078 3,289 1,046 — Non-employee director restricted stock units with a market condition (Successor) (860) 736 142 — CEO restricted stock units with a market condition (Successor) 493 83 — — Performance Stock Units Issued to Certain Members of Executive Management Containing a Market Condition (Successor) 379 — — — Unrestricted stock awards (Successor) — — 244 — Total stock-based compensation 6,297 11,191 3,546 3,040 Less: amounts capitalized to oil and natural gas properties (890) (1,995) (637) (476) Net stock-based compensation $ 5,407 $ 9,196 $ 2,909 $ 2,564
Executive Management
Schedule of executive officer restricted stock units containing a market condition with respect to RSUs granted	Relative TSR for the Performance Period Vesting as % of RSUs Granted Maximum Top 35% or better Relative TSR to Peer Group 150 % Target Top 50% or better Relative TSR to Peer Group 100 % Threshold Top 60% or better Relative TSR to Peer Group 50 % Below Threshold Less than 60% of Relative TSR to Peer Group 0 %
Schedule of executive officer restricted stock units with market condition valuation assumptions	Awards Issued March 1, 2018 Risk-free interest rate (1) 2.34 % Dividend yield — Expected volatility 40.0% - 127.2 % Calculated fair value per unit $ 13.34 (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the life of the executives restricted stock unit award with a market condition.
Schedule of executive officer restricted stock units with market condition award activity	Weighted Average Shares Fair Value Outstanding at December 31, 2017 — $ — Granted 96,305 $ 13.34 Vested — $ — Forfeited — $ — Outstanding at December 31, 2018 96,305 $ 13.34

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Taxes
Schedule of income tax provision (benefit)	Successor Predecessor For the Period For the Period October 21, 2016 January 1, 2016 For the Year Ended December 31, through through 2018 2017 December 31, 2016 October 20,2016 (in thousands) (in thousands) Current United States $ — $ — $ — $ — State — — — — Total current — — — — Deferred United States — — — — State — — — — Total deferred — — — — Total income tax provision (benefit) $ — $ — $ — $ —
Schedule of difference between the Company's estimated income tax from amount derived by applying statutory federal rate to pretax income	Successor Predecessor For the Period For the Period October 21, 2016 January 1, 2016 For the Year Ended December 31, through through October 20, 2018 2017 December 31, 2016 2016 (in thousands) (in thousands) Income (loss) before taxes $ 49,784 $ (85,077) $ 9,930 $ 1,323,079 Statutory rate 21 % 35 % 35 % 35 % Income tax provision (benefit) computed at statutory rate 10,455 (29,777) 3,475 463,078 Reconciling items: State income taxes, net of federal benefit 2,157 (2,864) 296 39,424 Change in valuation allowance (10,515) (40,700) (3,876) (528,706) Adjustment to deferred tax assets and liabilities for enacted change in federal tax rate — 73,182 — — Parking expenses 35 — — — Change in state rate 28 (606) (1) (153) Bankruptcy items — — — 12,262 Deferred tax true-ups (1,520) (140) 74 9,891 Other, net (640) 905 32 4,204 Total income tax provision (benefit) $ — $ — $ — $ —
Schedule of components of the entity's deferred taxes	The components of our deferred taxes are detailed in the table below (in thousands): As of As of December 31, December 31, 2018 2017 Deferred tax assets Federal tax loss carryforwards $ 60,874 $ 36,429 Derivative instruments and other — 813 State tax loss carryforwards 13,087 7,195 Employee benefit plans 3,086 3,053 Oil and gas properties and equipment 33,186 72,568 Disallowed interest expense 1,231 — Other 33 33 Less valuation allowance (109,574) (120,091) Total deferred tax assets $ 1,923 $ — Deferred tax liabilities Derivative instruments and other $ (1,923) $ — Oil and gas properties and equipment — — Total deferred tax liabilities $ (1,923) $ — Reflected in the accompanying balance sheet as: Net deferred tax asset (liability) $ — $ —

Income (Loss) Per Share (Tables

Income (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2018
Schedule of reconciliation of net income (loss) attributable to common shareholders and weighted average common shares outstanding for basic and diluted income (loss) per share	For the Period October 21, 2016 Year Ended December 31, through 2018 2017 December 31, 2016 (in thousands, except per share amounts) Net Income (Loss): Net income (loss) $ 49,784 $ (85,077) $ 9,930 Participating securities-non-vested restricted stock (1,394) — (280) Basic and diluted income (loss) $ 48,390 $ (85,077) $ 9,650 Common Shares: Common shares outstanding - basic (1) 25,337 25,119 25,009 Dilutive effect of potential common shares — — — Common shares outstanding - diluted 25,337 25,119 25,009 Net Income (Loss) Per Share: Basic $ 1.91 $ (3.39) $ 0.39 Diluted $ 1.91 $ (3.39) $ 0.39 Antidilutive stock options (2) 206 466 627 Antidilutive warrants (3) 6,626 6,626 6,626 (1) Weighted-average common shares outstanding for basic and diluted income per share purposes includes 9,407 and 17,533, shares of common stock that, while not issued and outstanding at December 31, 2018 and 2017, respectively, are required by the Plan to be issued. Weighted-average common shares outstanding for basic and diluted income (loss) per share purposes also includes 40,054 director shares that vested at December 31, 2017, and 39,335 director shares that vested at December 31, 2018, but final issuance of the vested shares was deferred until 2020 and 2021, respectively. (2) Amount represents options to purchase common stock that are excluded from the diluted net income (loss) per share calculations because the options are antidilutive. (3) Amount represents warrants to purchase common stock that are excluded from the diluted net income (loss) per share calculations because the warrants are antidilutive.
Predecessor
Schedule of reconciliation of net income (loss) to preferred shareholders, common shareholders, and participating securities for purposes of computing net income (loss) per share	For the Period January 1, 2016 through October 20, 2016 (in thousands, except per share amounts) Net income (loss) $ 1,323,079 Preferred dividend (1) — Net income (loss) attributable to shareholders $ 1,323,079 Participating securities-Series A preferred stock(2) — Participating securities-Non-vested restricted stock(2) (16,522) Net income (loss) attributable to common shareholders $ 1,306,557 Weighted average shares outstanding 10,645 Basic and diluted net income (loss) per share $ 122.74 (1) Calculation of the preferred stock dividend is discussed in "- Note 12. Preferred Stock". (2) As these shares are participating securities that participate in earnings, but are not required to participate in losses, this calculation demonstrates that there is not an allocation of the loss to the non‑vested restricted stockholders.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies
Schedule of contractual obligations for drilling contracts, long-term operating leases, and other contracts	At December 31, 2018, contractual obligations for drilling contracts, long‑term operating leases and other contracts are as follows (in thousands): 2023 and Total 2019 2020 2021 2022 beyond Drilling contracts $ — $ — $ — $ — $ — $ — Non-cancellable office lease commitments 5,335 665 678 690 702 2,600 Net minimum commitments $ 5,335 $ 665 $ 678 $ 690 $ 702 $ 2,600

Supplemental Information to C_2

Supplemental Information to Consolidated Statement of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2018
Supplemental Information to Consolidated Statement of Cash Flows
Schedule of summarized interest and income taxes and supplemental non-cash investing and financing activities	The following table summarizes interest and income taxes paid for the periods presented and supplemental non-cash investing and financing activities (in thousands): Successor Predecessor Period Period October 21, January 1, 2016 through 2016 through Year Ended December 31, December 31, October 20, 2018 2017 2016 2016 SUPPLEMENTAL INFORMATION: Non-cash investment in property and equipment $ 6,092 $ 17,164 $ 8,135 $ 12,995 Non-cash exchange of common equity of the reorganized Company for second lien notes $ — $ — $ — $ 591,042 Non-cash exchange of common equity and warrants of the reorganized Company for third lien notes $ — $ — $ — $ 556,136 Non-cash exchange of common equity and warrants of the reorganized Company for 2020 senior notes $ — $ — $ — $ 312,039 Non-cash exchange of common equity and warrants of the reorganized Company for 2021 senior notes $ — $ — $ — $ 361,050 Cash paid for interest, net of capitalized interest for the year ended December 31, 2018, December 31, 2017, and the Successor Period of $0.5 million, $2.4 million and $0.7 million, respectively (no capitalized interest for the Predecessor Period) $ 4,128 $ 5,353 $ 426 $ 6,709 Cash paid for reorganization items $ — $ — $ — $ 36,325

