Amplify Energy (AMPY) 10-K 14 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Mar. 08, 2018	Jun. 30, 2017
Document and Entity Information
Entity Registrant Name	Midstates Petroleum Company, Inc.
Entity Central Index Key	1,533,924
Document Type	10-K
Document Period End Date	Dec. 31, 2017
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			$ 146.8
Entity Common Stock, Shares Outstanding		25,153,381
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
CURRENT ASSETS:
Cash and cash equivalents	$ 68,498	$ 76,838
Accounts receivable:
Oil and gas sales	32,455	36,988
Joint interest billing	3,297	4,281
Other	166	2,456
Commodity derivative contracts	762
Other current assets	1,510	3,326
Total current assets	106,688	123,889
Oil and gas properties, on the basis of full cost accounting
Proved properties	765,308	573,150
Unproved properties not being amortized	7,065	65,080
Other property and equipment	6,508	6,339
Less accumulated depreciation, depletion, amortization and impairment	(204,419)	(12,974)
Net property and equipment	574,462	631,595
OTHER NONCURRENT ASSETS	6,978	5,455
TOTAL	688,128	760,939
CURRENT LIABILITIES:
Accounts payable	11,547	2,521
Accrued liabilities	42,842	53,731
Commodity derivative contracts	3,433
Total current liabilities	57,822	56,252
LONG-TERM LIABILITIES:
Asset retirement obligations	15,506	14,200
Commodity derivative contracts	562
Long-term debt	128,059	128,059
Other long-term liabilities	592	614
Total long-term liabilities	144,719	142,873
COMMITMENTS AND CONTINGENCIES (Note 16)
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value, 50,000,000 shares authorized; no shares issued or outstanding at December 31, 2017
Warrants, 6,625,554 warrants outstanding at December 31, 2017 and 2016	37,329	37,329
Common stock, $0.01 par value, 250,000,000 shares authorized; 25,272,969 shares issued and 25,173,346 shares outstanding at December 31, 2017; and 24,994,867 shares issued and outstanding at December 31, 2016	253	250
Treasury stock	(1,603)
Additional paid-in-capital	524,755	514,305
Retained earnings (deficit)	(75,147)	9,930
Total stockholders' equity	485,587	561,814
TOTAL	$ 688,128	$ 760,939

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Preferred stock, par value (in dollars per share)	$ 0.01
Preferred stock, shares authorized	50,000,000
Preferred stock, shares issued	0
Preferred stock, shares outstanding	0
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	25,272,969	24,994,867
Common stock, shares outstanding	25,173,346	24,994,867
Warrants outstanding	6,625,554	6,625,554

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, 2017	Dec. 31, 2015
REVENUES :
Oil sales	$ 25,549		$ 117,083
Natural gas liquid sales	8,391		44,112
Natural gas sales	13,635		59,708
Gains on commodity derivative contracts - net			3,659
Other	950		4,191
Total revenues	48,525		228,753
EXPENSES :
Lease operating and workover	15,324		63,287
Gathering and transportation	3,194		14,507
Severance and other taxes	1,286		8,869
Asset retirement accretion	210		1,100
Depreciation, depletion, and amortization	12,974		65,832
Impairment in carrying value of oil and gas properties			125,300
General and administrative	4,864		29,352
Total expenses	37,852		308,247
OPERATING INCOME (LOSS)	10,673		(79,494)
OTHER INCOME (EXPENSE):
Interest income			9
Interest expense-net of amounts capitalized (Predecessor Period excludes interest expense of $89.5 million on senior and secured notes)	(743)		(5,592)
Total other income (expense)	(743)		(5,583)
INCOME (LOSS) BEFORE TAXES	9,930		(85,077)
NET INCOME (LOSS)	9,930		(85,077)
Participating securities-non-vested restricted stock	(280)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 9,650		$ (85,077)
Basic and diluted net income (loss) per share attributable to common shareholders	$ 0.39		$ (3.39)
Basic and diluted weighted average number of common shares outstanding (Note 14)	25,009		25,119
Predecessor
REVENUES :
Oil sales		$ 112,628		$ 217,636
Natural gas liquid sales		27,473		38,249
Natural gas sales		48,318		66,823
Gains on commodity derivative contracts - net				40,960
Other		4,809		1,477
Total revenues		193,228		365,145
EXPENSES :
Lease operating and workover		52,803		81,473
Gathering and transportation		14,362		15,546
Severance and other taxes		5,210		8,605
Asset retirement accretion		1,414		1,610
Depreciation, depletion, and amortization		62,302		198,643
Impairment in carrying value of oil and gas properties		232,108		1,625,776
General and administrative		22,362		38,703
Acquisition and transaction costs				330
Debt restructuring costs and advisory fees		7,590		36,141
Other				2,121
Total expenses		398,151		2,008,948
OPERATING INCOME (LOSS)		(204,923)		(1,643,803)
OTHER INCOME (EXPENSE):
Interest income		81		115
Interest expense-net of amounts capitalized (Predecessor Period excludes interest expense of $89.5 million on senior and secured notes)		(66,360)		(163,148)
Reorganization items, net (Note 3)		1,594,281
Total other income (expense)		1,528,002		(163,033)
INCOME (LOSS) BEFORE TAXES		1,323,079		(1,806,836)
Income tax benefit				9,641
NET INCOME (LOSS)		1,323,079		(1,797,195)
Preferred stock dividend				(948)
Participating securities-non-vested restricted stock		(16,522)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		$ 1,306,557		$ (1,798,143)
Basic and diluted net income (loss) per share attributable to common shareholders		$ 122.74		$ (232.74)
Basic and diluted weighted average number of common shares outstanding (Note 14)		10,645		7,726

CONSOLIDATED STATEMENTS OF OPE5

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	1 Months Ended	9 Months Ended	12 Months Ended
	Oct. 20, 2016	Sep. 30, 2016	Dec. 31, 2015
Predecessor
OTHER INCOME (EXPENSE):
Interest expense on senior and secured notes	$ 89.5	$ 89.5	$ 89.5

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT) - USD ($) $ in Thousands	Series A Preferred Stock	Common Stock	Warrants	Treasury Stock	Additional Paid-in-Capital	Retained Earnings (Deficit)	Total
Balance (Predecessor) at Dec. 31, 2014	$ 3	$ 70		$ (2,592)	$ 882,528	$ (414,147)	$ 465,862
Increase (Decrease) in Stockholders' Equity
Share-based compensation | Predecessor		3			5,753		5,756
Acquisition of treasury stock | Predecessor				(489)			(489)
Net income (loss) | Predecessor						(1,797,195)	(1,797,195)
Conversion of preferred shares | Predecessor	$ (3)	37			(34)
Balance (Predecessor) at Dec. 31, 2015		110		(3,081)	888,247	(2,211,342)	(1,326,066)
Increase (Decrease) in Stockholders' Equity
Share-based compensation | Predecessor		(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 (Predecessor) at Oct. 21, 2016							(1,543,897)
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
Issuance of successor common stock		3					3
Share-based compensation					3,400		3,400
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		3			10,450		10,453
Acquisition of treasury stock				(1,603)			(1,603)
Net income (loss)						(85,077)	(85,077)
Balance at Dec. 31, 2017		$ 253	$ 37,329	$ (1,603)	$ 524,755	$ (75,147)	$ 485,587

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, 2017	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 9,930		$ (85,077)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Gains on commodity derivative contracts-net			(3,659)
Net cash received for commodity derivative contracts not designated as hedging instruments			6,891
Asset retirement accretion	210		1,100
Depreciation, depletion, and amortization	12,974		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		9,196
Amortization of deferred financing costs	63		385
Change in operating assets and liabilities:
Accounts receivable - oil and gas sales	(115)		2,766
Accounts receivable - JIB and other	(1,812)		3,362
Other current and noncurrent assets	1,783		283
Accounts payable	(1,555)		2,961
Accrued liabilities	(740)		(8,973)
Other	(3)		(765)
Net cash provided by operating activities	23,644		119,602
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(23,346)		(130,199)
Proceeds from the sale of oil and gas properties			4,235
Net cash used in investing activities	(23,346)		(125,964)
CASH FLOWS FROM FINANCING ACTIVITIES:
Deferred financing costs			(375)
Repurchase of restricted stock for tax withholdings			(1,603)
Net cash (used in) provided by financing activities			(1,978)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	298		(8,340)
Cash and cash equivalents, beginning of period	76,540		76,838
Cash and cash equivalents, end of period	76,838	$ 76,540	$ 68,498
Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		1,323,079		$ (1,797,195)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Gains on commodity derivative contracts-net				(40,960)
Net cash received for commodity derivative contracts not designated as hedging instruments				167,669
Asset retirement accretion		1,414		1,610
Depreciation, depletion, and amortization		62,302		198,643
Impairment in carrying value of oil and gas properties		232,108		1,625,776
Share-based compensation, net of amounts capitalized to oil and gas properties		2,564		4,408
Deferred income taxes				(9,641)
Amortization of deferred financing costs		4,587		11,316
Paid-in-kind interest expense		3,531		6,415
Amortization of deferred gain on debt restructuring		(8,246)		(14,948)
Operating lease abandonment		1,574
Non-cash reorganization items		(1,630,873)
Transaction costs for debt restructuring				34,398
Change in operating assets and liabilities:
Accounts receivable - oil and gas sales		(2,391)		26,437
Accounts receivable - JIB and other		22,002		22,833
Other current and noncurrent assets		(5,868)		590
Accounts payable		1,797		(4,176)
Accrued liabilities		55,160		(20,887)
Other		(743)		1,095
Net cash provided by operating activities		61,997		213,383
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment		(133,307)		(336,922)
Proceeds from the sale of oil and gas properties				42,366
Net cash used in investing activities		(133,307)		(294,556)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings				625,000
Proceeds from revolving credit facility		249,384		33,000
Repayment of long-term borrowings		(60,000)
Repayment of revolving credit facility		(121,324)		(468,150)
Deferred financing costs		(1,250)		(4,254)
Transaction costs for debt restructuring				(34,398)
Repurchase of restricted stock for tax withholdings		(53)		(489)
Net cash (used in) provided by financing activities		66,757		150,709
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(4,553)		69,536
Cash and cash equivalents, beginning of period	$ 76,540	81,093		11,557
Cash and cash equivalents, end of period		$ 76,540		$ 81,093

Organization and Business

Organization and Business	12 Months Ended
	Dec. 31, 2017
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 and Texas. 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 April 21, 2015, the Company closed the sale of all of its ownership interest in its Dequincy assets, which constituted its remaining producing and proved reserve properties in Louisiana (the “Dequincy Divestiture”) to Pintail Oil and Gas LLC. The net proceeds, inclusive of amounts placed in escrow, were approximately $42.4 million. With the completion of the Dequincy Divestiture, the Company no longer has any operations in the Louisiana/Gulf Coast area. 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”.