Supplemental Oil and Gas Disc_2

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Supplemental Oil and Gas Disclosures (Unaudited)
Schedule of costs incurred in oil and natural gas property acquisition, exploration and development activities	The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the year ended December 31, 2018, 2017, the Successor Period and the Predecessor Period (in thousands): Successor Predecessor For the Period For the Period October 21, 2016 January 1, 2016 For the Year Ended December 31, through December 31, through October 20, 2018 2017 2016 2016 Acquisition costs: Proved properties $ — $ — $ — $ — Unproved properties 6,711 11,964 1,430 6,869 Exploration costs — — — — Development costs 93,965 128,424 17,708 121,668 Total costs incurred $ 100,676 $ 140,388 $ 19,138 $ 128,537
Schedule of net capitalized costs	The following table sets forth the capitalized costs related to the Company's oil and natural gas producing activities as of December 31, 2018 and 2017 (in thousands): December 31, 2018 December 31, 2017 Proved properties $ 809,272 $ 765,308 Unproved properties not being amortized 4,050 7,065 Gross capitalized costs 813,322 772,373 Less: Accumulated depreciation, depletion, amortization and impairment (261,705) (201,722) Net capitalized costs $ 551,617 $ 570,651
Schedule of estimated quantities of proved oil and natural gas reserves	Oil NGL Gas Total (MBbl) (MBbl) (MMcf) (MBoe) 2016 (Predecessor) Proved Reserves Beginning Balance 24,713 16,245 195,492 73,540 Revision of previous estimates (3,089) (459) (946) (3,706) Extensions, discoveries and other additions 1,566 840 11,052 4,249 Sales of reserves in place — — — — Purchases of reserves in place — — — — Production (2,964) (1,932) (23,215) (8,765) Net proved reserves at October 20, 2016 20,226 14,694 182,383 65,318 Proved developed reserves, October 20, 2016 20,226 14,694 182,383 65,318 Proved undeveloped reserves, October 20, 2016 — — — — 2016 (Successor) Proved Reserves Beginning Balance 20,226 14,694 182,383 65,318 Revision of previous estimates 19,137 11,421 147,688 55,172 Extensions, discoveries and other additions 22,571 11,186 147,236 58,296 Sales of reserves in place — — — — Purchases of reserves in place — — — — Production (544) (429) (4,948) (1,798) Net proved reserves at December 31, 2016 61,390 36,872 472,359 176,988 Proved developed reserves, December 31, 2016 19,698 16,349 201,454 69,622 Proved undeveloped reserves, December 31, 2016 41,692 20,523 270,905 107,366 2017 Proved Reserves Beginning Balance 61,390 36,872 472,359 176,988 Revision of previous estimates (33,608) (13,010) (178,388) (76,350) Extensions, discoveries and other additions 5,819 4,003 51,849 18,464 Sales of reserves in place (99) (723) (7,495) (2,071) Purchases of reserves in place — — — — Production (2,368) (1,949) (22,606) (8,084) Net proved reserves at December 31, 2017 31,134 25,193 315,719 108,947 Proved developed reserves, December 31, 2017 17,268 15,464 190,550 64,490 Proved undeveloped reserves, December 31, 2017 13,866 9,729 125,169 44,457 2018 Proved Reserves Beginning Balance 31,134 25,193 315,719 108,947 Revision of previous estimates (13,765) (6,347) (114,092) (39,127) Extensions, discoveries and other additions 5,454 4,462 48,382 17,979 Sales of reserves in place (2,838) (2,414) (20,778) (8,714) Purchases of reserves in place — — — — Production (1,920) (1,623) (18,718) (6,663) Net proved reserves at December 31, 2018 18,065 19,271 210,513 72,422 Proved developed reserves, December 31, 2018 10,995 13,425 147,248 48,962 Proved undeveloped reserves, December 31, 2018 7,070 5,846 63,265 23,460
Schedule of benchmark prices used to determine estimated proved reserves	At December 31, 2018 2017 2016 Oil and Natural Gas Prices: Oil (per barrel) $ 65.56 $ 51.34 $ 42.75 Natural gas (per million British thermal units) $ 3.10 $ 2.98 $ 2.48
Schedule of standardized measure of discounted future net cash flows	The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s oil and natural gas reserves at December 31, 2018, 2017, and 2016 (in thousands): At December 31, 2018 2017 2016 Future cash inflows $ 2,131,791 $ 3,023,929 $ 4,186,389 Future production costs (695,677) (1,536,332) (2,078,640) Future development costs (159,400) (370,972) (692,533) Future income tax expense (52,778) (16,289) (106,563) Future net cash flows 1,223,936 1,100,336 1,308,653 10% annual discount for estimated timing of cash flows (657,660) (551,093) (778,703) Standardized measure of discounted future net cash flows $ 566,276 $ 549,243 $ 529,950
Schedule of changes in standardized measure of discounted future net cash flows	The following table sets forth the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the year ended December 31, 2018, 2017, the Successor Period and the Predecessor Period (in thousands): Successor Predecessor For the Period October For the Period January Year Ended December 31, 21, 2016 through 1, 2016 through 2018 2017 December 31, 2016 October 20, 2016 Standardized measure, beginning of period $ 549,243 $ 529,950 $ 349,905 $ 512,819 Net changes in prices and production costs 182,133 173,991 78,103 (113,313) Net changes in future development costs (639) (29,711) 2,022 175 Sales of oil and natural gas, net (134,681) (148,746) (27,292) (116,043) Extensions 134,496 92,776 102,087 29,871 Discoveries — — — — Purchases of reserves in place — — — — Divestiture of reserves (52,952) (8,079) — — Revisions of previous quantity estimates (162,513) (152,517) 102,623 (22,194) Previously estimated development costs incurred 28,443 7,909 — 29,975 Accretion of discount 55,813 57,816 5,832 42,735 Net change in income taxes (4,483) 39,316 (48,206) — Changes in timing, other (28,584) (13,462) (35,124) (14,120) Standardized measure, end of period $ 566,276 $ 549,243 $ 529,950 $ 349,905

Selected Quarterly Financial _2

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2018
Selected Quarterly Financial Data
Schedule of selected quarterly financial data	First Second Third Fourth Quarter Quarter Quarter Quarter (in thousands, except per share amounts) 2018 Total revenues $ 48,905 $ 42,324 $ 47,765 $ 69,643 Operating income (loss) 5,812 (245) 12,170 36,514 Net income (loss) 4,004 (1,542) 11,516 35,806 Net income (loss) available to common shareholders 3,905 (1,542) 11,165 34,862 Net income (loss) per share: Basic and Diluted $ 0.15 $ (0.06) $ 0.44 $ 1.38 Shares used in computation: Basic and Diluted 25,299 25,332 25,332 25,385 2017 Total revenues $ 65,015 $ 60,679 $ 49,715 $ 53,344 Operating income (loss) 19,462 14,970 5,312 (119,238) Net income (loss) 18,485 13,742 3,663 (120,967) Net income (loss) available to common shareholders 17,939 13,382 3,581 (120,967) Net income (loss) per share: Basic and Diluted $ 0.72 $ 0.53 $ 0.14 $ (4.78) Shares used in computation: Basic and Diluted 25,012 25,093 25,116 25,253

Organization and Business (Deta

Organization and Business (Details) - USD ($) $ in Thousands	May 31, 2018	Jul. 26, 2017	Dec. 31, 2018	Dec. 31, 2017
Acquisition information
Proceeds from the sale, net			$ 54,091	$ 2,885
Divestiture of Oil and Gas Properties
Acquisition information
Proceeds from the sale, gross	$ 58,000	$ 7,000
Proceeds from the sale, net	54,100	$ 2,900
Gain or loss recognized	0
RBL
Acquisition information
Repayment of debt using proceeds from sale	$ 50,000

Emergence from Voluntary Reor_2

Emergence from Voluntary Reorganization under Chapter 11 Proceedings (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 09, 2016	Oct. 21, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Oct. 24, 2018	Oct. 20, 2016	Apr. 01, 2016	May 21, 2015
2016 Reorganization
Cash paydown (payments)		$ 121,300
Common Stock, shares issued (in shares)				25,520,170	25,272,969
Common stock, shares authorized				250,000,000	250,000,000
Preferred stock, shares authorized				50,000,000	50,000,000
2016 LTIP
2016 Reorganization
Shares available for future issuance (in shares)				2,100,933
Percent organized equity set aside for Incentive Plan (in percent)		10.00%
Second lien notes
2016 Reorganization
Equity allocated to holders of debtors (as a percent)		96.25%
Cash paydown (payments)		$ 60,000
Interest rate (as a percent)									10.00%
Third lien notes
2016 Reorganization
Interest rate (as a percent)									12.00%
Exit Facility
2016 Reorganization
Cash paydown (payments)		40,000
Maximum borrowing capacity		170,000		$ 170,000	$ 170,000	$ 170,000
RBL
2016 Reorganization
Cash paydown (payments)		$ 81,324
Maximum borrowing capacity							$ 750,000	$ 170,000
Warrants | Unsecured Note
2016 Reorganization
Equity allocated to holders of debtors (as a percent)		1.25%
Warrants to acquire common stock shares (in shares)		2,213,789
Exercise price (in dollars per share)		$ 46
Warrants expiration term		42 months
Warrants | Third lien notes
2016 Reorganization
Equity allocated to holders of debtors (as a percent)		2.50%
Warrants to acquire common stock shares (in shares)		4,411,765
Exercise price (in dollars per share)		$ 24
Warrants expiration term		42 months
Common Stock
2016 Reorganization
New stock issued (in shares)	294,967	24,687,500	307,367	247,201	278,102
Shares available for future issuance (in shares)		17,533

Fresh Start Accounting - Reorga

Fresh Start Accounting - Reorganization value (Details) $ in Thousands	Oct. 21, 2016USD ($)
Fresh start accounting adjustments
Enterprise value	$ 600,000
Reorganization value	751,258
Minimum
Fresh start accounting adjustments
Enterprise value	500,000
Maximum
Fresh start accounting adjustments
Enterprise value	700,000
Weighted average
Fresh start accounting adjustments
Enterprise value	$ 600,000

Fresh Start Accounting - Valuat

Fresh Start Accounting - Valuation of Oil and Gas Properties (Details) $ in Millions	Oct. 21, 2016USD ($)itemcompany	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Valuation of Oil and Gas Properties
Federal statutory rate (in percent)		35.00%	21.00%	35.00%
Fair value of proved reserves	$ 539
Fair value of unproved property	$ 66.2
Operating and Other Costs
Valuation of Oil and Gas Properties
Escalated inflation (as a percent)	2
General and administrative expense
Valuation of Oil and Gas Properties
Escalated inflation (as a percent)	2
Number of years used to forecast historical expenses	5 years
Capital Expenditures
Valuation of Oil and Gas Properties
Escalated inflation (as a percent)	2
Pricing
Valuation of Oil and Gas Properties
Escalated inflation (as a percent)	2
Weighted-Average Cost of Capital
Valuation of Oil and Gas Properties
Number of companies (in companies) | company	8
Risk free rate utilized (as a percent)	2.20%
Number of inputs to calculate the risk premium | item	3
Market risk premium (as a percent)	6
Size premium (as a percent)	3.6
Cost of debt pre-tax (as a percent)	7
Cost of debt after-tax (as a percent)	4.6
Weighted average cost of capital rate (as a percent)	11

Fresh Start Accounting - Fair v

Fresh Start Accounting - Fair value stock (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 21, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Fresh start accounting adjustments
Enterprise value	$ 600,000
Plus: Cash and cash equivalents	76,540
Less: Fair value of debt	(128,059)
Less Fair value of warrants	(37,329)
Fair value of stock on the Effective Date	$ 511,152
Total shares issuable under the Plan	25,000,000
Total shares	25,686,000
Per share value (1) (in dollars per share)	$ 19.90
Fair value (in dollars per share)	$ 19.66
Restricted Stock Units
Fresh start accounting adjustments
Restricted shares granted under 2016 LTIP at October 21, 2016	686,324	2,035	271,968	85,389
Warrants | Unsecured Note
Fresh start accounting adjustments
Warrants issued	2,213,789
Shares of common stock acquired by warrants (in shares)	2,213,789
Exercise price (in dollars per share)	$ 46
Warrants | Third lien notes
Fresh start accounting adjustments
Warrants issued	4,411,765
Shares of common stock acquired by warrants (in shares)	4,411,765
Exercise price (in dollars per share)	$ 24

Fresh Start Accounting - Fair_2

Fresh Start Accounting - Fair value warrants (Details) - Warrants	Oct. 21, 2016company$ / shares
Estimated
Fair value warrants
Number of companies (in companies) | company	6
Unsecured Note
Assumptions used to estimate fair value of warrants
Risk-free interest rate (as a percent)	1.04%
Expected life (in years)	3 years 6 months
Expected volatility (as a percent)	55.00%
Strike Price (in dollars per share)	$ 46
Calculated fair value( in dollars per share)	$ 3.42
Third lien notes
Assumptions used to estimate fair value of warrants
Risk-free interest rate (as a percent)	1.04%
Expected life (in years)	3 years 6 months
Expected volatility (as a percent)	55.00%
Strike Price (in dollars per share)	$ 24
Calculated fair value( in dollars per share)	$ 6.74
Minimum | Estimated
Assumptions used to estimate fair value of warrants
Expected volatility (as a percent)	30.10%
Maximum | Estimated
Assumptions used to estimate fair value of warrants
Expected volatility (as a percent)	54.20%

Fresh Start Accounting - Reor_2

Fresh Start Accounting - Reorganzation value (Details) $ in Thousands	Oct. 21, 2016USD ($)
Fresh Start Accounting
Enterprise value	$ 600,000
Plus: Cash and cash equivalents	76,540
Plus: other working capital liabilities	60,118
Plus: other long-term liabilities	14,600
Reorganization value	$ 751,258

Fresh Start Accounting - Consol

Fresh Start Accounting - Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Oct. 21, 2016	Oct. 20, 2016
Reorganization Adjustments
Cash and cash equivalents (a)	$ (197,990)
Other current assets (b)	(2,748)
Total current assets	(200,738)
Successor
Cash and cash equivalents	76,540
Oil and gas sales	33,895
Joint interest billing	4,739
Other	26
Other current assets	5,677
Total current assets	120,877
Fresh Start Adjustments
Oil and gas properties, on the basis of full-cost accounting (h)	(3,176,723)
Other property and equipment (h)	(5,965)
Less accumulated depreciation, depletion, amortization and impairment (h)	3,449,241
Net property and equipment	266,553
Successor
Oil and gas properties, on the basis of full-cost accounting	619,220
Other property and equipment	6,210
Net property and equipment	625,430
Reorganization Adjustments
Other noncurrent assets (c)	1,250
TOTAL	(199,488)
Fresh Start Adjustments
TOTAL	266,553
Successor
Other noncurrent assets	4,951
TOTAL	751,258
Reorganization Adjustments
Accrued liabilities (a)	(15,416)
Debt classified as current (a)(d)	(249,384)
Total current liabilities	264,800
Successor
Accounts payable	10,294
Accrued liabilities	49,824
Total current liabilities	60,118
Reorganization Adjustments
OTHER LONG-TERM LIABILITIES (d)	128,059
LIABILITIES SUBJECT TO COMPROMISE (e)(a)	(1,882,187)
Fresh Start Adjustments
ASSET RETIREMENT OBLIGATIONS (h)	(6,385)
Successor
ASSET RETIREMENT OBLIGATIONS	13,983
OTHER LONG-TERM LIABILITIES	128,676
Reorganization Adjustments
Warrants	37,329
Common stock (f)	(104)
Common stock - successor	247
Treasury stock (f)	3,134
Additional paid in capital - predecessor (f)	(891,292)
Retained deficit (g)	2,159,221
Total stockholders' equity/(deficit)	1,819,440
TOTAL	(199,488)
Fresh Start Adjustments
Retained deficit (i)	272,938
Total stockholders' equity/(deficit)	272,938
TOTAL	266,553
Successor
Warrants	37,329
Common stock	247
Additional paid in capital	510,905
Total stockholders' equity	548,481
TOTAL	$ 751,258
Predecessor
CURRENT ASSETS:
Cash and cash equivalents		$ 274,530
Oil and gas sales		33,895
Joint interest billing		4,739
Other		26
Other current assets		8,425
Total current assets		321,615
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting		3,795,943
Other property and equipment		12,175
Less accumulated depreciation, depletion, amortization and impairment		(3,449,241)
Net property and equipment		358,877
Successor
Other noncurrent assets		3,701
TOTAL		684,193
CURRENT LIABILITIES:
Accounts payable		10,294
Accrued liabilities		65,240
Debt classified as current		249,384
Total current liabilities		324,918
Successor
ASSET RETIREMENT OBLIGATIONS		20,368
OTHER LONG-TERM LIABILITIES		617
LIABILITIES SUBJECT TO COMPROMISE		1,882,187
STOCKHOLDERS' EQUITY:
Common stock		104
Treasury stock		(3,134)
Additional paid in capital - predecessor		891,292
Retained deficit		(2,432,159)
Total Stockholders' equity(deficit)		(1,543,897)
TOTAL		$ 684,193

Fresh Start Accounting - Cash a

Fresh Start Accounting - Cash and cash equivalents (Details) $ in Thousands	Oct. 21, 2016USD ($)
Fresh start accounting adjustments
Cash paydown (payments)	$ 121,300
Payment to escrow for professional fees related to the Plan incurred through the effective date	15,416
Debt issuance costs associated with the Exit Facility	1,250
Total uses	197,990
Second lien notes
Fresh start accounting adjustments
Cash paydown (payments)	60,000
RBL
Fresh start accounting adjustments
Cash paydown (payments)	81,324
Exit Facility
Fresh start accounting adjustments
Cash paydown (payments)	$ 40,000

Fresh Start Accounting - Gain o

Fresh Start Accounting - Gain on settlement (Details) - USD ($) $ in Thousands	Oct. 21, 2016	Oct. 20, 2016
Fresh start accounting adjustments
Liabilities subject to compromise	$ 1,882,187
Cash paid to holders of Notes	(121,300)
Warrants	(37,329)
Write off of unamortized debt costs associated with RBL	(2,748)
Common stock issued	(511,152)
Gain on settlement	1,270,959	$ 1,270,959
Unsecured Note
Fresh start accounting adjustments
Warrants	(7,575)
Second lien notes
Fresh start accounting adjustments
Cash paid to holders of Notes	(60,000)
Third lien notes
Fresh start accounting adjustments
Warrants	$ (29,753)

Fresh Start Accounting - New st

Fresh Start Accounting - New stock issues (Details) - shares	Nov. 09, 2016	Oct. 21, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Common Stock
Fresh start accounting adjustments
New stock issued (in shares)	294,967	24,687,500	307,367	247,201	278,102

Fresh Start Accounting - Cumula

Fresh Start Accounting - Cumulative impact (Details) - USD ($) $ in Thousands	Oct. 21, 2016	Oct. 20, 2016
Fresh start accounting adjustments
Liabilities subject to compromise	$ 1,270,959	$ 1,270,959
Net impact to Predecessor accumulated deficit	$ 2,159,221
Predecessor
Fresh start accounting adjustments
Common stock		104
Treasury stock		(3,134)
Additional paid in capital - predecessor		$ 891,292

Fresh Start Accounting - Fresh

Fresh Start Accounting - Fresh Start Adjustments (Details) $ in Thousands	Oct. 21, 2016USD ($)
Fresh start accounting adjustments
Removal of accumulated depreciation, depletion, amortization and impairment - Fresh Start Adjustment	$ (3,449,241)
Oil and gas properties, on the basis of full-cost accounting (h)	(3,176,723)
Decrease in asset retirement obligation	(6,385)
Oil and Gas
Fresh start accounting adjustments
Oil and gas properties, on the basis of full-cost accounting (h)	$ 269,700

Fresh Start Accounting - Reor_3

Fresh Start Accounting - Reorganization items (Details) - USD ($) $ in Thousands	Oct. 21, 2016	Oct. 20, 2016
Reorganization items
Gain on settlement of liabilities subject to compromise	$ 1,270,959	$ 1,270,959
Fresh start adjustments	$ 272,938
Other reorganization items		1,221
Office fixed assets
Reorganization items
Other reorganization items		200
Office lease
Reorganization items
Other reorganization items		1,600
Predecessor
Reorganization items
Professional fees incurred		(38,835)
Gain on reorganization items, net		1,594,281
Predecessor | Second lien notes
Reorganization items
Unamortized gain on troubled debt restructuring		39,599
Predecessor | Third lien notes
Reorganization items
Unamortized gain on troubled debt restructuring		71,808
Predecessor | 2020 Senior Notes
Reorganization items
Unamortized Debt Issuance Costs		(10,738)
Predecessor | 2021 Senior Notes
Reorganization items
Unamortized Debt Issuance Costs		$ (12,671)

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Basis of Presentation (Details)	12 Months Ended
	Dec. 31, 2018segment
Summary of Significant Accounting Policies
Reportable segments (in segments)	1
Operating segments (in segments)	1

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Cash and Cash Equivalents (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Summary of Significant Accounting Policies
Cash balances exceeding FDIC Insurance	$ 12.8	$ 70.4

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Accounts Receivable and Allowance for Doubtful Accounts (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Summary of Significant Accounting Policies
Allowance for doubtful accounts	$ 0	$ 0

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Property and Equipment - Unevaluated Property (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Jul. 26, 2017
Property and equipment
Unevaluated property costs transferred to the full cost pool	$ 3	$ 58
Divestiture of Oil and Gas Properties
Property and equipment
Unevaluated property costs transferred to the full cost pool			$ 3

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Property and Equipment - Impairment and useful lives (Details) - USD ($) $ in Thousands	10 Months Ended	12 Months Ended
	Oct. 20, 2016	Dec. 31, 2018	Dec. 31, 2017
Property and equipment
Impairment of Oil and Gas Properties			$ 125,300
Carmen and Dacoma
Property and equipment
Impairment of Oil and Gas Properties			$ 125,300
Predecessor
Property and equipment
Impairment of Oil and Gas Properties	$ 232,108
Other Property and Equipment | Minimum
Property and equipment
Estimated useful lives (in years)		2 years
Other Property and Equipment | Maximum
Property and equipment
Estimated useful lives (in years)		10 years

Summary of Significant Accoun_9

Summary of Significant Accounting Policies - Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Summary of Significant Accounting Policies
Accrued oil and gas capital expenditures	$ 1,534	$ 9,081
Accrued revenue and royalty distributions	13,302	18,701
Accrued lease operating and workover expense	2,843	5,150
Accrued interest	209	108
Accrued taxes	1,813	2,758
Compensation and benefit related accruals	2,855	4,520
Other	2,965	2,524
Accrued liabilities	$ 25,521	$ 42,842

Summary of Significant Accou_10

Summary of Significant Accounting Policies - Recent Accounting Pronouncments Adopted During the Period (Details) - ASU 2016-02 - Effect of Accounting Principle Adoption $ in Thousands	Jan. 01, 2019USD ($)
Minimum
Recent accounting pronouncements
Operating Lease, Liability	$ 0
Operating Lease, Right-of-Use Asset	4
Maximum
Recent accounting pronouncements
Operating Lease, Liability	0
Operating Lease, Right-of-Use Asset	$ 7

Impact of ASC 606 Adoption (Det

Impact of ASC 606 Adoption (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Impact of ASC 606 Adoption
Revenues	$ 48,525	$ 69,643	$ 47,765	$ 42,324	$ 48,905	$ 53,344	$ 49,715	$ 60,679	$ 65,015	$ 208,637	$ 228,753
Gathering and transportation	3,194									241	14,507
Lease operating and workover expense	15,324									54,229	63,287
Net income	9,930									49,784	(85,077)
Retained deficit		(25,363)				$ (75,147)				(25,363)	(75,147)
Under ASC 605
Impact of ASC 606 Adoption
Gathering and transportation										12,646
Lease operating and workover expense										54,469
Net income										49,784
Retained deficit		$ (25,363)								(25,363)
Increase/(Decrease)
Impact of ASC 606 Adoption
Gathering and transportation										(12,405)
Lease operating and workover expense										(240)
Oil
Impact of ASC 606 Adoption
Revenues	25,549									123,945	117,083
Oil | Under ASC 605
Impact of ASC 606 Adoption
Revenues										124,006
Oil | Increase/(Decrease)
Impact of ASC 606 Adoption
Revenues										(61)
Natural gas liquid
Impact of ASC 606 Adoption
Revenues	8,391									44,747	44,112
Natural gas liquid | Under ASC 605
Impact of ASC 606 Adoption
Revenues										44,818
Natural gas liquid | Increase/(Decrease)
Impact of ASC 606 Adoption
Revenues										(71)
Natural gas
Impact of ASC 606 Adoption
Revenues	$ 13,635									32,138	$ 59,708
Natural gas | Under ASC 605
Impact of ASC 606 Adoption
Revenues										44,651
Natural gas | Increase/(Decrease)
Impact of ASC 606 Adoption
Revenues										$ (12,513)