Emergence from Voluntary Reorga

Emergence from Voluntary Reorganization under Chapter 11 Proceedings	12 Months Ended
	Dec. 31, 2017
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 revolving credit facility (“RBL”), with a $170.0 million exit facility (the “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. The Company will issue 17,533 additional common shares, with respect to general unsecured claims, pursuant to the Plan in a future distribution. 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 10. 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, 2017
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 Enterprise value $ Plus: Cash and cash equivalents Less: Fair value of debt ) Less: Fair value of warrants ) Fair value of stock on the Effective Date $ Total shares issuable under the Plan Restricted shares granted under 2016 LTIP at October 21, 2016 Total shares Per share value (1) $ (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 Risk-free interest rate (1) % % Dividend yield — — Expected life (2) Expected volatility (3) % % Strike Price $ $ Calculated fair value $ $ (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 Enterprise value $ Plus: cash and cash equivalents Plus: other working capital liabilities Plus: other long-term liabilities Reorganization value $ 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 $ $ ){a} $ — $ Accounts receivable: Oil and gas sales — — Joint interest billing — — Other — — Other current assets ){b} — Total current assets ) — PROPERTY AND EQUIPMENT: Oil and gas properties, on the basis of full-cost accounting — ){h} Other property and equipment — ){h} Less accumulated depreciation, depletion, amortization and impairment ) — {h} — Net property and equipment — OTHER NONCURRENT ASSETS {c} {a} — TOTAL $ $ ) $ $ LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT) CURRENT LIABILITIES: Accounts payable $ $ — $ — $ Accrued liabilities ){a} — Debt classified as current ){a} {d} — — Total current liabilities ) — ASSET RETIREMENT OBLIGATIONS — ){h} OTHER LONG-TERM LIABILITIES {d} — LIABILITIES SUBJECT TO COMPROMISE ){e} {a} — — COMMITMENTS AND CONTINGENCIES STOCKHOLDERS’ EQUITY/(DEFICIT): Preferred stock — — — — Warrants — {e} — Common stock - predecessor ){f} — — Common stock - successor — {f} — Treasury stock ) {f} — — Additional paid-in-capital - predecessor ){f} — — Additional paid-in-capital - successor — {f} — Retained deficit ) {g} {i} — Total stockholders’ equity/(deficit) ) TOTAL $ $ ) $ $ 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 $ Cash payment to holders of Second Lien Notes Claims Cash payment to the RBL lenders in consideration of a temporary reduction in the amount available to be drawn under the Exit Facility Payment to escrow for professional fees related to the Plan incurred through the Effective Date Debt issuance costs associated with the Exit Facility Total uses $ {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 $ Cash paid to holders of Second Lien Notes Claims ) Warrants issued to holders of Third Lien Notes Claims ) Warrants issued to holders of Unsecured Notes Claims ) Write-off of unamortized debt costs associated with RBL ) Common stock issued ) Gain on settlement $ {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 $ Common stock - predecessor Treasury stock ) Additional paid-in-capital - predecessor Net impact to Predecessor accumulated deficit $ 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 Professional fees incurred $ ) Adjustment to unamortized debt issuance costs associated with 2020 Senior Notes ) Adjustment to unamortized debt issuance costs associated with 2021 Senior Notes ) Adjustment to unamortized gain on troubled debt restructuring associated with Second Lien Notes Adjustment to unamortized gain on troubled debt restructuring associated with Third Lien Notes Gain on settlement of liabilities subject to compromise Fresh start adjustments Other reorganization items (1) Gain on reorganization items, net $ (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, 2017
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 consolidated financial statements as of and for the year ended December 31, 2015 include the results of the Dequincy Divestiture from January 1, 2015 through April 21, 2015, the date of disposition. 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. 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 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, 2017 and 2016 that exceeded the balance insured by the FDIC in the amount of $70.4 million and $78.4 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, 2017 and 2016, 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 5. Fair Value Measurements of Financial Instruments”. The fair value of the Company’s long-term debt is disclosed, see “—Note 10. 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 2015, the Company transferred the remaining unevaluated property balance consisting of $56.3 million of Mississippian unevaluated property costs, $0.2 million of Anadarko Basin unevaluated property costs and $0.1 million of Gulf Coast unevaluated property costs to the full cost pool as a result of current pricing during 2015, its anticipated drilling plans and uncertainty regarding its ability to finance its future exploration activities at that time. During the year ended December 31, 2017, the Company transferred $58.0 million of unevaluated property to the full cost pool. As discussed below under “Impairment of Oil and Gas Properties/Ceiling Test” the Company’s strategy was refined during the fourth quarter of 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 under the new proved undeveloped type curve. 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. 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 its strategy was refined to add further focus to optimizing free cash flows and keeping leverage to a minimum. As a result, in December of 2017 the Company decreased its current drilling activity from two drilling rigs to one drilling rig. Further, the five-year development plan was revised from a two-rig program to a one rig program. This change in strategy (reduced 5-year drilling activity) 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. In addition, at year end 2017 our proved undeveloped type curve was revised downward by the Company’s third-party reserves engineering firm and capital costs assumptions were revised upward, both as a result of recent drilling results. As a result of the Company’s focus on optimizing free cash flow, keeping leverage to a minimum and optimizing drilling returns, all proved undeveloped reserves included in the December 31, 2017 reserve report are focused on infill drilling in the Carmen and Dacoma areas. 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 but continue to meet the definition of a proved undeveloped location from an engineering standpoint. 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. For the year ended December 31, 2017, the Predecessor Period and the year ended December 31, 2015, the Company recorded impairments of oil and gas properties of $125.3 million, $232.1 million and $1.6 billion, respectively. During the Predecessor Period and the year ended December 31, 2015, 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. 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, 2017 and 2016, accrued liabilities consisted of the following (in thousands): December 31, 2017 December 31, 2016 Accrued oil and gas capital expenditures $ $ Accrued revenue and royalty distributions Accrued lease operating and workover expense Accrued interest Accrued taxes Compensation and benefit related accruals Other Accrued liabilities $ $ 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 9. 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 12. Equity and Share-Based Compensation”. Revenue Recognition Oil, NGLs and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has transferred and collection of the revenues is reasonably assured. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met. The Company follows the sales method of accounting for oil, NGLs and natural gas revenues, whereby revenue is recognized 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, 2017, 2016 or 2015. Beginning January 1, 2018, the FASB Accounting Standards Update (“ASU”) 2014-09 becomes effective for the Company. See “Recent Accounting Pronouncements” below for further information. 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. Costs incurred in 2015 relate to the Dequincy Divestiture. See “—Note 8. 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. We will continue to monitor guidance and update account policies and procedures as needed. See “—Note 13. Income Taxes.” 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 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 14. Income (Loss) Per Share.” Recent Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers (Topic 606) ” (“ASU 2014-09”). 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. ASU 2014-09 requires an entity to perform the following steps: Step 1—Identify the contract with a customer: A contract between two or more parties creates enforceable rights and obligations. A contract that identifies the relevant parties and has been approved by those parties, identifies the payment terms, has commercial substance and results in a probable collection of future consideration meets the definition of ASU 2014-09. Step 2—Identify the performance obligations in the contract: A performance obligation is effectively a promise in a contract with a customer to transfer goods or services to the customer. If an entity promises to transfer more than one good or service to the customer, each performance obligation is accounted for separately if such performance obligations are distinct, as defined under ASU 2014-09. Step 3—Determine the transaction price: The amount of consideration an entity expects to be entitled to as a result of performing services to a customer or transferring goods to a customer is the transaction price. The transaction price takes into account variable consideration, the existence of significant financing component, noncash consideration and the type of consideration payable to the entity. Step 4—Allocate the transaction price to the performance obligations in the contract: An entity should allocate the transaction price to each performance obligation in an amount that represents the amount of the entity expects to be entitled to for satisfying each performance obligation. Step 5—Recognize revenue when, or as, the entity satisfies a performance obligation: An entity recognizes revenue when, or as, it satisfies a performance obligation. A performance obligation can be satisfied over time or at a point in time. ASU 2014-09 provides criteria for determining the appropriate classification of each performance obligation. Throughout 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, “ Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date ” ASU No. 2016-08, “ Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations ”, ASU No. 2016-10, “Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing” , ASU No. 2016-12, “ Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients ” and ASU No. 2016-20, “ Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers ”. ASU 2014-09 and the associated amendments mentioned above will be effective for the Company beginning on January 1, 2018, including interim periods within that reporting period. The Company completed its assessment of ASU 2014-09 during the fourth quarter of 2017. The primary impact to the Company’s revenues as the result of adopting ASU 2014-09 will be the netting of certain deductions and costs, such as transportation and gathering expenses, against revenue instead of its historical practice of presenting such expenses gross. For example, revenues from oil, natural gas and NGL sales for the year ended December 31, 2017 would have been $15.8 million lower under ASU 2014-09, with an offsetting decrease to total expenses. The implementation of ASU 2014-09 will not impact the Company’s timing of revenue recognition, financial position, net income or cash flows. The Company does not anticipate a material cumulative effect adjustment on January 1, 2018 as a result of adopting ASU 2014-09. The Company also completed its evaluation of information technology and internal control changes that will be required for adoption based on the its contract review process, which primarily required the remapping of certain accounts utilized for tracking these deduction and expenses along with enhanced reviews of any new revenue contracts or modifications to existing revenue contracts. The Company will apply the modified retrospective approach upon adoption of this standard on the effective date of January 1, 2018. In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases (Topic 842)” (“ASU 2016-02”). ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. 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. 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. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company is in the initial evaluation and planning stages for ASU 2016-02. In August 2016, the FASB issued ASU 2016-15, “ Statement of Cash Flows — Classification of Certain Cash Receipts and Cash Payments” (“ASU 2016-15”). ASU 2016-15 addresses eight specific cash flow issues with the objective of reducing existing diversity of practice. The eight specific cash flow issues contained within ASU 2016-15 are debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. ASU 2016-15 is effective for the Company for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company does not believe the adoption of ASU 2016-15 will have a material impact on its cash flows. In July 2017, the FASB issued Accounting Standards Update 2017-11, “Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815)” (“ASU 2017-11”). ASU 2011-17 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“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.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	12 Months Ended
	Dec. 31, 2017
Fair Value Measurements of Financial Instruments
Fair Value Measurements of Financial Instruments	5. 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, 2017, 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. The Company did not have any open commodity derivative contract positions at December 31, 2016. 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, 2017 Significant Other Significant Quoted Prices in Active Observable Inputs Unobservable Inputs Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps $ — $ $ — $ Commodity derivative oil collars $ — $ $ — $ Commodity derivative gas collars $ — $ $ — $ Total assets $ — $ $ — $ Derivative Liabilities: Commodity derivative oil swaps $ — $ ) $ — $ ) Commodity derivative gas swaps $ — $ — $ — $ — Commodity derivative oil collars $ — $ ) $ — $ ) Commodity derivative gas collars $ — $ ) $ — $ ) Total liabilities $ — $ ) $ — $ ) At December 31, 2016, the Company did not have any open commodity derivative contract positions.