Impact of ASC 606 Adoption - Im

Impact of ASC 606 Adoption - Imbalances (Details) $ in Thousands	Dec. 31, 2018USD ($)
Extractive Industries [Abstract]
Production balance asset (liability)	$ 0

Fair Value Measurements of Fi_3

Fair Value Measurements of Financial Instruments (Details) $ in Thousands	Dec. 31, 2018USD ($)Counterparty	Dec. 31, 2017USD ($)
Fair Value Measurements of Financial Instruments
Number of counterparties | Counterparty	4
Recurring | Estimated | Commodity Derivatives
Derivative Assets:
Total assets	$ 13,925	$ 4,384
Derivative Liabilities:
Total liabilities	(6,274)	(7,617)
Recurring | Estimated | Commodity Derivatives | Swaps | Oil
Derivative Assets:
Total assets	3,806
Derivative Liabilities:
Total liabilities		(3,679)
Recurring | Estimated | Commodity Derivatives | Swaps | Natural gas
Derivative Assets:
Total assets	236	821
Derivative Liabilities:
Total liabilities	(443)
Recurring | Estimated | Commodity Derivatives | Collars | Oil
Derivative Assets:
Total assets	9,306	952
Derivative Liabilities:
Total liabilities	(5,199)	(2,605)
Recurring | Estimated | Commodity Derivatives | Collars | Natural gas
Derivative Assets:
Total assets	577	2,611
Derivative Liabilities:
Total liabilities	(632)	(1,333)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives
Derivative Assets:
Total assets	13,925	4,384
Derivative Liabilities:
Total liabilities	(6,274)	(7,617)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Swaps | Oil
Derivative Assets:
Total assets	3,806
Derivative Liabilities:
Total liabilities		(3,679)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Swaps | Natural gas
Derivative Assets:
Total assets	236	821
Derivative Liabilities:
Total liabilities	(443)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Collars | Oil
Derivative Assets:
Total assets	9,306	952
Derivative Liabilities:
Total liabilities	(5,199)	(2,605)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Collars | Natural gas
Derivative Assets:
Total assets	577	2,611
Derivative Liabilities:
Total liabilities	$ (632)	$ (1,333)

Risk Management and Derivativ_3

Risk Management and Derivative Instruments- Hedging (Details) - Designated as Hedging Instrument $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)MMBTU$ / bbl$ / MMBTUbbl
Risk Management and Derivative Instruments
Derivative contracts, loss | $	$ 7.7
NYMEX | WTI | Swap Contract Quarter Ended December 31, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	313,720
Swap weighted average strike price	58.59
NYMEX | WTI | Swap Contract Quarter Ended March 31, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	74,800
Swap weighted average strike price	66.48
NYMEX | WTI | Swap Contract Quarter Ended June 30, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	57,650
Swap weighted average strike price	64.69
NYMEX | WTI | Swap Contract Quarter Ended September 30, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	46,000
Swap weighted average strike price	62.96
NYMEX | WTI | Swap Contract Quarter Ended December 31, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	46,000
Swap weighted average strike price	61.43
NYMEX | WTI | Three Way Collar Contract Quarter Ended December 31, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	46,000
Weighted average ceiling price	56.70
Weighted average floor price	50
Weighted average sub-floor price	40
NYMEX | WTI | Three Way Collar Contract Quarter Ended March 31, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	180,000
Weighted average ceiling price	63.14
Weighted average floor price	53.75
Weighted average sub-floor price	43.75
NYMEX | WTI | Three Way Collar Contract Quarter Ended June 30, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	182,000
Weighted average ceiling price	63.14
Weighted average floor price	53.75
Weighted average sub-floor price	43.75
NYMEX | WTI | Three Way Collar Contract Quarter Ended September 30, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	184,000
Weighted average ceiling price	63.14
Weighted average floor price	53.75
Weighted average sub-floor price	43.75
NYMEX | WTI | Three Way Collar Contract Quarter Ended December 31, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	184,000
Weighted average ceiling price	63.14
Weighted average floor price	53.75
Weighted average sub-floor price	43.75
NYMEX | WTI | Three Way Collar Contract Quarter Ended March 31, 2020
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	91,000
Weighted average ceiling price	65.75
Weighted average floor price	50
Weighted average sub-floor price	40
NYMEX | WTI | Three Way Collar Contract Quarter Ended June 30, 2020
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	91,000
Weighted average ceiling price	65.75
Weighted average floor price	50
Weighted average sub-floor price	40
NYMEX | WTI | Three Way Collar Contract Quarter Ended September 30, 2020
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	92,000
Weighted average ceiling price	65.75
Weighted average floor price	50
Weighted average sub-floor price	40
NYMEX | WTI | Three Way Collar Contract Quarter Ended December 31, 2020
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	92,000
Weighted average ceiling price	65.75
Weighted average floor price	50
Weighted average sub-floor price	40
NYMEX | HENRY HUB | Swap Contract Quarter Ended December 31, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	2,055,000
Swap weighted average strike price | $ / MMBTU	2.95
NYMEX | HENRY HUB | Swap Contract Quarter Ended March 31, 2019
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,980,000
Swap weighted average strike price | $ / MMBTU	3.01
NYMEX | HENRY HUB | Swap Contract Quarter Ended June 30, 2019
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,365,000
Swap weighted average strike price | $ / MMBTU	2.75
NYMEX | HENRY HUB | Swap Contract Quarter Ended September 30, 2019
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,380,000
Swap weighted average strike price | $ / MMBTU	2.75
NYMEX | HENRY HUB | Swap Contract Quarter Ended December 31, 2019
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	465,000
Swap weighted average strike price | $ / MMBTU	2.75
NYMEX | HENRY HUB | Three Way Collar Contract Quarter Ended December 31, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,380,000
Weighted average ceiling price | $ / MMBTU	3.40
Weighted average floor price | $ / MMBTU	3
Weighted average sub-floor price | $ / MMBTU	2.50
NYMEX | HENRY HUB | Three Way Collar Contract Quarter Ended March 31, 2019
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,350,000
Weighted average ceiling price | $ / MMBTU	3.40
Weighted average floor price | $ / MMBTU	3
Weighted average sub-floor price | $ / MMBTU	2.50
NYMEX | HENRY HUB | Three Way Collar Contract Quarter Ended December 31, 2019
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	610,000
Weighted average ceiling price | $ / MMBTU	3.45
Weighted average floor price | $ / MMBTU	2.65
Weighted average sub-floor price | $ / MMBTU	2.15
NYMEX | HENRY HUB | Three Way Collar Contract Quarter Ended March 31, 2020
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	910,000
Weighted average ceiling price | $ / MMBTU	3.45
Weighted average floor price | $ / MMBTU	2.65
Weighted average sub-floor price | $ / MMBTU	2.15

Risk Management and Derivativ_4

Risk Management and Derivative Instruments- Balance Sheet Presentation (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Total derivative financial instruments - current liabilities		$ (3,433)
Total derivative financial instruments - noncurrent liabilities	$ (80)	(562)
Commodity Derivatives | Not designated as Hedging Instrument
Total derivative financial instruments - current assets	6,940	762
Total derivative financial instruments - noncurrent assets	791
Total derivative financial instruments - current liabilities		(3,433)
Total derivative financial instruments - noncurrent liabilities	(80)	(562)
Total derivative fair value at period end	7,651	(3,233)
Derivative assets:
Gross Recognized Assets	13,925	4,384
Gross Amounts Offset, Assets	(6,194)	(3,622)
Net Recognized Fair Value Assets	7,731	762
Derivative liabilities:
Gross Recognized Liabilities	(6,274)	(7,617)
Gross Amounts Offset, Liabilities	6,194	3,622
Net Recognized Fair Value Liabilities	(80)	(3,995)
Commodity Derivatives | Not designated as Hedging Instrument | Swap | Oil
Total derivative financial instruments - current assets	3,806
Total derivative financial instruments - current liabilities		(3,679)
Commodity Derivatives | Not designated as Hedging Instrument | Swap | Natural gas
Total derivative financial instruments - current assets	(207)	821
Commodity Derivatives | Not designated as Hedging Instrument | Collars | Oil
Total derivative financial instruments - current assets	3,316	(760)
Total derivative financial instruments - noncurrent assets	791
Total derivative financial instruments - current liabilities		(370)
Total derivative financial instruments - noncurrent liabilities		(523)
Commodity Derivatives | Not designated as Hedging Instrument | Collars | Natural gas
Total derivative financial instruments - current assets	25	701
Total derivative financial instruments - current liabilities		616
Total derivative financial instruments - noncurrent liabilities	(80)	(39)
Current Assets | Commodity Derivatives | Not designated as Hedging Instrument
Derivative assets:
Gross Recognized Assets	11,066	3,479
Gross Amounts Offset, Assets	(4,126)	(2,717)
Net Recognized Fair Value Assets	6,940	762
Non-Current Assets | Commodity Derivatives | Not designated as Hedging Instrument
Derivative assets:
Gross Recognized Assets	2,859	905
Gross Amounts Offset, Assets	(2,068)	(905)
Net Recognized Fair Value Assets	791
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument
Derivative liabilities:
Gross Recognized Liabilities	(4,126)	(6,150)
Gross Amounts Offset, Liabilities	4,126	2,717
Net Recognized Fair Value Liabilities		(3,433)
Non-Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument
Derivative liabilities:
Gross Recognized Liabilities	(2,148)	(1,467)
Gross Amounts Offset, Liabilities	2,068	905
Net Recognized Fair Value Liabilities	$ (80)	$ (562)

Risk Management and Derivativ_5

Risk Management and Derivative Instruments - Gain Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Risk Management and Derivative Instruments
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments	$ (7,328)	$ 6,891
Unrealized net gains (losses)	10,883	(3,232)
Gains (losses) on commodity derivative contracts - net	$ 3,555	$ 3,659

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Oil and gas properties, on the basis of full-cost accounting
Proved properties	$ 809,272	$ 765,308
Unproved properties not being amortized	4,050	7,065
Other property and equipment	6,345	6,508
Less accumulated depreciation, depletion, amortization and impairment	(266,198)	(204,419)
Net property and equipment	$ 553,469	$ 574,462

Property and Equipment - Additi

Property and Equipment - Additional information (Details) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)$ / Boe	Oct. 20, 2016USD ($)$ / Boe	Dec. 31, 2018USD ($)$ / Boe	Dec. 31, 2017USD ($)$ / Boe
Other information
Depreciation, Depletion and Amortization	$ 12,974		$ 62,000	$ 65,832
Interest capitalized	700		500	2,400
Internal costs capitalized	1,400		2,800	5,300
Qualifying share-based compensation expense	637		890	1,995
Oil and Gas
Other information
Depreciation, Depletion and Amortization	$ 12,600		$ 60,000	$ 63,400
Depletion expense (per Boe) | $ / Boe	7		9	7.85
Other Property and Equipment
Other information
Depreciation, Depletion and Amortization	$ 400		$ 2,000	$ 2,400
Predecessor
Other information
Depreciation, Depletion and Amortization		$ 62,302
Internal costs capitalized		3,400
Qualifying share-based compensation expense		476
Predecessor | Oil and Gas
Other information
Depreciation, Depletion and Amortization		$ 59,900
Depletion expense (per Boe) | $ / Boe		6.84
Predecessor | Other Property and Equipment
Other information
Depreciation, Depletion and Amortization		$ 2,400