Risk Management and Derivative

Risk Management and Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Risk Management and Derivative Instruments
Risk Management and Derivative Instruments	6. 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. · Collars: A collar contains a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party. · 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 at December 31, 2017, the Company would not have experienced a loss. Commodity Derivative Contracts The Company has entered into various oil and natural gas derivative contracts that extend through December 2019, summarized as follows: NYMEX WTI Fixed Swaps Collars Three-Way Collars Hedge Weighted Hedge Weighted Weighted Hedge Weighted Weighted Weighted Quarter Ended: December 31, 2017(1)(2) $ $ $ $ $ $ March 31, 2018(1) $ — $ — $ — $ $ $ June 30, 2018(1) $ — $ — $ — $ $ $ September 30, 2018(1) $ — $ — $ — $ $ $ December 31, 2018(1) $ — $ — $ — $ $ $ March 31, 2019(1) — $ — — $ — $ — $ $ $ June 30, 2019(1) — $ — — $ — $ — $ $ $ September 30, 2019(1) — $ — — $ — $ — $ $ $ December 31, 2019(1) — $ — — $ — $ — $ $ $ NYMEX HENRY HUB Fixed Swaps Collars Three-Way Collars Hedge Weighted Hedge Weighted Weighted Hedge Weighted Weighted Weighted Quarter Ended: December 31, 2017(1) $ $ $ $ $ $ March 31, 2018(1)(3) $ — $ — $ — $ $ $ June 30, 2018(1) — $ — — $ — $ — $ $ $ September 30, 2018(1) — $ — — $ — $ — $ $ $ December 31, 2018(1) — $ — — $ — $ — $ $ $ March 31, 2019(1) — $ — — $ — $ — $ $ $ (1) Positions shown represent open commodity derivative contract positions as of December 31, 2017. The Company did not have any open commodity derivative contract positions as of December 31, 2016. (2) During the second quarter, the Company entered into long call oil trades to offset its three-way collar short calls for the second half of 2017. (3) During the second quarter, the Company entered into natural gas three-way collars with long call ceilings in order to offset its Q1 2018 natural gas fixed swaps. 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 at December 31, 2017 (in thousands): Type Balance Sheet Location (1) December 31, 2017 Gas swaps Derivative financial instruments — current assets $ Oil collars Derivative financial instruments — current assets ) Gas collars Derivative financial instruments — current assets Total derivative financial instruments — current assets $ Oil swaps Derivative financial instruments — current liabilities $ ) Oil collars Derivative financial instruments — current liabilities ) Gas collars Derivative financial instruments — current liabilities Total derivative financial instruments — current liabilities $ ) Oil collars Derivative financial instruments — noncurrent liabilities $ ) Gas collars Derivative financial instruments — noncurrent liabilities ) Total derivative financial instruments — noncurrent liabilities $ ) Total derivative fair value at period end $ ) (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. As of December 31, 2016, the Company did not have any open commodity derivative contract positions. 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 at December 31, 2017 (in thousands): December 31, 2017 Not Designated as Gross Recognized Gross Amounts Net Recognized ASC 815 Hedges Balance Sheet Location Classification Assets/Liabilities Offset Assets/Liabilities Derivative Assets: Commodity contracts Derivative financial instruments — current $ $ ) $ Commodity contracts Derivative financial instruments — noncurrent ) — $ $ ) $ Derivative Liabilities: Commodity contracts Derivative financial instruments — current $ ) $ $ ) Commodity contracts Derivative financial instruments — noncurrent ) ) $ ) $ $ ) As of December 31, 2016, the Company did not have any open commodity derivative contract positions. 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 Year For the Period For the Period For the Year 2017 December 31, 2016 October 20, 2016 2015 Net cash received for commodity derivative contracts $ $ — $ — $ Unrealized net losses ) — — ) Gains on commodity derivative contracts—net $ $ — $ — $ 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, 2017
Property and Equipment
Property and Equipment	7. Property and Equipment The Company’s property and equipment as of December 31, 2017 and 2016 was as follows (in thousands): December 31, 2017 December 31, 2016 Oil and gas properties, on the basis of full-cost accounting: Proved properties $ $ Unproved properties not being amortized Other property and equipment Less accumulated depreciation, depletion, amortization and impairment ) ) Net property and equipment $ $ For the year ended December 31, 2017, Successor Period, Predecessor Period and the year ended December 31, 2015, depletion expense related to oil and gas properties was $63.4 million, $12.6 million, $59.9 million, and $195.2 million, respectively, and $7.85, $7.00, $6.84, and $16.26 per Boe, respectively. For the year ended December 31, 2017, the Successor Period, the Predecessor Period and the year ended December 31, 2015, depreciation expense related to other property and equipment was $2.4 million, $0.4 million, $2.4 million and $3.5 million, respectively. For the year ended December 31, 2017, the Successor Period and the year ended December 31, 2015, interest capitalized to unevaluated properties was $2.4 million, $0.7 million and $4.9 million, respectively. The Company did not capitalized interest for the Predecessor Period. For the year ended December 31, 2017, the Successor Period, the Predecessor Period and the year ended December 31, 2015, the Company capitalized $5.3 million, $1.4 million, $3.4 million and $7.3 million, respectively, of internal costs to oil and gas properties, including $2.0 million, $0.6 million, $0.5 million and $1.3 million, respectively, of qualifying share-based compensation expense, see “—Note 12. Equity and Share-Based Compensation”. During the year ended December 31, 2017, the Company disposed of certain oil and gas equipment for cash proceeds of $1.4 million, which were reflected as a reduction of oil and gas properties with no gain or loss recognized. 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), subject to standard post-closing adjustments. The net proceeds from the sale were retained for general corporate purposes.

Acquisition and Divestitures of

Acquisition and Divestitures of Oil and Gas Properties	12 Months Ended
	Dec. 31, 2017
Acquisition and Divestitures of Oil and Gas Properties
Acquisition and Divestitures of Oil and Gas Properties	8. Acquisition and Divestitures of Oil and Gas Properties Dequincy Divestiture On April 21, 2015, the Company closed the Dequincy Divestiture for $44.0 million, completing the Company’s disposition of its producing properties and proved reserves in Louisiana. The net proceeds, inclusive of amounts placed in escrow, were approximately $42.4 million, which was net of customary closing adjustments. This amount was reflected as a reduction of oil and natural gas properties, with no gain or loss recognized. The net proceeds were retained for general corporate purposes. Exploration Agreement with PetroQuest On June 25, 2014, the Company entered into an exploration agreement with PetroQuest Energy LLC (“PetroQuest”) with an effective date of May 1, 2014, in which the Company conveyed to PetroQuest an undivided 50% of its right, title and interest in and to the acreage and other interests in the Fleetwood prospect area in Louisiana. With the execution of the agreement, PetroQuest paid $3.0 million in cash consideration and in January 2015, PetroQuest paid additional cash of $7.0 million. As further consideration, PetroQuest granted a credit to the Company of an additional non-interest bearing total sum of $14.0 million, to be credited or paid against the Company’s share of costs or expenses incurred to develop the prospect area, including but not limited to, all mineral lease acquisition or maintenance costs and all drilling, completion, equipping and facility costs. For any amounts not fully credited on or before December 31, 2015, the Company could elect to take the remaining portion in cash. The Company received the unutilized portion of the non-interest bearing amount of approximately $4.4 million during 2016. Acquisition and Transaction Expenses For the year ended December 31, 2015, acquisition and transaction costs of $0.3 million relate to the execution of the Dequincy Divestiture.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligations
Asset Retirement Obligations	9. 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 $15.5 million and $14.2 million as of December 31, 2017 and 2016, respectively. At December 31, 2017 and 2016, all AROs represent long-term liabilities and are classified as such. The following table details the change in the AROs for the year ended December 31, 2017 and the Successor Period, respectively (in thousands): Successor For the Year Ended For the Period October 2017 December 31, 2016 Asset retirement obligations at beginning of period $ $ Liabilities incurred Revisions — Liabilities settled ) — Liabilities eliminated through asset sale (1) ) — Current period accretion expense Asset retirement obligations at end of year $ $ (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 7. Property and Equipment”.

Debt

Debt	12 Months Ended
	Dec. 31, 2017
Debt
Debt	10. Debt Exit Facility At December 31, 2017 and 2016, the Company maintained the Exit Facility with a borrowing base of $170.0 million. At December 31, 2017 and 2016, the Company had $128.1 million drawn on the Exit Facility and had outstanding letters of credit obligations totaling $1.9 million. At December 31, 2017, the Company had $40.0 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, 2017 and 2016, the weighted average interest rate was 6.3% and 5.5%, respectively. Unamortized debt issuance costs of $1.2 million associated with the Exit Facility are included in “Other noncurrent assets” on the consolidated balance sheets at December 31, 2017 and 2016, respectively. 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. 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. On May 24, 2017, the Company entered into the First Amendment to the Exit Facility (the “First Amendment”). The First Amendment, among other items, (i) moved the first scheduled borrowing base redetermination from April 2018 to October 2017; (ii) removed the requirement to maintain a cash collateral account with the administrative agent in the amount of $40.0 million; (iii) removed the requirement to maintain at least 20% liquidity of the then effective borrowing base; (iv) amended the required mortgage threshold from 95% to 90%; (v) amended the threshold amount for which the borrower is required to provide advance notice to the administrative agent of a sale or disposition of oil and gas properties which occurs during the period between two successive redeterminations of the borrowing base; (vi) amended the required ratio of total net indebtedness to EBITDA; (vii) amended the required EBITDA to interest coverage ratio and (viii) removed certain limitations on capital expenditures. On October 27, 2017, the Company’s borrowing base was redetermined at the existing amount of $170.0 million. The Company’s Anadarko Basin assets in Texas and Oklahoma were excluded from the redetermination of the borrowing base. The Company was in compliance with all debt covenants at December 31, 2017. The Company believes the carrying amount of the Credit Facility at December 31, 2017 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. 2015 Debt Restructuring On May 21, 2015, the Company issued $625.0 million of Second Lien Notes and utilized the proceeds to repay the outstanding balance of the RBL in an amount of approximately $468.2 million, with the remainder utilized for general corporate purposes. Further, the Company exchanged approximately $504.1 million of Third Lien Notes for approximately $279.8 million of 2020 Senior Notes and $350.3 million of 2021 Senior Notes, representing an exchange at 80.0% of the exchanged Unsecured Notes’ par value. Additionally, on June 2, 2015, the Company exchanged approximately $20.0 million of Third Lien Notes for approximately $26.6 million of 2020 Senior Notes and $2.0 million of 2021 Senior Notes, representing an exchange at 70.0% of the exchanged Unsecured Notes’ par value. Approximately $63.9 million of the principal amount of 2020 Senior Notes and $70.7 million of the principal amount of 2021 Senior Notes was extinguished. The exchanges of Third Lien Notes for the Unsecured Notes as well as the issuance of the Second Lien Notes were accounted for as a troubled debt restructuring. As the future cash flows of the modified debt instruments were greater than the carrying amount of the previous debt instruments, no debt extinguishment gain was recognized. The amount of extinguished debt was to be amortized over the remaining life of the Second Lien Notes and Third Lien Notes using the effective interest method and recognized as a reduction of interest expense. All costs incurred related to the May 21, 2015 and June 2, 2015 exchanges, including restructuring costs as well as the direct issuance costs of the Second Lien Notes and Third Lien Notes, were expensed and are included within debt restructuring costs and advisory fees in the consolidated statements of operations. As a result of the Company’s emergence on the Effective Date, the remaining unamortized gain on the troubled debt restructuring was eliminated at that time. 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, 2017
Preferred Stock
Preferred Stock	11. 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 current 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, 2017
Equity and Share-Based Compensation
Equity and Share-Based Compensation	12. 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, 2017, the Company had 25,272,969 and 25,173,346 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. The Company will issue 17,533 additional common shares pursuant to the Plan in a future distribution. 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, 2015: Common Treasury Share count as of December 31, 2014 (Predecessor) ) Grants of restricted stock — Forfeitures of restricted stock ) — Acquisition of treasury stock — ) Fractional share adjustment due to reverse stock split ) — Issuance of common stock for Series A Preferred Stock conversion — Share count as of December 31, 2015 (Predecessor) ) Grants of restricted stock — — Forfeitures of restricted stock ) — Acquisition of treasury stock — ) Share count as of October 21, 2016 (Predecessor) ) Cancellation of common stock ) — Cancellation of treasury stock — Share count as of October 21, 2016 (Predecessor) — — Issuance of successor common stock — Share count as of October 21, 2016 (Successor) — Issuance of successor common stock — Acquisition of treasury stock — — Share count as of December 31, 2016 (Successor) — Issuance of successor common stock — Acquisition of treasury stock — ) Share count as of December 31, 2017 (Successor) ) (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, 2017, 2,129,011 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, 2017, the Company had 324,984 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 and RSUs issued to the Chief Executive Officer (“CEO”) containing a market condition, which are discussed below. RSUs granted to employees 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. RSUs granted to non-employee directors vest on the first to occur of (i) one-year elapses from the grant date, (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, 2017, the Successor Period, the Predecessor Period and the year ended December 31, 2015: Restricted Stock Weighted Average Non-vested shares outstanding at December 31, 2014 (Predecessor) $ Granted $ Vested ) $ Forfeited ) $ Non-vested shares outstanding at December 31, 2015 (Predecessor) $ Granted — $ — Vested ) $ Forfeited ) $ Non-vested shares outstanding at October 20, 2016 (Predecessor) $ Cancellation of non-vested shares ) $ Non-vested shares outstanding at October 20, 2016 (Predecessor) — $ — Granted at Effective Date $ Non-vested shares outstanding at October 21, 2016 (Successor) $ Granted $ Forfeited ) $ Non-vested shares outstanding at December 31, 2016 (Successor) $ Granted $ Vested(1) ) $ Forfeited ) $ Non-vested shares outstanding at December 31, 2017 (Successor) $ (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. 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. 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, 2017, the Successor Period, the Predecessor Period and the year ended December 31, 2015, was $5.8 million, $1.7 million, $2.6 million and $4.4 million, respectively. For the year ended December 31, 2017, the Successor Period, the Predecessor Period and the year ended December 31, 2015, the Company capitalized $1.3 million, $0.4 million, $0.5 million and $1.3 million, respectively, of qualifying restricted stock unit share-based compensation costs to oil and gas properties. For the year ended December 31, 2014, the Company announced that its corporate headquarters was relocating from Houston, Texas to Tulsa, Oklahoma, which resulted in the accelerated vesting of restricted stock awards under the 2012 LTIP in the period for Houston employees subject to a severance agreement. Of the $4.4 million in share-based compensation for year ended December 31, 2015, approximately $1.5 million was related to the accelerated vesting for employees impacted by the corporate relocation. Unrecognized expense as of December 31, 2017 for all outstanding RSUs under the 2016 LTIP Plan was $3.5 million and will be recognized over a weighted average period of 1.4 years. Stock Options On December 31, 2017, the Company had 245,845 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 Weighted-average assumptions used: Risk-free interest rate (1) % % Dividend yield — — Expected option life (2) Expected volatility (3) % % Calculated fair value per stock option $ $ (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, 2017 and the Successor Period: Options Range of Weighted Weighted Stock options outstanding at October 21, 2016 $ $ Granted $ $ Vested — $ — $ — — Forfeited ) $ — Stock options outstanding at December 31, 2016 $ Granted $ $ Vested (1) ) $ 19.08-20.97 $ — Forfeited ) $ $ — Stock options outstanding at December 31, 2017 $ Vested and exercisable at end of period (2) $ 19.08-20.97 $ (1) Vested stock options include 109,820 awards in which vesting was accelerated to October 21, 2017 as a result of the former CEO’s amended employment agreement. (2) Vested and exercisable options at December 31, 2017, had no aggregate intrinsic value. There were no vested options at December 31, 2016. On August 22, 2017, the Company amended 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 $0.7 million of compensation expense associated with Mr. Brace’s non-vested stock options was accelerated into the third and fourth quarters of 2017. 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, 2017 and 2016 was $2.6 million and $0.8 million, respectively. For the years ended December 31, 2017 and 2016, the Company capitalized $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, 2017 for all outstanding stock options was $1.3 million and will be recognized over a weighted average period of 1.3 years. Non-Employee Director Restricted Stock Units Containing a Market Condition On November 23, 2016, the Company issued certain 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 liability and related compensation expense of these awards for each period is recognized by dividing the fair value of the total liability 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 non-employee directors. A Monte Carlo simulation was used in order to determine the fair value of these awards as of December 31, 2017 and 2016. The assumptions used to estimate the fair value of restricted stock unit awards with a market condition at December 31, 2017 and 2016 are as follows: December 31, 2017 December 31, 2016 Risk-free interest rate (1) % % Dividend yield — — Expected volatility (2) % % Market Price Hurdle $ $ Calculated fair value per restricted stock 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 expected life of the restricted stock unit. (2) As the Company does not have a significant stock trading 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 55.1% to 89.0% and 39.8% to 61.4%, respectively. 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, 2017 and 2016, the Company recorded $0.9 million and $0.1 million, respectively, of liabilities included within accrued liabilities on the consolidated balance sheets related to the market condition awards. As of December 31, 2017, there was no unrecognized stock-based compensation related to director market condition awards. The following table reflects the outstanding non-employee director restricted stock unit awards containing a market condition for the year ended December 31, 2017 and the Successor Period: Shares Weighted Average Outstanding at October 21, 2016 — $ — Granted $ Vested — $ — Forfeited — $ — Outstanding at December 31, 2016 $ Outstanding at December 31, 2017 $ 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 (1) 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 (2) with respect to the remaining 50% of the RSUs granted, the Company’s “Relative TSR” as follows: Actual TSR for the Performance Period Vesting as % of Relative TSR for the Performance Period Vesting as % of Maximum 25% or greater compounded annual growth (“CAGR”) % Top 5% or better Relative TSR to Peer Group % Target 20% or greater CAGR % Top 33.3% or better Relative TSR to Peer Group % Threshold 15% or greater CAGR % Top 50% or better Relative TSR to Peer Group % 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 (1) accelerate all or a portion of the award, (2) cancel all of the award and pay cash, stock or combination equal to the change in control price, (3) provide for the assumption or substitution or continuation by the successor company, (4) certify to the extent to which the vesting conditions had been achieved prior to the conclusion of the performance period or (5) adjust RSUs to reflect the change in control. 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 Risk-free interest rate (1) 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 $0.1 million at December 31, 2017. As of December 31, 2017, unrecognized stock-based compensation related to CEO RSUs containing a market condition was $1.4 million and will be recognized over a weighted-average period of 2.8 years. The following table reflects the outstanding CEO RSUs containing a market condition for the year ended December 31, 2017: Shares Weighted Average Outstanding at December 31, 2016 — $ — Granted $ Vested — $ — Forfeited — $ — Outstanding at December 31, 2017 $ 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, 2017 or 2016. Stock-Based Compensation Expense Summary The following summarizes stock-based compensation expense for the periods presented (in thousands): Successor Predecessor For the Year For the For the For the Year 2017 31, 2016 2016 2015 Restricted stock units (Predecessor) $ — $ — $ $ Restricted stock units (Successor) — — Stock options (Successor) — — Non-employee director restricted stock units with a market condition (Successor) — — CEO restricted stock units with a market condition (Successor) — — — Unrestricted stock awards (Successor) — — — Total stock-based compensation Less: amounts capitalized to oil and natural gas properties ) ) ) ) Net stock-based compensation $ $ $ $

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Taxes
Income Taxes	13. Income Taxes The Company emerged from bankruptcy in October 2016. Under the Bankruptcy Plan, a substantial portion of the Company’s pre-petition debt securities were extinguished. Absent an exception, a debtor recognizes cancellation of indebtedness income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The Internal Revenue Code of 1986, as amended (“IRC”), provides that a debtor in a bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. As a result of the market value of equity upon emergence from Chapter 11 bankruptcy proceedings, the estimated amount of U.S. CODI is approximately $1.2 billion, which reduced the value of the Company’s U.S. net operating losses and other assets. The actual reduction in tax attributes occurred on the first day of the Company’s tax year subsequent to the date of emergence, or January 1, 2017. The Company had a full reduction of its federal and state NOL carryforwards and a reduction of the tax basis in its fixed assets as of January 1, 2017, pursuant to IRC section 108. 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. As the Tax Act was passed late in the fourth quarter of 2017, ongoing guidance from the Department of Treasury and state agencies and accounting interpretation is expected to be issued over the next 12 months. Therefore, the Company considers the accounting of certain items, as discussed below, to be incomplete due to forthcoming guidance and the ongoing analysis of final year-end data and tax positions. The Company has 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 continues to analyze 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 is 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 has not adjusted certain tax items previously reported on its financial statements for IRC Section 162(m) until it is able to obtain sufficient information to make a reasonable estimate of the effects of the Tax Act. The Company expects to complete its analysis within the measurement period in accordance with SAB No. 118. As of December 31, 2017, the Company has recorded a full valuation allowance against its net deferred tax assets of $120.1 million, of which $72.6 million relates to deferred tax assets on the Company’s property and equipment. The change in the Company’s valuation allowance was driven by two amounts; (1) a $32.5 million increase due to the Company’s yearly activity from December 31, 2016 to December 31, 2017; and (2) a $73.2 million reduction as a result of the reduction of the corporate tax rate in the Tax Act. As of December 31, 2017, 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 Year Ended For the Period For the Period For the Year Ended December 31, 2017 December 31, 2016 October 20, 2016 December 31, 2015 (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 Year Ended For the Period For the Period Year Ended December 31, 2017 December 31, 2016 October 20, 2016 December 31, 2015 (in thousands) (in thousands) Income (loss) before taxes $ ) $ $ $ ) Statutory rate % % % % Income tax provision (benefit) computed at statutory rate ) ) Reconciling items: State income taxes, net of federal benefit ) ) Change in valuation allowance ) ) ) Adjustment to deferred tax assets and liabilities for enacted change in federal tax rate — — — Change in state rate ) ) ) ) Bankruptcy items — — — Deferred tax true-ups ) — Other, net ) 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 2017 2016 Deferred tax assets Federal tax loss carryforwards — Derivative instruments and other — State tax loss carryforwards — Employee benefit plans Oil and gas properties and equipment Other Less valuation allowance ) ) Total deferred tax assets $ — $ — Deferred tax liabilities Oil and gas properties and equipment — — Total deferred tax liabilities $ — $ — 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, 2017
Income (Loss) Per Share
Income (Loss) Per Share	14. 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, 2017 and the Successor Period: For the Period Year Ended October 21, 2016 through (in thousands, except per (in thousands, except per Net Income (Loss): Net income (loss) $ ) $ Participating securities—non-vested restricted stock — ) Basic and diluted income (loss) $ ) $ Common Shares: Common shares outstanding — basic (1) Dilutive effect of potential common shares — — Common shares outstanding — diluted Net Income (Loss) Per Share: Basic $ ) $ Diluted $ ) $ Antidilutive stock options (2) Antidilutive warrants (3) (1) Weighted-average common shares outstanding for basic and diluted income (loss) per share purposes includes 17,533 shares of common stock that, while not issued and outstanding at December 31, 2017 or 2016, are required by the Plan to be issued. Weighted-average common shares outstanding for basic and diluted income (loss) per share purposes also includes 57,856 director shares that vested at December 31, 2017 but final issuance of the vested shares was deferred until 2020. (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 and the year ended December 31, 2015: For the Period January 1, 2016 through Year Ended (in thousands, except per share amounts) Net income (loss) $ 1,323,079 $ (1,797,195 ) Preferred dividend(1) — ) Net income (loss) attributable to shareholders $ $ ) Participating securities—Series A preferred stock(2) — — Participating securities—Non-vested restricted stock(2) ) — Net income (loss) attributable to common shareholders $ $ ) Weighted average shares outstanding Basic and diluted net income (loss) per share $ $ ) (1) Calculation of the preferred stock dividend is discussed in “—Note 11. 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, 2017
Concentrations of Credit Risk
Concentrations of Credit Risk	15. 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, 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. For the year ended December 31, 2015, two purchasers accounted for 43% and 25%, 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, 2017, three purchasers accounted for approximately 42%, 35% and 10%, respectively, of the accounts receivable balance. At December 31, 2016, two purchasers accounted for approximately 44% and 26%, 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, 2017. The Company did not have any open commodity derivative contract positions at December 31, 2016 and all of our derivative positions at December 31, 2015 had expired.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies
Commitments and Contingencies	16. Commitments and Contingencies Contractual Obligations At December 31, 2017, contractual obligations for drilling contracts, long-term operating leases and other contracts are as follows (in thousands): Total 2018 2019 2020 2021 2022 and Drilling contracts $ — $ — $ — $ — $ — $ — Non-cancellable office lease commitments Net minimum commitments $ $ $ $ $ $ For the year ended December 31, 2017, the Successor Period, the Predecessor Period and year ended December 31, 2015, the Company expensed $0.6 million, $0.1 million, $4.3 million and $2.3 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 we do not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLs, we would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee. We are 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 9. 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, 2017 and 2016, 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, 2017
Supplemental Information to Consolidated Statement of Cash Flows
Supplemental Information to Consolidated Statement of Cash Flows	17. 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 Year Ended Period Period Year Ended December 31, December 31, October 20, December 31, SUPPLEMENTAL INFORMATION: Non-cash investment in property and equipment $ $ $ $ Non-cash component of Dequincy Divestiture: —Asset retirement obligation disposed $ — $ — $ — $ ) Non-cash exchange of third lien notes for 2020 senior notes and 2021 senior notes $ — $ — $ — $ Non-cash exchange of common equity of the reorganized Company for second lien notes $ — $ — $ $ — Non-cash exchange of common equity and warrants of the reorganized Company for third lien notes $ — $ — $ $ — Non-cash exchange of common equity and warrants of the reorganized Company for 2020 senior notes $ — $ — $ $ — Non-cash exchange of common equity and warrants of the reorganized Company for 2021 senior notes $ — $ — $ $ — Cash paid for interest, net of capitalized interest for the year ended December 31, 2017, Successor Period and the year ended December 31, 2015 of $2.4 million, $0.7 million and $4.9 million, respectively (no capitalized interest for the Predecessor Period) $ $ $ $ Cash paid for reorganization items $ — $ — $ $ —