Acquisition and Divestitures _2

Acquisition and Divestitures of Oil and Gas Properties (Details) - USD ($) $ in Thousands	May 31, 2018	Jul. 26, 2017	Dec. 31, 2018	Dec. 31, 2017
Acquisition of Oil and Gas Properties
Proceeds from the sale, net			$ 54,091	$ 2,885
Acquisition and transaction costs			$ 900
Exit Facility
Acquisition of Oil and Gas Properties
Repayment of debt using proceeds from sale	$ 50,000
Divestiture of Oil and Gas Properties
Acquisition of Oil and Gas Properties
Proceeds from the sale, gross	58,000	$ 7,000
Proceeds from the sale, net	$ 54,100	$ 2,900

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	2 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Changes in asset retirement obligations
Asset retirement obligations at beginning of period		$ 15,506	$ 14,200
Liabilities incurred		435	571
Revisions			1,832
Liabilities settled		(1)	(744)
Liabilities eliminated through asset sales		(8,699)	(1,453)
Current period accretion expense	$ 210	846	1,100
Asset retirement obligations at end of period	$ 14,200	$ 8,087	$ 15,506

Debt (Details)

Debt (Details) $ in Thousands	Feb. 14, 2019USD ($)	Nov. 15, 2018USD ($)	May 31, 2018USD ($)	Oct. 20, 2016USD ($)	Feb. 29, 2016USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Oct. 24, 2018USD ($)	Oct. 21, 2016USD ($)	Apr. 01, 2016USD ($)
Debt
Drawn from facility						$ 1,000
Letter of credit obligations						1,900	$ 1,900
Exit Facility
Debt
Maximum borrowing capacity						170,000	170,000	$ 170,000	$ 170,000
Repayment of debt						105,000
Repayment from available cash						55,000
Repayment of debt using proceeds from sale			$ 50,000
Drawn from facility						23,100	$ 128,100
Current borrowing capacity						$ 145,000
Weighted-average interest rate (as a percent)						7.30%	6.30%
Unamortized debt issuance costs						$ 1,200	$ 1,200
Commitment fee (as a percent)						0.50
Net indebtedness to EBITDA covenant		1.50
Liquidity covenant		$ 50,000
Exit Facility | Subsequent Event
Debt
Drawn from facility	$ 39,000
Exit Facility | Minimum
Debt
EBITDA to interest expense coverage ratio						2.50
Exit Facility | Maximum
Debt
Net indebtedness to EBITDA covenant						4
Exit Facility | LIBOR
Debt
Basis rate (as a percent)						4.50%
Exit Facility | LIBOR floor
Debt
Basis rate (as a percent)						1.00%
RBL
Debt
Maximum borrowing capacity				$ 750,000						$ 170,000
Repayment of debt using proceeds from sale			$ 50,000
Drawn from facility					$ 249,200
RBL | LIBOR | Minimum
Debt
Basis rate (as a percent)				2.00%
RBL | LIBOR | Maximum
Debt
Basis rate (as a percent)				3.00%

Debt - Reorganization (Details)

Debt - Reorganization (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 21, 2016	Dec. 31, 2018	Oct. 24, 2018	Dec. 31, 2017	Oct. 20, 2016	Apr. 01, 2016
2016 Reorganization
Cash paydown (payments)	$ 121,300
Second lien notes
2016 Reorganization
Cash paydown (payments)	$ 60,000
Equity allocated to holders of debtors (as a percent)	96.25%
Third lien notes | Warrants
2016 Reorganization
Equity allocated to holders of debtors (as a percent)	2.50%
Warrants to acquire common stock shares (in shares)	4,411,765
Exercise price (in dollars per share)	$ 24
Warrants expiration term	42 months
Unsecured Note | Warrants
2016 Reorganization
Equity allocated to holders of debtors (as a percent)	1.25%
Warrants to acquire common stock shares (in shares)	2,213,789
Exercise price (in dollars per share)	$ 46
Warrants expiration term	42 months
Exit Facility
2016 Reorganization
Cash paydown (payments)	$ 40,000
Maximum borrowing capacity	170,000	$ 170,000	$ 170,000	$ 170,000
RBL
2016 Reorganization
Cash paydown (payments)	$ 81,324
Maximum borrowing capacity					$ 750,000	$ 170,000

Debt - Credit Facilities (Detai

Debt - Credit Facilities (Details) - USD ($) $ in Thousands	Oct. 20, 2016	Apr. 01, 2016	Jun. 02, 2015	Feb. 29, 2016	Dec. 31, 2018	Oct. 21, 2016	May 21, 2015	May 31, 2013	Oct. 01, 2012
Debt
Drawn from facility					$ 1,000
Cash paydown (payments)						$ 121,300
2020 Senior Notes
Debt
Face amount									$ 600,000
Debt instrument exchanged face amount			$ 306,400
Interest rate (as a percent)									10.75%
2021 Senior Notes
Debt
Face amount								$ 700,000
Debt instrument exchanged face amount			352,300
Interest rate (as a percent)								9.25%
Second lien notes
Debt
Cash paydown (payments)						60,000
Face amount							$ 625,000
Interest rate (as a percent)							10.00%
Third lien notes
Debt
Face amount			$ 20,000				$ 504,100
Interest rate (as a percent)							12.00%
Cash interest rate							10.00%
PIK Interest							2.00%
RBL
Debt
Maximum borrowing capacity	$ 750,000	$ 170,000
Current borrowing capacity	$ 252,000	170,000
Drawn from facility				$ 249,200
Borrowing capacity increase (decrease)		$ (82,000)
Commitment fee, option one (as a percent)	0.375%
Commitment fee, option two (as a percent)	0.50%
Cash paydown (payments)						$ 81,324
RBL | LIBOR | Minimum
Debt
Basis rate (as a percent)	2.00%
RBL | LIBOR | Maximum
Debt
Basis rate (as a percent)	3.00%

Preferred Stock (Details)

Preferred Stock (Details) - $ / shares	Sep. 30, 2015	Oct. 01, 2012	Dec. 31, 2015	Dec. 31, 2018	Dec. 31, 2017
Series A Preferred Stock
Preferred stock, shares issued				0	0
Predecessor | Series A Preferred Stock
Series A Preferred Stock
Preferred stock, shares issued		325,000
Liquidation value (in dollars per share)		$ 1,000
Rate of dividend for preferred stock (as a percent)		8.00%
Converstion ratio	11.5
Shares issued (in shares)			3,738,424

Equity and Share-Based Compen_3

Equity and Share-Based Compensation - Common Shares (Details)	Nov. 09, 2016shares	Nov. 08, 2016shares	Oct. 21, 2016shares	Oct. 20, 2016shares	Dec. 31, 2016shares	Oct. 20, 2016shares	Dec. 31, 2018Vote$ / sharesshares	Dec. 31, 2017$ / sharesshares
Common Shares
Common Stock, shares issued (in shares)							25,520,170	25,272,969
Common stock, shares outstanding							25,345,981	25,173,346
Common stock, shares authorized							250,000,000	250,000,000
Preferred stock, shares authorized							50,000,000	50,000,000
Preferred stock, par value (in dollars per share) | $ / shares							$ 0.01	$ 0.01
Common stock, par value (in dollars per share) | $ / shares							$ 0.01	$ 0.01
Common Stock, votes per share (in votes) | Vote							1
Common Stock
Common Shares
Shares available for future distribution (in shares)			17,533
Changes in number of shares outstanding
Common stock, bgn balance (in shares)							25,272,969	24,994,867
Issuance of successor common stock (in shares)	294,967		24,687,500		307,367		247,201	278,102
Common stock, ending balance			24,687,500		24,994,867		25,520,170	25,272,969
Common Stock | Director
Common Shares
Granted (in shares)		12,400
Treasury Stock
Changes in number of shares outstanding
Treasury stock, bgn balance (in shares)							(99,623)
Acquisition of treasury stock (in shares)							74,566	(99,623)
Treasury stock, ending balance (in shares)							(174,189)	(99,623)
Common Stock | Director
Common Shares
Granted (in shares)		12,400
Predecessor | Common Stock
Changes in number of shares outstanding
Common stock, bgn balance (in shares)			10,914,780		10,914,780	10,962,105
Forfeitures of restricted stock (in shares)						(47,325)
Cancellation of common stock (in shares)				(10,914,780)
Common stock, ending balance				10,914,780		10,914,780
Predecessor | Treasury Stock
Changes in number of shares outstanding
Treasury stock, bgn balance (in shares)			(148,649)		(148,649)	(96,291)
Cancellation of treasury stock (in shares)				148,649
Acquisition of treasury stock (in shares)						(52,358)
Treasury stock, ending balance (in shares)				(148,649)		(148,649)

Equity and Share-Based Compen_4

Equity and Share-Based Compensation - Warrants (Details) - Warrants	Oct. 21, 2016$ / sharesshares
Unsecured Note
Warrants
Warrants issued	2,213,789
Warrants to acquire common stock shares (in shares)	2,213,789
Exercise price (in dollars per share) | $ / shares	$ 46
Third lien notes
Warrants
Warrants issued	4,411,765
Warrants to acquire common stock shares (in shares)	4,411,765
Exercise price (in dollars per share) | $ / shares	$ 24

Equity and Share-Based Compen_5

Equity and Share-Based Compensation - Emergence from Bankruptcy and 2016 Long Term Incentive Plan (Details) - USD ($) $ in Millions	10 Months Ended
	Oct. 20, 2016	Dec. 31, 2018	Oct. 21, 2016
Share-Based Compensation
Shares authorized (in shares)			25,000,000
2016 LTIP
Share-Based Compensation
Shares authorized (in shares)			3,513,950
Shares available for future distribution (in shares)		2,100,933
Predecessor
Share-Based Compensation
Cancellation of share based awards expense	$ 1.3