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions
Related Party Transactions	18. 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., an entity holding approximately 25.4% of the Company’s outstanding common stock. 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. No transactions with EcoStim occurred in the Successor Period, the Predecessor Period or the year ended December 31, 2015. 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 the year ended December 31, 2015.

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2017
Subsequent Event
Subsequent Event	19. Subsequent Event On January 24, 2018, the Company had a reduction in workforce resulting in severance costs of $1.6 million. In addition, $1.4 million in additional costs were incurred as a result of 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, 2017
Supplemental Oil and Gas Disclosures (Unaudited)
Supplemental Oil and Gas Disclosures (Unaudited)	20. 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, 2017, the Successor Period, the Predecessor Period and the year ended December 31, 2015 (in thousands): Successor Predecessor For the Year For the Period For the Period For the Year December 31, through December 31, through October 20, December 31, Acquisition costs: Proved properties $ — $ — $ — $ — Unproved properties Exploration costs — — — — Development costs Total costs incurred $ $ $ $ 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 $5.3 million, $1.4 million, $3.4 million and $7.3 million for the year ended December 31, 2017, the Successor Period, the Predecessor Period and the year ended December 31, 2015, 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 $2.4 million, $0.7 million and $4.9 million for the year ended December 31, 2017, the Successor Period and the year ended December 31, 2015. 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, 2017 and 2016 (in thousands): December 31, 2017 December 31, 2016 Proved properties $ $ Unproved properties not being amortized Gross capitalized costs Less: Accumulated depreciation, depletion, amortization and impairment ) ) Net capitalized costs $ $ At December 31, 2017, the Company had $7.1 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 primarily 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, 2017, 2016 and 2015 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, 2017, 2016 and 2015: Oil NGL Gas Total 2015 (Predecessor) Proved Reserves Beginning Balance Revision of previous estimates ) ) ) ) Extensions, discoveries and other additions Sales of reserves in place ) ) ) ) Purchases of reserves in place Production ) ) ) ) Net proved reserves at December 31, 2015 Proved developed reserves, December 31, 2015 Proved undeveloped reserves, December 31, 2015 2016 (Predecessor) Proved Reserves Beginning Balance Revision of previous estimates ) ) ) ) Extensions, discoveries and other additions Sales of reserves in place — — — — Purchases of reserves in place — — — — Production ) ) ) ) Net proved reserves at October 20, 2016 Proved developed reserves, October 20, 2016 Proved undeveloped reserves, October 20, 2016 — — — — 2016 (Successor) Proved Reserves Beginning Balance Revision of previous estimates Extensions, discoveries and other additions Sales of reserves in place — — — — Purchases of reserves in place — — — — Production ) ) ) ) Net proved reserves at December 31, 2016 Proved developed reserves, December 31, 2016 Proved undeveloped reserves, December 31, 2016 2017 Proved Reserves Beginning Balance Revision of previous estimates ) ) ) ) Extensions, discoveries and other additions Sales of reserves in place ) ) ) ) Purchases of reserves in place — — — — Production ) ) ) ) Net proved reserves at December 31, 2017 Proved developed reserves, December 31, 2017 Proved undeveloped reserves, December 31, 2017 Revision of Previous Estimates 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. As a result, in December of 2017 the Company decreased its current drilling activity from two drilling rigs to one drilling rig. Further, the five-year development plan was revised from a two-rig program to a one rig program. This change in strategy (reduced 5-year drilling activity) 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. In addition, at year end 2017 the Company’s proved undeveloped type curve was revised downward by its third-party reserves engineering firm and capital costs assumptions were revised upward, both as a result of recent drilling results. As a result of the Company’s focus on optimizing free cash flow, keeping leverage to a minimum and optimizing drilling returns, all proved undeveloped reserves included in the December 31, 2017 reserve report are focused on infill drilling in the Carmen and Dacoma areas. 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 but continue to meet the definition of a proved undeveloped location from an engineering standpoint. 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, 2017, the Company had 18,464 MBoe of extensions and discoveries, all of which occurred in the Mississippian Lime area. For the Successor Period, the Company had 58,296 MBoe of extensions and discoveries associated with its proved undeveloped reserves in the Mississippian Lime area. 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 this expected development plan. Proved undeveloped reserves that were not included in any proved category in prior years but included in the Company’s updated five-year development schedule were classified as an extension in the above tables. For the Predecessor Period and the year ended December 31, 2015, the Company had 4,249 MBoe and 6,398 MBoe, respectively, 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 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. For the year ended December 31, 2015, the Company had 5,019 MBoe in sales of reserves in place, of which 2,307 MBoe of the sale related to the Dequincy Divestiture, which closed on April 21, 2015, and 2,712 MBoe resulted from the swap of leasehold interests in the Mississippian Lime area in the second quarter of 2015. Purchases of Reserves in Place For the year ended December 31, 2015, the Company had 6,118 MBoe of additions from purchases of reserves in place resulting from a swap of leasehold interests in the Mississippian Lime area. 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. Our 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 our estimated proved reserves for the periods indicated: Successor Predecessor At December 31, At December 31, 2017 2016 2015 Oil and Natural Gas Prices: Oil (per barrel) $ $ $ Natural gas (per million British thermal units) $ $ $ 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, 2017, 2016, and 2015 (in thousands): Successor Predecessor At December 31, Year Ended 2017 2016 2015 Future cash inflows $ $ $ Future production costs ) ) ) Future development costs ) ) ) Future income tax expense ) ) — Future net cash flows 10% annual discount for estimated timing of cash flows ) ) ) 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, 2017, the Successor Period, the Predecessor Period and the year ended December 31, 2015 (in thousands): Successor Predecessor Year Ended For the Period October For the Period January Year Ended 2017 December 31, 2016 October 20, 2016 2015 Standardized measure, beginning of period $ $ $ $ Net changes in prices and production costs ) ) Net changes in future development costs ) Sales of oil and natural gas, net ) ) ) ) Extensions Discoveries — — — — Purchases of reserves in place — — — Divestiture of reserves ) — — ) Revisions of previous quantity estimates ) ) ) Previously estimated development costs incurred — Accretion of discount Net change in income taxes ) — Changes in timing, other ) ) ) Standardized measure, end of period $ $ $ $

Selected Quarterly Financial Da

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2017
Selected Quarterly Financial Data
Selected Quarterly Financial Data	21. 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 (in thousands, except per share amounts) 2017 (Successor) Total revenues $ $ $ $ Operating income (loss) ) Net income (loss) ) Net income (loss) available to common shareholders ) Net income (loss) per share: Basic and Diluted $ $ $ $ ) Shares used in computation: Basic and Diluted 2016 (Successor) Total revenues $ — $ — $ — $ Operating income — — — Net income — — — Net income available to common shareholders — — — Net income per share: Basic and Diluted $ — $ — $ — $ Shares used in computation: Basic and Diluted — — — 2016 (Predecessor) Total revenues $ $ $ $ Operating income (loss) ) ) ) ) Net income (loss) ) ) Net loss available to common shareholders ) ) Net loss per share: Basic and Diluted $ ) $ $ ) $ Shares used in computation: Basic and Diluted (1) Fourth quarter for the 2016 Predecessor Period is for the period October 1, 2016 through October 20, 2016. Fourth quarter for the 2016 Successor Period is the period October 21, 2016 through December 31, 2016.

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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 consolidated financial statements as of and for the year ended December 31, 2015 include the results of the Dequincy Divestiture from January 1, 2015 through April 21, 2015, the date of disposition. 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.
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 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, 2017 and 2016 that exceeded the balance insured by the FDIC in the amount of $70.4 million and $78.4 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, 2017 and 2016, 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 5. Fair Value Measurements of Financial Instruments”. The fair value of the Company’s long-term debt is disclosed, see “—Note 10. 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 2015, the Company transferred the remaining unevaluated property balance consisting of $56.3 million of Mississippian unevaluated property costs, $0.2 million of Anadarko Basin unevaluated property costs and $0.1 million of Gulf Coast unevaluated property costs to the full cost pool as a result of current pricing during 2015, its anticipated drilling plans and uncertainty regarding its ability to finance its future exploration activities at that time. During the year ended December 31, 2017, the Company transferred $58.0 million of unevaluated property to the full cost pool. As discussed below under “Impairment of Oil and Gas Properties/Ceiling Test” the Company’s strategy was refined during the fourth quarter of 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 under the new proved undeveloped type curve. 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. 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 its strategy was refined to add further focus to optimizing free cash flows and keeping leverage to a minimum. As a result, in December of 2017 the Company decreased its current drilling activity from two drilling rigs to one drilling rig. Further, the five-year development plan was revised from a two-rig program to a one rig program. This change in strategy (reduced 5-year drilling activity) 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. In addition, at year end 2017 our proved undeveloped type curve was revised downward by the Company’s third-party reserves engineering firm and capital costs assumptions were revised upward, both as a result of recent drilling results. As a result of the Company’s focus on optimizing free cash flow, keeping leverage to a minimum and optimizing drilling returns, all proved undeveloped reserves included in the December 31, 2017 reserve report are focused on infill drilling in the Carmen and Dacoma areas. 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 but continue to meet the definition of a proved undeveloped location from an engineering standpoint. 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. For the year ended December 31, 2017, the Predecessor Period and the year ended December 31, 2015, the Company recorded impairments of oil and gas properties of $125.3 million, $232.1 million and $1.6 billion, respectively. During the Predecessor Period and the year ended December 31, 2015, 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. 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, 2017 and 2016, accrued liabilities consisted of the following (in thousands): December 31, 2017 December 31, 2016 Accrued oil and gas capital expenditures $ $ Accrued revenue and royalty distributions Accrued lease operating and workover expense Accrued interest Accrued taxes Compensation and benefit related accruals Other Accrued liabilities $ $
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 9. 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 12. Equity and Share-Based Compensation”.
Revenue Recognition	Revenue Recognition Oil, NGLs and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has transferred and collection of the revenues is reasonably assured. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met. The Company follows the sales method of accounting for oil, NGLs and natural gas revenues, whereby revenue is recognized 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, 2017, 2016 or 2015. Beginning January 1, 2018, the FASB Accounting Standards Update (“ASU”) 2014-09 becomes effective for the Company. See “Recent Accounting Pronouncements” below for further information.
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. Costs incurred in 2015 relate to the Dequincy Divestiture. See “—Note 8. 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. We will continue to monitor guidance and update account policies and procedures as needed. See “—Note 13. Income Taxes.”
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 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 14. Income (Loss) Per Share.”
Recent Accounting Pronouncements	Recent Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers (Topic 606) ” (“ASU 2014-09”). 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. ASU 2014-09 requires an entity to perform the following steps: Step 1—Identify the contract with a customer: A contract between two or more parties creates enforceable rights and obligations. A contract that identifies the relevant parties and has been approved by those parties, identifies the payment terms, has commercial substance and results in a probable collection of future consideration meets the definition of ASU 2014-09. Step 2—Identify the performance obligations in the contract: A performance obligation is effectively a promise in a contract with a customer to transfer goods or services to the customer. If an entity promises to transfer more than one good or service to the customer, each performance obligation is accounted for separately if such performance obligations are distinct, as defined under ASU 2014-09. Step 3—Determine the transaction price: The amount of consideration an entity expects to be entitled to as a result of performing services to a customer or transferring goods to a customer is the transaction price. The transaction price takes into account variable consideration, the existence of significant financing component, noncash consideration and the type of consideration payable to the entity. Step 4—Allocate the transaction price to the performance obligations in the contract: An entity should allocate the transaction price to each performance obligation in an amount that represents the amount of the entity expects to be entitled to for satisfying each performance obligation. Step 5—Recognize revenue when, or as, the entity satisfies a performance obligation: An entity recognizes revenue when, or as, it satisfies a performance obligation. A performance obligation can be satisfied over time or at a point in time. ASU 2014-09 provides criteria for determining the appropriate classification of each performance obligation. Throughout 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, “ Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date ” ASU No. 2016-08, “ Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations ”, ASU No. 2016-10, “Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing” , ASU No. 2016-12, “ Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients ” and ASU No. 2016-20, “ Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers ”. ASU 2014-09 and the associated amendments mentioned above will be effective for the Company beginning on January 1, 2018, including interim periods within that reporting period. The Company completed its assessment of ASU 2014-09 during the fourth quarter of 2017. The primary impact to the Company’s revenues as the result of adopting ASU 2014-09 will be the netting of certain deductions and costs, such as transportation and gathering expenses, against revenue instead of its historical practice of presenting such expenses gross. For example, revenues from oil, natural gas and NGL sales for the year ended December 31, 2017 would have been $15.8 million lower under ASU 2014-09, with an offsetting decrease to total expenses. The implementation of ASU 2014-09 will not impact the Company’s timing of revenue recognition, financial position, net income or cash flows. The Company does not anticipate a material cumulative effect adjustment on January 1, 2018 as a result of adopting ASU 2014-09. The Company also completed its evaluation of information technology and internal control changes that will be required for adoption based on the its contract review process, which primarily required the remapping of certain accounts utilized for tracking these deduction and expenses along with enhanced reviews of any new revenue contracts or modifications to existing revenue contracts. The Company will apply the modified retrospective approach upon adoption of this standard on the effective date of January 1, 2018. In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases (Topic 842)” (“ASU 2016-02”). ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. 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. 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. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company is in the initial evaluation and planning stages for ASU 2016-02. In August 2016, the FASB issued ASU 2016-15, “ Statement of Cash Flows — Classification of Certain Cash Receipts and Cash Payments” (“ASU 2016-15”). ASU 2016-15 addresses eight specific cash flow issues with the objective of reducing existing diversity of practice. The eight specific cash flow issues contained within ASU 2016-15 are debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. ASU 2016-15 is effective for the Company for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company does not believe the adoption of ASU 2016-15 will have a material impact on its cash flows. In July 2017, the FASB issued Accounting Standards Update 2017-11, “Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815)” (“ASU 2017-11”). ASU 2011-17 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“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.

Fresh Start Accounting (Tables)

Fresh Start Accounting (Tables)	12 Months Ended
	Dec. 31, 2017
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 Enterprise value $ Plus: Cash and cash equivalents Less: Fair value of debt ) Less: Fair value of warrants ) Fair value of stock on the Effective Date $ Total shares issuable under the Plan Restricted shares granted under 2016 LTIP at October 21, 2016 Total shares Per share value (1) $ (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 Risk-free interest rate (1) % % Dividend yield — — Expected life (2) Expected volatility (3) % % Strike Price $ $ Calculated fair value $ $ (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 Enterprise value $ Plus: cash and cash equivalents Plus: other working capital liabilities Plus: other long-term liabilities Reorganization value $
Schedule of reorganization balance sheet and fresh start accounting adjustments	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 $ $ ){a} $ — $ Accounts receivable: Oil and gas sales — — Joint interest billing — — Other — — Other current assets ){b} — Total current assets ) — PROPERTY AND EQUIPMENT: Oil and gas properties, on the basis of full-cost accounting — ){h} Other property and equipment — ){h} Less accumulated depreciation, depletion, amortization and impairment ) — {h} — Net property and equipment — OTHER NONCURRENT ASSETS {c} {a} — TOTAL $ $ ) $ $ LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT) CURRENT LIABILITIES: Accounts payable $ $ — $ — $ Accrued liabilities ){a} — Debt classified as current ){a} {d} — — Total current liabilities ) — ASSET RETIREMENT OBLIGATIONS — ){h} OTHER LONG-TERM LIABILITIES {d} — LIABILITIES SUBJECT TO COMPROMISE ){e} {a} — — COMMITMENTS AND CONTINGENCIES STOCKHOLDERS’ EQUITY/(DEFICIT): Preferred stock — — — — Warrants — {e} — Common stock - predecessor ){f} — — Common stock - successor — {f} — Treasury stock ) {f} — — Additional paid-in-capital - predecessor ){f} — — Additional paid-in-capital - successor — {f} — Retained deficit ) {g} {i} — Total stockholders’ equity/(deficit) ) TOTAL $ $ ) $ $ 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 $ Cash payment to holders of Second Lien Notes Claims Cash payment to the RBL lenders in consideration of a temporary reduction in the amount available to be drawn under the Exit Facility Payment to escrow for professional fees related to the Plan incurred through the Effective Date Debt issuance costs associated with the Exit Facility Total uses $ {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 $ Cash paid to holders of Second Lien Notes Claims ) Warrants issued to holders of Third Lien Notes Claims ) Warrants issued to holders of Unsecured Notes Claims ) Write-off of unamortized debt costs associated with RBL ) Common stock issued ) Gain on settlement $ {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 $ Common stock - predecessor Treasury stock ) Additional paid-in-capital - predecessor Net impact to Predecessor accumulated deficit $ 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.
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 $ Cash payment to holders of Second Lien Notes Claims Cash payment to the RBL lenders in consideration of a temporary reduction in the amount available to be drawn under the Exit Facility Payment to escrow for professional fees related to the Plan incurred through the Effective Date Debt issuance costs associated with the Exit Facility Total uses $
Schedule of Liabilities subject to compromise, settled	The gain was calculated as follows (in thousands): Predecessor Liabilities subject to compromise $ Cash paid to holders of Second Lien Notes Claims ) Warrants issued to holders of Third Lien Notes Claims ) Warrants issued to holders of Unsecured Notes Claims ) Write-off of unamortized debt costs associated with RBL ) Common stock issued ) Gain on settlement $
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 $ Common stock - predecessor Treasury stock ) Additional paid-in-capital - predecessor Net impact to Predecessor accumulated deficit $
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 Professional fees incurred $ ) Adjustment to unamortized debt issuance costs associated with 2020 Senior Notes ) Adjustment to unamortized debt issuance costs associated with 2021 Senior Notes ) Adjustment to unamortized gain on troubled debt restructuring associated with Second Lien Notes Adjustment to unamortized gain on troubled debt restructuring associated with Third Lien Notes Gain on settlement of liabilities subject to compromise Fresh start adjustments Other reorganization items (1) Gain on reorganization items, net $ (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 Accoun31

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Summary of Significant Accounting Policies
Schedule of accrued liabilities	At December 31, 2017 and 2016, accrued liabilities consisted of the following (in thousands): December 31, 2017 December 31, 2016 Accrued oil and gas capital expenditures $ $ Accrued revenue and royalty distributions Accrued lease operating and workover expense Accrued interest Accrued taxes Compensation and benefit related accruals Other Accrued liabilities $ $

Fair Value Measurements of Fi32

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Measurements of Financial Instruments
Schedule of derivative instruments measured at fair value	Fair Value Measurements at December 31, 2017 Significant Other Significant Quoted Prices in Active Observable Inputs Unobservable Inputs Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps $ — $ $ — $ Commodity derivative oil collars $ — $ $ — $ Commodity derivative gas collars $ — $ $ — $ Total assets $ — $ $ — $ Derivative Liabilities: Commodity derivative oil swaps $ — $ ) $ — $ ) Commodity derivative gas swaps $ — $ — $ — $ — Commodity derivative oil collars $ — $ ) $ — $ ) Commodity derivative gas collars $ — $ ) $ — $ ) Total liabilities $ — $ ) $ — $ )

Risk Management and Derivativ33

Risk Management and Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Risk Management and Derivative Instruments
Schedule of commodity derivative contracts	NYMEX WTI Fixed Swaps Collars Three-Way Collars Hedge Weighted Hedge Weighted Weighted Hedge Weighted Weighted Weighted Quarter Ended: December 31, 2017(1)(2) $ $ $ $ $ $ March 31, 2018(1) $ — $ — $ — $ $ $ June 30, 2018(1) $ — $ — $ — $ $ $ September 30, 2018(1) $ — $ — $ — $ $ $ December 31, 2018(1) $ — $ — $ — $ $ $ March 31, 2019(1) — $ — — $ — $ — $ $ $ June 30, 2019(1) — $ — — $ — $ — $ $ $ September 30, 2019(1) — $ — — $ — $ — $ $ $ December 31, 2019(1) — $ — — $ — $ — $ $ $ NYMEX HENRY HUB Fixed Swaps Collars Three-Way Collars Hedge Weighted Hedge Weighted Weighted Hedge Weighted Weighted Weighted Quarter Ended: December 31, 2017(1) $ $ $ $ $ $ March 31, 2018(1)(3) $ — $ — $ — $ $ $ June 30, 2018(1) — $ — — $ — $ — $ $ $ September 30, 2018(1) — $ — — $ — $ — $ $ $ December 31, 2018(1) — $ — — $ — $ — $ $ $ March 31, 2019(1) — $ — — $ — $ — $ $ $ (1) Positions shown represent open commodity derivative contract positions as of December 31, 2017. The Company did not have any open commodity derivative contract positions as of December 31, 2016. (2) During the second quarter, the Company entered into long call oil trades to offset its three-way collar short calls for the second half of 2017. (3) During the second quarter, the Company entered into natural gas three-way collars with long call ceilings in order to offset its Q1 2018 natural gas fixed swaps.
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 at December 31, 2017 (in thousands): Type Balance Sheet Location (1) December 31, 2017 Gas swaps Derivative financial instruments — current assets $ Oil collars Derivative financial instruments — current assets ) Gas collars Derivative financial instruments — current assets Total derivative financial instruments — current assets $ Oil swaps Derivative financial instruments — current liabilities $ ) Oil collars Derivative financial instruments — current liabilities ) Gas collars Derivative financial instruments — current liabilities Total derivative financial instruments — current liabilities $ ) Oil collars Derivative financial instruments — noncurrent liabilities $ ) Gas collars Derivative financial instruments — noncurrent liabilities ) Total derivative financial instruments — noncurrent liabilities $ ) Total derivative fair value at period end $ ) (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 at December 31, 2017 (in thousands): December 31, 2017 Not Designated as Gross Recognized Gross Amounts Net Recognized ASC 815 Hedges Balance Sheet Location Classification Assets/Liabilities Offset Assets/Liabilities Derivative Assets: Commodity contracts Derivative financial instruments — current $ $ ) $ Commodity contracts Derivative financial instruments — noncurrent ) — $ $ ) $ Derivative Liabilities: Commodity contracts Derivative financial instruments — current $ ) $ $ ) Commodity contracts Derivative financial instruments — noncurrent ) ) $ ) $ $ )
Schedule of net cash received for commodity derivative contracts and unrealized net gains related to the change in fair value of derivative instruments - 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 Year For the Period For the Period For the Year 2017 December 31, 2016 October 20, 2016 2015 Net cash received for commodity derivative contracts $ $ — $ — $ Unrealized net losses ) — — ) Gains on commodity derivative contracts—net $ $ — $ — $