Equity and Share-Based Compen_6

Equity and Share-Based Compensation - Restricted Stock Units (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 21, 2017	Oct. 21, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Oct. 20, 2016	Dec. 31, 2018	Dec. 31, 2017
Additional information
Share-based compensation, net of amounts capitalized to oil and gas properties			$ 2,909				$ 5,407	$ 9,196
Qualifying share-based compensation expense			$ 637				$ 890	$ 1,995
Restricted Stock Units
Share-Based Compensation
Vesting period (in years)							3 years
Vesting percentage (in percent)							33.00%
Restricted Stock
Non-vested shares outstanding at the beginning of the period (in shares)							324,984	685,662
Granted (in shares)		686,324	2,035				271,968	85,389
Vested (in shares)							(323,927)	(335,958)
Forfeited (in shares)			(2,697)				(21,503)	(110,109)
Non-vested shares outstanding at the end of the period (in shares)		686,324	685,662	251,522	324,984		251,522	324,984
Weighted Average Grant Date Fair Value
Non-vested shares outstanding at the beginning of the period (in dollars per share)							$ 18.84	$ 19.66
Granted (in dollars per share)		$ 19.66	$ 20.97				14.24	16.50
Vested (in dollars per share)							17.57	19.65
Forfeited (in dollars per share)			19.66				15.52	19.66
Non-vested shares outstanding at the end of the period (in dollars per share)		$ 19.66	$ 19.66	$ 15.79	$ 18.84		$ 15.79	$ 18.84
Additional information
Accelerated vesting (in shares)	109,820						102,092
Vested but issuance deferred (in shares)								57,856
Share-based compensation, net of amounts capitalized to oil and gas properties			$ 1,700				$ 4,500	$ 5,800
Accelerated compensation expense				$ 100	$ 1,200
Qualifying share-based compensation expense			$ 400				700	$ 1,300
Unrecognized expense for share-based compensation				$ 1,900			$ 1,900
Weighted-average period for over which unrecognized expense will be recognized							1 year 3 months 18 days
Restricted Stock Units | Director
Additional information
Accelerated vesting (in shares)							26,223
Predecessor
Additional information
Share-based compensation, net of amounts capitalized to oil and gas properties						$ 2,564
Qualifying share-based compensation expense						$ 476
Predecessor | Restricted Stock Units
Restricted Stock
Non-vested shares outstanding at the beginning of the period (in shares)		108,313	108,313			318,031
Vested (in shares)						(162,393)
Forfeited (in shares)		(108,313)				(47,325)
Non-vested shares outstanding at the end of the period (in shares)						108,313
Weighted Average Grant Date Fair Value
Non-vested shares outstanding at the beginning of the period (in dollars per share)		$ 20.08	$ 20.08			$ 21.46
Vested (in dollars per share)						23.09
Forfeited (in dollars per share)		$ 20.08				19.02
Non-vested shares outstanding at the end of the period (in dollars per share)						$ 20.08
Additional information
Share-based compensation, net of amounts capitalized to oil and gas properties						$ 2,600
Qualifying share-based compensation expense						$ 500
twelve-month anniversary of the grant | Restricted Stock Units
Share-Based Compensation
Vesting percentage (in percent)							33.00%
twenty four-month anniversary of the grant date | Restricted Stock Units
Share-Based Compensation
Vesting percentage (in percent)							33.00%

Equity and Share-Based Compen_7

Equity and Share-Based Compensation - Stock Options (Details) $ / shares in Units, $ in Thousands	2 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)company$ / sharesshares	Dec. 31, 2016$ / sharesshares
Additional information
Share-based compensation, net of amounts capitalized to oil and gas properties | $	$ 2,909	$ 5,407	$ 9,196
Qualifying share-based compensation expense | $	$ 637	$ 890	$ 1,995
Stock options
Share-Based Compensation
Vesting period (in years)		3 years
Expiration period (in years)		10 years
Weighted average assumptions used
Risk-free interest rate (as a percent)	1.38%		2.11%
Expected option life (in years)	5 years 11 months 16 days		5 years 11 months 16 days
Expected volatility (as a percent)	60.00%		65.00%
Calculated fair value	$ 10.88		$ 11.43	$ 10.88
Increase in expense due to change in expected term | $	$ 100
Decrease in expense due to change in expected term | $	$ (200)
Options
Stock options outstanding at beginning of period (in shares) | shares		245,845	627,806
Granted (in shares) | shares			4,000
Vested (in shares) | shares		(170,173)	(253,678)
Forfeited (in shares) | shares		(5,570)	(132,283)
Stock options outstanding at end of period (in shares) | shares	627,806	70,102	245,845	627,806
Vested and exercisable at end of period (in shares) | shares		136,161
Range of Exercise Prices
Exercise price (Lower limit)		$ 19.08	$ 19.08
Exercise price (Upper limit)		20.97	20.97
Weighted Average Exercise Price
Stock options outstanding at beginning of period (in dollars per share)		19.66	19.66
Granted (in dollars per share)			19.08
Weighted average vested price of vested options (in dollars per share)		19.66	19.66
Forfeited (in dollars per share)		19.66	19.66
Stock options outstanding at end of period (in dollars per share)	$ 19.66	19.65	$ 19.66	$ 19.66
Vested and exercisable at end of period (in dollars per share)		$ 19.67
Weighted Average Remaining Contractual Term (Years)
Granted (in years)			9 years 2 months 12 days
Vested (in years)		7 years 9 months 18 days
Stock options outstanding at end of period (in years)		7 years 9 months 18 days	8 years 10 months 24 days	8 years 9 months 18 days
Vested and exercisable at end of period (in years)		7 years 9 months 18 days
Additional information
Accelerated vesting (in shares) | shares		102,092
Share-based compensation, net of amounts capitalized to oil and gas properties | $	$ 800	$ 900	$ 2,600
Qualifying share-based compensation expense | $	$ 200	200	$ 700
Unrecognized expense for share-based compensation | $		$ 200
Weighted-average period for over which unrecognized expense will be recognized		9 months 18 days
Stock options | Minimum
Weighted Average Exercise Price
Vested and exercisable at end of period (in dollars per share)		$ 19.08
Stock options | Maximum
Weighted Average Exercise Price
Vested and exercisable at end of period (in dollars per share)		$ 20.97
Stock options | Estimated
Weighted average assumptions used
Number of companies (in companies) | company			6
Expected volatility rate, minimum (as a percent)	38.50%		36.90%
Expected volatility rate, maximum (as a percent)	65.90%		68.20%
Stock options | six-month anniversary of grant date
Share-Based Compensation
Vesting percentage (in percent)		16.66%
Stock options | twelve-month anniversary of the grant
Share-Based Compensation
Vesting percentage (in percent)		16.66%
Stock options | twenty four-month anniversary of the grant date
Share-Based Compensation
Vesting percentage (in percent)		33.33%
Stock options | thirty six month anniversary of the grant date
Share-Based Compensation
Vesting percentage (in percent)		33.33%
Weighted average assumptions used
Increase in expense due to change in expected term | $	$ 900
Decrease in expense due to change in expected term | $	$ (1,100)

Equity and Share-Based Compen_8

Equity and Share-Based Compensation - Non-Employee Director Restricted Stock Units Containing a Market Condition (Details) - RSU with market condition - Director $ / shares in Units, $ in Millions	Nov. 23, 2016shares	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)company$ / sharesshares
Share-Based Compensation
Service period (in years)		1 year
Assumptions used
Risk-free interest rate (as a percent)		2.43%	2.06%
Expected volatility (as a percent)		39.00%	54.80%
Market Price Hurdle (in dollars per share) | $ / shares		$ 30	$ 30
Calculated fair value | $ / shares		$ 0.41	$ 11.54
Liability related to market condition awards | $		$ 0.1	$ 0.9
Unrecognized expense for share-based compensation | $		$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested shares outstanding at the beginning of the period (in shares) | shares		76,296
Granted (in shares) | shares	76,296
Forfeited (in shares) | shares		(25,432)
Non-vested shares outstanding at the end of the period (in shares) | shares		50,864	76,296
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested shares outstanding at the beginning of the period (in dollars per share) | $ / shares		$ 17.71
Non-vested shares outstanding at the end of the period (in dollars per share) | $ / shares		$ 17.71	$ 17.71
Market Condition
Share-Based Compensation
Vesting period	60 days
Estimated
Assumptions used
Number of companies (in companies) | company			6
Expected volatility rate, minimum (as a percent)			55.10%
Expected volatility rate, maximum (as a percent)			89.00%

Equity and Share-Based Compen_9

Equity and Share-Based Compensation - Chief Executive Officer Restricted Stock Units and Performance Stock Units Issued to Certain Members of Executive Management Containing a Market Condition (Details) - USD ($) $ / shares in Units, $ in Thousands	Mar. 01, 2018	Nov. 01, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Assumptions used
Share-based compensation, net of amounts capitalized to oil and gas properties			$ 2,909	$ 5,407	$ 9,196
Stock based compensation expense			3,546	6,297	11,191
Capitalized qualifying share-based compensation expense			$ 637	890	1,995
CEO | RSU with market condition
Share-Based Compensation
Vesting percent Actual TSR (in percent)		50.00%
Vesting percent Relative TSR (in percent)		50.00%
Days considered for calculation of average stock price		20 days
Assumptions used
Risk-free interest rate (as a percent)		1.74%
Expected volatility rate, minimum (as a percent)		41.00%
Expected volatility rate, maximum (as a percent)		130.00%
Calculated fair value		$ 10.92
Service period (in years)		3 years
Stock based compensation expense				493	$ 83
Unrecognized expense for share-based compensation				$ 900
Weighted-average period for over which unrecognized expense will be recognized				1 year 9 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested shares outstanding at the beginning of the period (in shares)				135,778
Non-vested shares outstanding at the end of the period (in shares)				135,778	135,778
Weighted Average Grant Date Fair Value
Non-vested shares outstanding at the beginning of the period (in dollars per share)				$ 10.92
Non-vested shares outstanding at the end of the period (in dollars per share)				$ 10.92	$ 10.92
CEO | RSU with market condition | 25% or greater CAGR
Share-Based Compensation
Vesting (in percent)		120.00%
CEO | RSU with market condition | 20% or greater CAGR
Share-Based Compensation
Vesting (in percent)		100.00%
CEO | RSU with market condition | 15% or greater CAGR
Share-Based Compensation
Vesting (in percent)		50.00%
CEO | RSU with market condition | Less than 15% CAGR
Share-Based Compensation
Vesting (in percent)		0.00%
CEO | RSU with market condition | Top 5% or better Relative TSR to Peer Group
Share-Based Compensation
Vesting (in percent)		120.00%
CEO | RSU with market condition | Top 33.5% or Better Relative TSR To Peer Group
Share-Based Compensation
Vesting (in percent)		100.00%
CEO | RSU with market condition | Top 50% or better Relative TSR to Peer Group
Share-Based Compensation
Vesting (in percent)		50.00%
CEO | RSU with market condition | Less than 50% of Relative TSR to Peer Group
Share-Based Compensation
Vesting (in percent)		0.00%
Executive Management | Performance stock units
Assumptions used
Risk-free interest rate (as a percent)	2.34%
Expected volatility rate, minimum (as a percent)	40.00%
Expected volatility rate, maximum (as a percent)	127.20%
Service period (in years)	3 years
Share-based compensation, net of amounts capitalized to oil and gas properties				$ 300
Stock based compensation expense				379
Capitalized qualifying share-based compensation expense				100
Unrecognized expense for share-based compensation				$ 900
Weighted-average period for over which unrecognized expense will be recognized				2 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted (in shares)	96,305			96,305
Non-vested shares outstanding at the end of the period (in shares)				96,305
Weighted Average Grant Date Fair Value
Granted (in dollars per share)				$ 13.34
Non-vested shares outstanding at the end of the period (in dollars per share)				$ 13.34
Executive Management | Performance stock units | Maximum
Share-Based Compensation
Vesting (in percent)	150.00%
Executive Management | Performance stock units | Minimum
Share-Based Compensation
Vesting (in percent)	100.00%
Executive Management | Performance stock units | Top 35% or better Relative TSR to Peer Group
Share-Based Compensation
Vesting (in percent)	150.00%
Executive Management | Performance stock units | Top 50% or better Relative TSR to Peer Group
Share-Based Compensation
Vesting (in percent)	100.00%
Executive Management | Performance stock units | Top 60% or better Relative TSR to Peer Group
Share-Based Compensation
Vesting (in percent)	50.00%
Executive Management | Performance stock units | Less than 60% of Relative TSR to Peer Group
Share-Based Compensation
Vesting (in percent)	0.00%