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property and Equipment
Schedule of property and equipment	The Company’s property and equipment as of December 31, 2017 and 2016 was as follows (in thousands): December 31, 2017 December 31, 2016 Oil and gas properties, on the basis of full-cost accounting: Proved properties $ $ Unproved properties not being amortized Other property and equipment Less accumulated depreciation, depletion, amortization and impairment ) ) Net property and equipment $ $

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligations
Schedule of change in the AROs	The following table details the change in the AROs for the year ended December 31, 2017 and the Successor Period, respectively (in thousands): Successor For the Year Ended For the Period October 2017 December 31, 2016 Asset retirement obligations at beginning of period $ $ Liabilities incurred Revisions — Liabilities settled ) — Liabilities eliminated through asset sale (1) ) — Current period accretion expense Asset retirement obligations at end of year $ $ (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 7. Property and Equipment”.

Equity and Share-Based Compen36

Equity and Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Equity and Share-Based Compensation
Summary of changes in the number of outstanding shares	Common Treasury Share count as of December 31, 2014 (Predecessor) ) Grants of restricted stock — Forfeitures of restricted stock ) — Acquisition of treasury stock — ) Fractional share adjustment due to reverse stock split ) — Issuance of common stock for Series A Preferred Stock conversion — Share count as of December 31, 2015 (Predecessor) ) Grants of restricted stock — — Forfeitures of restricted stock ) — Acquisition of treasury stock — ) Share count as of October 21, 2016 (Predecessor) ) Cancellation of common stock ) — Cancellation of treasury stock — Share count as of October 21, 2016 (Predecessor) — — Issuance of successor common stock — Share count as of October 21, 2016 (Successor) — Issuance of successor common stock — Acquisition of treasury stock — — Share count as of December 31, 2016 (Successor) — Issuance of successor common stock — Acquisition of treasury stock — ) Share count as of December 31, 2017 (Successor) ) (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	Restricted Stock Weighted Average Non-vested shares outstanding at December 31, 2014 (Predecessor) $ Granted $ Vested ) $ Forfeited ) $ Non-vested shares outstanding at December 31, 2015 (Predecessor) $ Granted — $ — Vested ) $ Forfeited ) $ Non-vested shares outstanding at October 20, 2016 (Predecessor) $ Cancellation of non-vested shares ) $ Non-vested shares outstanding at October 20, 2016 (Predecessor) — $ — Granted at Effective Date $ Non-vested shares outstanding at October 21, 2016 (Successor) $ Granted $ Forfeited ) $ Non-vested shares outstanding at December 31, 2016 (Successor) $ Granted $ Vested(1) ) $ Forfeited ) $ Non-vested shares outstanding at December 31, 2017 (Successor) $ (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.
Schedule of assumptions used to estimate fair value of stock option awards	Awards Issued in Awards Issued in Weighted-average assumptions used: Risk-free interest rate (1) % % Dividend yield — — Expected option life (2) Expected volatility (3) % % Calculated fair value per stock option $ $ (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	Options Range of Weighted Weighted Stock options outstanding at October 21, 2016 $ $ Granted $ $ Vested — $ — $ — — Forfeited ) $ — Stock options outstanding at December 31, 2016 $ Granted $ $ Vested (1) ) $ 19.08-20.97 $ — Forfeited ) $ $ — Stock options outstanding at December 31, 2017 $ Vested and exercisable at end of period (2) $ 19.08-20.97 $ (1) Vested stock options include 109,820 awards in which vesting was accelerated to October 21, 2017 as a result of the former CEO’s amended employment agreement. (2) Vested and exercisable options at December 31, 2017, had no aggregate intrinsic value. There were no vested options at December 31, 2016.
Schedule of assumptions used to estimate fair value of restricted stock units with market condition	December 31, 2017 December 31, 2016 Risk-free interest rate (1) % % Dividend yield — — Expected volatility (2) % % Market Price Hurdle $ $ Calculated fair value per restricted stock 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 expected life of the restricted stock unit. (2) As the Company does not have a significant stock trading 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 55.1% to 89.0% and 39.8% to 61.4%, respectively.
Schedule of outstanding restricted stock unit awards containing market condition	Shares Weighted Average Outstanding at October 21, 2016 — $ — Granted $ Vested — $ — Forfeited — $ — Outstanding at December 31, 2016 $ Outstanding at December 31, 2017 $
Schedule of chief executive officer Restricted stock units containing a market condition with respect to RSUs granted	Actual TSR for the Performance Period Vesting as % of Relative TSR for the Performance Period Vesting as % of Maximum 25% or greater compounded annual growth (“CAGR”) % Top 5% or better Relative TSR to Peer Group % Target 20% or greater CAGR % Top 33.3% or better Relative TSR to Peer Group % Threshold 15% or greater CAGR % Top 50% or better Relative TSR to Peer Group % Below Threshold Less than 15% CAGR % Less than 50% of Relative TSR to Peer Group %
Schedule of chief executive officer restricted stock units with market condition valuation assumptions	Awards Issued Risk-free interest rate (1) 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 chief executive officer restricted stock units with market condition award activity	Shares Weighted Average Outstanding at December 31, 2016 — $ — Granted $ Vested — $ — Forfeited — $ — Outstanding at December 31, 2017 $
Summary of share-based compensation expense	The following summarizes stock-based compensation expense for the periods presented (in thousands): Successor Predecessor For the Year For the For the For the Year 2017 31, 2016 2016 2015 Restricted stock units (Predecessor) $ — $ — $ $ Restricted stock units (Successor) — — Stock options (Successor) — — Non-employee director restricted stock units with a market condition (Successor) — — CEO restricted stock units with a market condition (Successor) — — — Unrestricted stock awards (Successor) — — — Total stock-based compensation Less: amounts capitalized to oil and natural gas properties ) ) ) ) Net stock-based compensation $ $ $ $

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Taxes
Schedule of income tax provision (benefit)	Successor Predecessor For the Year Ended For the Period For the Period For the Year Ended December 31, 2017 December 31, 2016 October 20, 2016 December 31, 2015 (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 Year Ended For the Period For the Period Year Ended December 31, 2017 December 31, 2016 October 20, 2016 December 31, 2015 (in thousands) (in thousands) Income (loss) before taxes $ ) $ $ $ ) Statutory rate % % % % Income tax provision (benefit) computed at statutory rate ) ) Reconciling items: State income taxes, net of federal benefit ) ) Change in valuation allowance ) ) ) Adjustment to deferred tax assets and liabilities for enacted change in federal tax rate — — — Change in state rate ) ) ) ) Bankruptcy items — — — Deferred tax true-ups ) — Other, net ) 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 2017 2016 Deferred tax assets Federal tax loss carryforwards — Derivative instruments and other — State tax loss carryforwards — Employee benefit plans Oil and gas properties and equipment Other Less valuation allowance ) ) Total deferred tax assets $ — $ — Deferred tax liabilities Oil and gas properties and equipment — — Total deferred tax liabilities $ — $ — 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, 2017
Schedule of reconciliation of net income attributable to common shareholders and weighted average common shares outstanding for basic and diluted earnings per share	For the Period Year Ended October 21, 2016 through (in thousands, except per (in thousands, except per Net Income (Loss): Net income (loss) $ ) $ Participating securities—non-vested restricted stock — ) Basic and diluted income (loss) $ ) $ Common Shares: Common shares outstanding — basic (1) Dilutive effect of potential common shares — — Common shares outstanding — diluted Net Income (Loss) Per Share: Basic $ ) $ Diluted $ ) $ Antidilutive stock options (2) Antidilutive warrants (3) (1) Weighted-average common shares outstanding for basic and diluted income (loss) per share purposes includes 17,533 shares of common stock that, while not issued and outstanding at December 31, 2017 or 2016, are required by the Plan to be issued. Weighted-average common shares outstanding for basic and diluted income (loss) per share purposes also includes 57,856 director shares that vested at December 31, 2017 but final issuance of the vested shares was deferred until 2020. (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 Year Ended (in thousands, except per share amounts) Net income (loss) $ 1,323,079 $ (1,797,195 ) Preferred dividend(1) — ) Net income (loss) attributable to shareholders $ $ ) Participating securities—Series A preferred stock(2) — — Participating securities—Non-vested restricted stock(2) ) — Net income (loss) attributable to common shareholders $ $ ) Weighted average shares outstanding Basic and diluted net income (loss) per share $ $ ) (1) Calculation of the preferred stock dividend is discussed in “—Note 11. 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, 2017
Commitments and Contingencies
Schedule of contractual obligations for drilling contracts, long-term operating leases, and other contracts	At December 31, 2017, contractual obligations for drilling contracts, long-term operating leases and other contracts are as follows (in thousands): Total 2018 2019 2020 2021 2022 and Drilling contracts $ — $ — $ — $ — $ — $ — Non-cancellable office lease commitments Net minimum commitments $ $ $ $ $ $

Supplemental Information to C40

Supplemental Information to Consolidated Statement of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Information to Consolidated Statement of Cash Flows
Schedule of summarized interest and income taxes and supplemental non-cash investing and financing activities	Successor Predecessor Year Ended Period Period Year Ended December 31, December 31, October 20, December 31, SUPPLEMENTAL INFORMATION: Non-cash investment in property and equipment $ $ $ $ Non-cash component of Dequincy Divestiture: —Asset retirement obligation disposed $ — $ — $ — $ ) Non-cash exchange of third lien notes for 2020 senior notes and 2021 senior notes $ — $ — $ — $ Non-cash exchange of common equity of the reorganized Company for second lien notes $ — $ — $ $ — Non-cash exchange of common equity and warrants of the reorganized Company for third lien notes $ — $ — $ $ — Non-cash exchange of common equity and warrants of the reorganized Company for 2020 senior notes $ — $ — $ $ — Non-cash exchange of common equity and warrants of the reorganized Company for 2021 senior notes $ — $ — $ $ — Cash paid for interest, net of capitalized interest for the year ended December 31, 2017, Successor Period and the year ended December 31, 2015 of $2.4 million, $0.7 million and $4.9 million, respectively (no capitalized interest for the Predecessor Period) $ $ $ $ Cash paid for reorganization items $ — $ — $ $ —