Equity and Share-Based Compe_10

Equity and Share-Based Compensation - Unrestricted Common Share Awards (Details) - USD ($) $ in Thousands	Nov. 08, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Share-Based Compensation
Stock based compensation expense		$ 3,546	$ 6,297	$ 11,191
Common Stock | Director
Share-Based Compensation
Granted (in shares)	12,400
Stock based compensation expense		$ 244
Unrecognized expense for share-based compensation			$ 0	$ 0

Equity and Share-Based Compe_11

Equity and Share-Based Compensation - Stock-Based Compensation Expense Summary (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2018	Dec. 31, 2017
Stock-Based Compensation Expense Summary
Total stock-based compensation	$ 3,546		$ 6,297	$ 11,191
Less: amounts capitalized to oil and natural gas properties	(637)		(890)	(1,995)
Net stock-based compensation	2,909		5,407	9,196
Restricted Stock Units
Stock-Based Compensation Expense Summary
Total stock-based compensation	2,114		5,207	7,083
Less: amounts capitalized to oil and natural gas properties	(400)		(700)	(1,300)
Net stock-based compensation	1,700		4,500	5,800
Stock options
Stock-Based Compensation Expense Summary
Total stock-based compensation	1,046		1,078	3,289
Less: amounts capitalized to oil and natural gas properties	(200)		(200)	(700)
Net stock-based compensation	800		900	2,600
RSU with market condition | Director
Stock-Based Compensation Expense Summary
Total stock-based compensation	142			736
Total stock-based compensation			(860)
RSU with market condition | CEO
Stock-Based Compensation Expense Summary
Total stock-based compensation			493	$ 83
Performance stock units | Executive Management
Stock-Based Compensation Expense Summary
Total stock-based compensation			379
Less: amounts capitalized to oil and natural gas properties			(100)
Net stock-based compensation			$ 300
Common Stock | Director
Stock-Based Compensation Expense Summary
Total stock-based compensation	$ 244
Predecessor
Stock-Based Compensation Expense Summary
Total stock-based compensation		$ 3,040
Less: amounts capitalized to oil and natural gas properties		(476)
Net stock-based compensation		2,564
Predecessor | Restricted Stock Units
Stock-Based Compensation Expense Summary
Total stock-based compensation		3,040
Less: amounts capitalized to oil and natural gas properties		(500)
Net stock-based compensation		$ 2,600

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2018	Dec. 31, 2017
Income Taxes
Estimated deductions				$ 10,900
Change to income tax previously reported			$ 0
Future income tax payments			0
Reconciliation of income tax expense
Income (loss) before taxes	$ 9,930		$ 49,784	$ (85,077)
Statutory rate	35.00%		21.00%	35.00%
Income tax provision (benefit) computed at statutory rate	$ 3,475		$ 10,455	$ (29,777)
Reconciling items:
State income taxes, net of federal benefit	296		2,157	(2,864)
Change in valuation allowance	(3,876)		(10,515)	(40,700)
Adjustment to deferred tax assets and liabilities for enacted change in federal tax rate				73,182
Parking expenses			35
Change in state rate	(1)		28	(606)
Deferred tax true-ups	74		(1,520)	(140)
Other, net	$ 32		(640)	905
Deferred tax assets
Federal tax loss carryforwards			60,874	36,429
Derivative instruments and other				813
State tax loss carryforwards			13,087	7,195
Employee benefit plans			3,086	3,053
Oil and gas properties and equipment			33,186	72,568
Disallowed interest expense			1,231
Other			33	33
Less valuation allowance			(109,574)	$ (120,091)
Total deferred tax assets			1,923
Deferred tax liabilities
Derivative instruments and other			(1,923)
Total deferred tax liabilities			$ (1,923)
Predecessor
Reconciliation of income tax expense
Income (loss) before taxes		$ 1,323,079
Statutory rate		35.00%
Income tax provision (benefit) computed at statutory rate		$ 463,078
Reconciling items:
State income taxes, net of federal benefit		39,424
Change in valuation allowance		(528,706)
Change in state rate		(153)
Bankruptcy items		12,262
Deferred tax true-ups		9,891
Other, net		$ 4,204

Income (Loss) Per Share (Detail

Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	2 Months Ended	3 Months Ended								10 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Oct. 20, 2016	Dec. 31, 2018	Dec. 31, 2017
Income (Loss) Per Share
Net income (loss)	$ 9,930	$ 35,806	$ 11,516	$ (1,542)	$ 4,004	$ (120,967)	$ 3,663	$ 13,742	$ 18,485		$ 49,784	$ (85,077)
Participating securities-non-vested restricted stock	(280)										(1,394)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 9,650	$ 34,862	$ 11,165	$ (1,542)	$ 3,905	$ (120,967)	$ 3,581	$ 13,382	$ 17,939		$ 48,390	$ (85,077)
Common shares outstanding - basic	25,009,000										25,337,000	25,119,000
Common shares outstanding - diluted	25,009,000										25,337,000	25,119,000
Basic (in dollars per share)	$ 0.39										$ 1.91	$ (3.39)
Diluted (in dollars per share)	$ 0.39										$ 1.91	$ (3.39)
Shares of common stock to be issued by required Plan											9,407	17,533
Basic and diluted weighted average number of common shares outstanding	25,009,000	25,385,000	25,332,000	25,332,000	25,299,000	25,253,000	25,116,000	25,093,000	25,012,000		25,337,000	25,119,000
Basic and diluted net income (loss) per share attributable to common shareholders	$ 0.39	$ 1.38	$ 0.44	$ (0.06)	$ 0.15	$ (4.78)	$ 0.14	$ 0.53	$ 0.72		$ 1.91	$ (3.39)
Directors shares for calculation of earnings per share											39,335	40,054
Stock options
Income (Loss) Per Share
Antidilutive securities (in shares)	627,000										206,000	466,000
Warrants
Income (Loss) Per Share
Antidilutive securities (in shares)	6,626,000										6,626,000	6,626,000
Predecessor
Income (Loss) Per Share
Net income (loss)										$ 1,323,079
Net income (loss) attributable to shareholders										1,323,079
Participating securities-non-vested restricted stock										(16,522)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS										$ 1,306,557
Basic and diluted weighted average number of common shares outstanding										10,645,000
Basic and diluted net income (loss) per share attributable to common shareholders										$ 122.74

Concentrations of Credit Risk (

Concentrations of Credit Risk (Details) - Customer concentration	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2018	Dec. 31, 2017
Revenue | Purchaser one
Concentrations of Credit Risk
Concentration risk (as a percent)	40.00%		35.00%	37.00%
Revenue | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)	29.00%		32.00%	25.00%
Revenue | Purchaser three
Concentrations of Credit Risk
Concentration risk (as a percent)			23.00%	14.00%
Accounts receivable | Purchaser one
Concentrations of Credit Risk
Concentration risk (as a percent)			71.00%	42.00%
Accounts receivable | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)			26.00%	35.00%
Accounts receivable | Purchaser three
Concentrations of Credit Risk
Concentration risk (as a percent)				10.00%
Predecessor | Revenue | Purchaser one
Concentrations of Credit Risk
Concentration risk (as a percent)		46.00%
Predecessor | Revenue | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)		29.00%

Commitments and Contingencies_2

Commitments and Contingencies (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2018	Dec. 31, 2017
Net minimum commitments
2019			$ 665
2020			678
2021			690
2022			702
2023 and beyond			2,600
Total			5,335
Office rent	$ 100		600	$ 600
Loss contingency accrual			1,100	1,100
Insurance reimbursement claim				$ 1,900
Non-cancellable office lease commitments
Net minimum commitments
2019			665
2020			678
2021			690
2022			702
2023 and beyond			2,600
Total			$ 5,335
Predecessor
Net minimum commitments
Office rent		$ 4,300

Supplemental Information to C_3

Supplemental Information to Consolidated Statement of Cash Flows (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2018	Dec. 31, 2017
SUPPLEMENTAL INFORMATION:
Non-cash investment in property and equipment	$ 8,135		$ 6,092	$ 17,164
Cash paid for interest, net of capitalized interest for the year ended December 31, 2018, December 31, 2017, and the Successor Period of $0.5 million, $2.4 million and $0.7 million, respectively (no capitalized interest for the Predecessor Period)	426		4,128	5,353
Capitalized interest	$ 700		$ 500	$ 2,400
Predecessor
SUPPLEMENTAL INFORMATION:
Non-cash investment in property and equipment		$ 12,995
Cash paid for interest, net of capitalized interest for the year ended December 31, 2018, December 31, 2017, and the Successor Period of $0.5 million, $2.4 million and $0.7 million, respectively (no capitalized interest for the Predecessor Period)		6,709
Cash paid for reorganization items		36,325
Capitalized interest		0
Predecessor | 2020 Senior Notes
SUPPLEMENTAL INFORMATION:
Non-cash exchange of common equity and warrants of the reorganized Company for notes		312,039
Predecessor | 2021 Senior Notes
SUPPLEMENTAL INFORMATION:
Non-cash exchange of common equity and warrants of the reorganized Company for notes		361,050
Predecessor | Second lien notes
SUPPLEMENTAL INFORMATION:
Non-cash exchange of common equity and warrants of the reorganized Company for notes		591,042
Predecessor | Third lien notes
SUPPLEMENTAL INFORMATION:
Non-cash exchange of common equity and warrants of the reorganized Company for notes		$ 556,136

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	10 Months Ended	12 Months Ended
	Oct. 20, 2016	Dec. 31, 2017
EcoStim
Related Party Transactions
Amount paid, related party		$ 11.6
Accounts payable, related party		$ 2.1
Dixie Electric | Predecessor
Related Party Transactions
Amount paid, related party	$ 1.7

Subsequent Event (Details)

Subsequent Event (Details) $ / shares in Units, $ in Thousands	Feb. 14, 2019USD ($)$ / sharesshares	Jan. 30, 2019USD ($)	Jan. 14, 2019$ / sharesshares	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Oct. 21, 2016$ / sharesshares
Subsequent Event
Drawn from facility | $				$ 1,000
Exit Facility
Subsequent Event
Drawn from facility | $				$ 23,100	$ 128,100
Warrants | Unsecured Note
Subsequent Event
Exercise price (in dollars per share) | $ / shares						$ 46
Warrants to acquire common stock shares (in shares)						2,213,789
Warrants | Third lien notes
Subsequent Event
Exercise price (in dollars per share) | $ / shares						$ 24
Warrants to acquire common stock shares (in shares)						4,411,765
Subsequent Event
Subsequent Event
Severance costs | $		$ 1,200
Subsequent Event | Exit Facility
Subsequent Event
Drawn from facility | $	$ 39,000
Subsequent Event | Common Stock
Subsequent Event
Stock repurchase (in shares)			5,000,000
Purchase price per share (in dollars per share) | $ / shares	$ 10		$ 10
Shares repurchased (in shares)	5,000,000
Subsequent Event | Warrants
Subsequent Event
Shares eligible to receive upon exercise of each warrant, Adjustment factor	1.05
Subsequent Event | Warrants | Unsecured Note
Subsequent Event
Exercise price (in dollars per share) | $ / shares	$ 43.67
Subsequent Event | Warrants | Unsecured Note | Maximum
Subsequent Event
Warrants to acquire common stock shares (in shares)	2,332,089
Subsequent Event | Warrants | Third lien notes
Subsequent Event
Exercise price (in dollars per share) | $ / shares	$ 22.78
Subsequent Event | Warrants | Third lien notes | Maximum
Subsequent Event
Warrants to acquire common stock shares (in shares)	4,647,520

Supplemental Oil and Gas Disc_3

Supplemental Oil and Gas Disclosures (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2018	Dec. 31, 2017
Acquisition costs:
Unproved properties	$ 1,430		$ 6,711	$ 11,964
Development costs	17,708		93,965	128,424
Total costs incurred	19,138		100,676	140,388
General and administrative expense
Acquisition costs:
Development costs	1,400		2,800	5,300
Capitalized interest expenses
Acquisition costs:
Development costs	$ 700		$ 500	$ 2,400
Predecessor
Acquisition costs:
Unproved properties		$ 6,869
Development costs		121,668
Total costs incurred		128,537
Predecessor | General and administrative expense
Acquisition costs:
Development costs		$ 3,400

Supplemental Oil and Gas Disc_4

Supplemental Oil and Gas Disclosures (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Capitalized Costs, Net
Proved properties	$ 809,272	$ 765,308
Unproved properties not being amortized	4,050	7,065
Gross capitalized costs	813,322	772,373
Less: Accumulated depreciation, depletion, amortization and impairment	(261,705)	(201,722)
Net capitalized costs	551,617	$ 570,651
Mississippian Lime
Capitalized Costs, Net
Unproved properties not being amortized	$ 4,100
Maximum period considered for depletion (in years)	5 years

Supplemental Oil and Gas Disc_5

Supplemental Oil and Gas Disclosures (Unaudited) - Estimated Quantities of Proved Oil and Natural Gas Reserves (Details)	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016MBoeMMcfMBbls	Oct. 20, 2016MBoeMMcfMBbls	Dec. 31, 2018MBoeMMcfMBbls	Dec. 31, 2017MBoeMMcfMBbls	Dec. 31, 2015BoeMBoeMMcfMBbls
Proved Reserves, Total
Beginning Balance | MBoe			108,947	176,988
Revision of previous estimates	55,172		(39,127)	(76,350)	(75,700)
Extensions, discoveries and other additions | MBoe	58,296		17,979	18,464
Sales of reserves in place | MBoe			(8,714)	(2,071)
Production | MBoe	(1,798)		(6,663)	(8,084)
Net proved reserves | MBoe	176,988		72,422	108,947
Proved developed reserves | MBoe	69,622		48,962	64,490
Proved undeveloped reserves | MBoe	107,366		23,460	44,457
Oil
Proved Reserves
Beginning Balance			31,134	61,390
Revision of previous estimates	19,137		(13,765)	(33,608)
Extensions, discoveries and other additions	22,571		5,454	5,819
Sales of reserves in place			(2,838)	(99)
Production	(544)		(1,920)	(2,368)
Net proved reserves	61,390		18,065	31,134
Proved developed reserves	19,698		10,995	17,268
Proved undeveloped reserves	41,692		7,070	13,866
Natural gas liquid
Proved Reserves
Beginning Balance			25,193	36,872
Revision of previous estimates	11,421		(6,347)	(13,010)
Extensions, discoveries and other additions	11,186		4,462	4,003
Sales of reserves in place			(2,414)	(723)
Production	(429)		(1,623)	(1,949)
Net proved reserves	36,872		19,271	25,193
Proved developed reserves	16,349		13,425	15,464
Proved undeveloped reserves	20,523		5,846	9,729
Natural gas
Proved Reserves
Beginning Balance | MMcf			315,719	472,359
Revision of previous estimates | MMcf	147,688		(114,092)	(178,388)
Extensions, discoveries and other additions | MMcf	147,236		48,382	51,849
Sales of reserves in place | MMcf			(20,778)	(7,495)
Production | MMcf	(4,948)		(18,718)	(22,606)
Net proved reserves | MMcf	472,359		210,513	315,719
Proved developed reserves | MMcf	201,454		147,248	190,550
Proved undeveloped reserves | MMcf	270,905		63,265	125,169
Predecessor
Proved Reserves, Total
Beginning Balance | MBoe	65,318	73,540
Revision of previous estimates | MBoe		(3,706)
Extensions, discoveries and other additions | MBoe		4,249
Production | MBoe		(8,765)
Net proved reserves | MBoe		65,318			73,540
Proved developed reserves | MBoe		65,318
Predecessor | Oil
Proved Reserves
Beginning Balance	20,226	24,713
Revision of previous estimates		(3,089)
Extensions, discoveries and other additions		1,566
Production		(2,964)
Net proved reserves		20,226			24,713
Proved developed reserves		20,226
Predecessor | Natural gas liquid
Proved Reserves
Beginning Balance	14,694	16,245
Revision of previous estimates		(459)
Extensions, discoveries and other additions		840
Production		(1,932)
Net proved reserves		14,694			16,245
Proved developed reserves		14,694
Predecessor | Natural gas
Proved Reserves
Beginning Balance | MMcf	182,383	195,492
Revision of previous estimates | MMcf		(946)
Extensions, discoveries and other additions | MMcf		11,052
Production | MMcf		(23,215)
Net proved reserves | MMcf		182,383			195,492
Proved developed reserves | MMcf		182,383

Supplemental Oil and Gas Disc_6

Supplemental Oil and Gas Disclosures (Unaudited) - Revision of Previous Estimates, Extensions, Discoveries and Other Additions and Sales of Reserves in Place (Details) $ in Millions	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016MBoelocation	Oct. 20, 2016MBoe	Dec. 31, 2018MBoe	Dec. 31, 2017MBoelocation	Dec. 31, 2015USD ($)BoeMMBTU
Estimated Quantities of Proved Oil and Natural Gas Reserves
Revision of previous estimates	55,172		(39,127)	(76,350)	(75,700)
Extensions, discoveries and other additions	58,296		17,979	18,464
Undeveloped property locations (in locations) | location	274			139
Sales of reserves in place			8,714	2,071
Mississippian Lime
Estimated Quantities of Proved Oil and Natural Gas Reserves
Revision of Previous Estimates, percentage of reductions due to transfer of proved undeveloped reserves					98.00%
Transfer of proved undeveloped reserves (in MBoe) | MMBTU					77,362
Amount of transfer of proved undeveloped reserves | $					$ 179
Predecessor
Estimated Quantities of Proved Oil and Natural Gas Reserves
Revision of previous estimates		(3,706)
Extensions, discoveries and other additions		4,249

Supplemental Oil and Gas Disc_7

Supplemental Oil and Gas Disclosures (Unaudited) - Benchmark Prices Used to Determine Estimated Proved Reserves (Details)	Dec. 31, 2018$ / bbl$ / MMBTU	Dec. 31, 2017$ / bbl$ / MMBTU	Dec. 31, 2016$ / bbl$ / MMBTU
Oil
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
Benchmark price (per barrel & btu) | $ / bbl	65.56	51.34	42.75
Natural gas
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
Benchmark price (per barrel & btu) | $ / MMBTU	3.10	2.98	2.48

Supplemental Oil and Gas Disc_8

Supplemental Oil and Gas Disclosures (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows from Projected Production (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Oct. 20, 2016
Standardized measure of discounted future net cash flows
Future cash inflows	$ 2,131,791	$ 3,023,929	$ 4,186,389
Future production costs	(695,677)	(1,536,332)	(2,078,640)
Future development costs	(159,400)	(370,972)	(692,533)
Future income tax expense	(52,778)	(16,289)	(106,563)
Future net cash flows	1,223,936	1,100,336	1,308,653
10% annual discount for estimated timing of cash flows	(657,660)	(551,093)	(778,703)
Standardized measure of discounted future net cash flows	$ 566,276	$ 549,243	$ 529,950	$ 349,905

Supplemental Oil and Gas Disc_9

Supplemental Oil and Gas Disclosures (Unaudited) - Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2018	Dec. 31, 2017
Changes in Standardized Measure of Discounted Future Net Cash Flows
Standardized measure, beginning of period	$ 349,905		$ 549,243	$ 529,950
Net changes in prices and production costs	78,103		182,133	173,991
Net changes in future development costs	2,022		(639)	(29,711)
Sales of oil and natural gas, net	(27,292)		(134,681)	(148,746)
Extensions	102,087		134,496	92,776
Divestiture of reserves			(52,952)	(8,079)
Revisions of previous quantity estimates	102,623		(162,513)	(152,517)
Previously estimated development costs incurred			28,443	7,909
Accretion of discount	5,832		55,813	57,816
Net change in income taxes	(48,206)		(4,483)	39,316
Changes in timing, other	(35,124)		(28,584)	(13,462)
Standardized measure, end of period	529,950	$ 349,905	$ 566,276	$ 549,243
Predecessor
Changes in Standardized Measure of Discounted Future Net Cash Flows
Standardized measure, beginning of period	$ 349,905	512,819
Net changes in prices and production costs		(113,313)
Net changes in future development costs		175
Sales of oil and natural gas, net		(116,043)
Extensions		29,871
Revisions of previous quantity estimates		(22,194)
Previously estimated development costs incurred		29,975
Accretion of discount		42,735
Changes in timing, other		(14,120)
Standardized measure, end of period		$ 349,905

Selected Quarterly Financial _3

Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	2 Months Ended	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Selected Quarterly Financial Data
Revenues, Total	$ 48,525	$ 69,643	$ 47,765	$ 42,324	$ 48,905	$ 53,344	$ 49,715	$ 60,679	$ 65,015	$ 208,637	$ 228,753
Operating income (loss)	10,673	36,514	12,170	(245)	5,812	(119,238)	5,312	14,970	19,462	54,251	(79,494)
Net income (loss)	9,930	35,806	11,516	(1,542)	4,004	(120,967)	3,663	13,742	18,485	49,784	(85,077)
Net income (loss) available to common shareholders	$ 9,650	$ 34,862	$ 11,165	$ (1,542)	$ 3,905	$ (120,967)	$ 3,581	$ 13,382	$ 17,939	$ 48,390	$ (85,077)
Net income (loss) per share
Basic and diluted net income (loss) per share	$ 0.39	$ 1.38	$ 0.44	$ (0.06)	$ 0.15	$ (4.78)	$ 0.14	$ 0.53	$ 0.72	$ 1.91	$ (3.39)
Shares used in computation
Basic and diluted weighted average number of common shares outstanding	25,009	25,385	25,332	25,332	25,299	25,253	25,116	25,093	25,012	25,337	25,119