Supplemental Oil and Gas Disc41

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017, the Successor Period, the Predecessor Period and the year ended December 31, 2015 (in thousands): Successor Predecessor For the Year For the Period For the Period For the Year December 31, through December 31, through October 20, December 31, Acquisition costs: Proved properties $ — $ — $ — $ — Unproved properties Exploration costs — — — — Development costs Total costs incurred $ $ $ $
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, 2017 and 2016 (in thousands): December 31, 2017 December 31, 2016 Proved properties $ $ Unproved properties not being amortized Gross capitalized costs Less: Accumulated depreciation, depletion, amortization and impairment ) ) Net capitalized costs $ $
Schedule of estimated quantities of proved oil and natural gas reserves	Oil NGL Gas Total 2015 (Predecessor) Proved Reserves Beginning Balance Revision of previous estimates ) ) ) ) Extensions, discoveries and other additions Sales of reserves in place ) ) ) ) Purchases of reserves in place Production ) ) ) ) Net proved reserves at December 31, 2015 Proved developed reserves, December 31, 2015 Proved undeveloped reserves, December 31, 2015 2016 (Predecessor) Proved Reserves Beginning Balance Revision of previous estimates ) ) ) ) Extensions, discoveries and other additions Sales of reserves in place — — — — Purchases of reserves in place — — — — Production ) ) ) ) Net proved reserves at October 20, 2016 Proved developed reserves, October 20, 2016 Proved undeveloped reserves, October 20, 2016 — — — — 2016 (Successor) Proved Reserves Beginning Balance Revision of previous estimates Extensions, discoveries and other additions Sales of reserves in place — — — — Purchases of reserves in place — — — — Production ) ) ) ) Net proved reserves at December 31, 2016 Proved developed reserves, December 31, 2016 Proved undeveloped reserves, December 31, 2016 2017 Proved Reserves Beginning Balance Revision of previous estimates ) ) ) ) Extensions, discoveries and other additions Sales of reserves in place ) ) ) ) Purchases of reserves in place — — — — Production ) ) ) ) Net proved reserves at December 31, 2017 Proved developed reserves, December 31, 2017 Proved undeveloped reserves, December 31, 2017
Schedule of benchmark prices used to determine estimated proved reserves	Successor Predecessor At December 31, At December 31, 2017 2016 2015 Oil and Natural Gas Prices: Oil (per barrel) $ $ $ Natural gas (per million British thermal units) $ $ $
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, 2017, 2016, and 2015 (in thousands): Successor Predecessor At December 31, Year Ended 2017 2016 2015 Future cash inflows $ $ $ Future production costs ) ) ) Future development costs ) ) ) Future income tax expense ) ) — Future net cash flows 10% annual discount for estimated timing of cash flows ) ) ) Standardized measure of discounted future net cash flows $ $ $
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, 2017, the Successor Period, the Predecessor Period and the year ended December 31, 2015 (in thousands): Successor Predecessor Year Ended For the Period October For the Period January Year Ended 2017 December 31, 2016 October 20, 2016 2015 Standardized measure, beginning of period $ $ $ $ Net changes in prices and production costs ) ) Net changes in future development costs ) Sales of oil and natural gas, net ) ) ) ) Extensions Discoveries — — — — Purchases of reserves in place — — — Divestiture of reserves ) — — ) Revisions of previous quantity estimates ) ) ) Previously estimated development costs incurred — Accretion of discount Net change in income taxes ) — Changes in timing, other ) ) ) Standardized measure, end of period $ $ $ $

Selected Quarterly Financial 42

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2017
Selected Quarterly Financial Data
Schedule of selected quarterly financial data	First Second Third Fourth (in thousands, except per share amounts) 2017 (Successor) Total revenues $ $ $ $ Operating income (loss) ) Net income (loss) ) Net income (loss) available to common shareholders ) Net income (loss) per share: Basic and Diluted $ $ $ $ ) Shares used in computation: Basic and Diluted 2016 (Successor) Total revenues $ — $ — $ — $ Operating income — — — Net income — — — Net income available to common shareholders — — — Net income per share: Basic and Diluted $ — $ — $ — $ Shares used in computation: Basic and Diluted — — — 2016 (Predecessor) Total revenues $ $ $ $ Operating income (loss) ) ) ) ) Net income (loss) ) ) Net loss available to common shareholders ) ) Net loss per share: Basic and Diluted $ ) $ $ ) $ Shares used in computation: Basic and Diluted (1) Fourth quarter for the 2016 Predecessor Period is for the period October 1, 2016 through October 20, 2016. Fourth quarter for the 2016 Successor Period is the period October 21, 2016 through December 31, 2016.

Organization and Business (Deta

Organization and Business (Details) $ in Millions	Apr. 21, 2015USD ($)
Predecessor | Dequincy Divestiture
Acquisition information
Net proceeds from sale of ownership interest	$ 42.4

Emergence from Voluntary Reor44

Emergence from Voluntary Reorganization under Chapter 11 Proceedings (Details) - USD ($) $ / shares in Units, $ in Millions	Oct. 21, 2016	Dec. 31, 2017	Oct. 27, 2017	Dec. 31, 2016	Nov. 09, 2016	Oct. 20, 2016	Apr. 30, 2016	Apr. 01, 2016	Jun. 02, 2015	May 21, 2015	May 31, 2013
2016 Reorganization
Common stock, shares issued		25,272,969		24,994,867
Common stock, shares authorized		250,000,000		250,000,000
Preferred stock, shares authorized		50,000,000
Percentage of Management Equity Incentive Plan	10.00%
Common Stock
2016 Reorganization
Common stock, shares issued		25,272,969
Exit Facility
2016 Reorganization
Maximum borrowing capacity		$ 170	$ 170	$ 170
Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | Common Stock
2016 Reorganization
Common stock, shares issued	24,687,500				294,967
Number of shares available for future issuance					17,533
Common stock, shares authorized					250,000,000
Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | Preferred Stock
2016 Reorganization
Preferred stock, shares authorized					50,000,000
Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | Exit Facility
2016 Reorganization
Permanent pay-down	$ 81.3
Anticipated borrowing base after emergence from bankruptcy	170
Maximum borrowing capacity	170						$ 170
2020 Senior Notes | Predecessor
2016 Reorganization
Interest rate (as a percent)									10.75%
2021 Senior Notes | Predecessor
2016 Reorganization
Interest rate (as a percent)									9.25%		9.25%
Second Lien Notes
2016 Reorganization
Permanent pay-down	60
Second Lien Notes | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement
2016 Reorganization
Permanent pay-down	$ 60
Equity allocated to holders of debtors (as a percent)	96.25%
Second Lien Notes | Predecessor
2016 Reorganization
Interest rate (as a percent)										10.00%
Third Lien Notes | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | 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
Warrant strike price (in dollars per share)	$ 24
Warrants expiration term	42 months
Third Lien Notes | Predecessor
2016 Reorganization
Interest rate (as a percent)										12.00%
Unsecured Notes | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | Warrant B
2016 Reorganization
Equity allocated to holders of debtors (as a percent)	1.25%
Warrants to acquire common stock shares (in shares)	2,213,789
Warrant strike price (in dollars per share)	$ 46
Warrants expiration term	42 months
Senior Revolving Credit Facility, due 2018
2016 Reorganization
Permanent pay-down	$ 121.3
Senior Revolving Credit Facility, due 2018 | Predecessor
2016 Reorganization
Maximum borrowing capacity						$ 750		$ 170

Fresh Start Accounting - Valuat

Fresh Start Accounting - Valuation and Properties (Details) $ in Thousands	Oct. 21, 2016USD ($)item	Dec. 31, 2016	Oct. 20, 2016USD ($)	Dec. 31, 2017	Dec. 31, 2015
Fresh start accounting adjustments
Reorganization value	$ 751,300
Valuation of Oil and Gas Properties
Federal statutory rate		35.00%		35.00%
Fresh Start Adjustments
Fresh start accounting adjustments
Enterprise value	$ 600,000
Valuation of Oil and Gas Properties
Escalated inflation (as a percent)	2
Number of guideline Companies used for valuation | item	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
Federal statutory rate	35.00%
Cost of debt after-tax (as a percent)	4.6
Weighted average cost of capital rate (as a percent)	11
Fresh Start Adjustments | Maximum
Fresh start accounting adjustments
Maximum percentage of voting shares of emerging entity to qualify for fresh start accounting (as a percent)	50
Fresh Start Adjustments | Oil and Gas Properties
Valuation of Oil and Gas Properties
Fair value of proved reserves	$ 539,000
Fair value of probable and possible reserves	$ 66,200
Fresh Start Adjustments | Operating and Other Costs
Valuation of Oil and Gas Properties
Escalated inflation (as a percent)	2
Fresh Start Adjustments | General and administrative expense
Valuation of Oil and Gas Properties
Number of years used to forecast historical expenses	5 years
Fresh Start Adjustments | General and administrative expense | Minimum
Valuation of Oil and Gas Properties
Escalated inflation (as a percent)	2
Fresh Start Adjustments | Capital Expenditures
Valuation of Oil and Gas Properties
Escalated inflation (as a percent)	2
Predecessor
Valuation of Oil and Gas Properties
Federal statutory rate			35.00%		35.00%
Bankruptcy Reorganization Chapter 11 | Plan Support Agreement
Fresh start accounting adjustments
Enterprise value	$ 600,000
Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | Minimum
Fresh start accounting adjustments
Enterprise value			$ 500,000
Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | Maximum
Fresh start accounting adjustments
Enterprise value			700,000
Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | Weighted average
Fresh start accounting adjustments
Enterprise value			$ 600,000

Fresh Start Accounting - Enterp

Fresh Start Accounting - Enterprise to FV (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 21, 2016	Dec. 31, 2017	Dec. 31, 2016	Oct. 20, 2016
Fresh start accounting adjustments
Plus: Cash and cash equivalents	$ 76,540	$ 68,498	$ 76,838	$ 76,540
Per share value(in dollars per share)		$ 0.01	$ 0.01
Fresh Start Adjustments
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
Restricted shares granted under 2016 LTIP at October 21, 2016	686,000
Total shares	25,686,000
Per share value(in dollars per share)	$ 19.90
Fresh Start Adjustments | Warrants | Third Lien Notes
Fresh start accounting adjustments
Warrants to acquire common stock shares (in shares)	4,411,765
Aggregate shares of common stock (in shares)	4,411,765
Warrant strike price (in dollars per share)	$ 24
Fresh Start Adjustments | Warrant B | Unsecured Note
Fresh start accounting adjustments
Warrants to acquire common stock shares (in shares)	2,213,789
Aggregate shares of common stock (in shares)	2,213,789
Warrant strike price (in dollars per share)	$ 46

Fresh Start Accounting - Assump

Fresh Start Accounting - Assumptions to estimate FV of Warrants (Details) - Fresh Start Adjustments	Oct. 21, 2016item$ / shares
Assumptions used to estimate fair value of warrants
Risk-free interest rate (as a percent)	2.20%
Warrants
Assumptions used to estimate fair value of warrants
Number of peer companies to estimate volatility | item	6
Warrants | Minimum
Assumptions used to estimate fair value of warrants
Expected volatility (as a percent)	30.10%
Warrants | Maximum
Assumptions used to estimate fair value of warrants
Expected volatility (as a percent)	54.20%
Warrants | 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
Warrants | Unsecured 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)	$ 46
Calculated fair value( in dollars per share)	$ 3.42

Fresh Start Accounting - Ente48

Fresh Start Accounting - Enterprise to Reorg values (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Oct. 21, 2016	Oct. 20, 2016
Fresh start accounting adjustments
Plus: Cash and cash equivalents	$ 68,498	$ 76,838	$ 76,540	$ 76,540
Fresh Start Adjustments
Fresh start accounting adjustments
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 - Balanc

Fresh Start Accounting - Balance sheet effects (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Oct. 21, 2016	Oct. 20, 2016	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 68,498	$ 76,838	$ 76,540	$ 76,540
Accounts receivable:
Oil and gas sales	32,455	36,988	33,895
Joint interest billing	3,297	4,281	4,739
Other	166	2,456	26
Other current assets	1,510	3,326	5,677
Total current assets	106,688	123,889	120,877
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting			619,220
Other property and equipment	6,508	6,339	6,210
Less accumulated depreciation, depletion, amortization and impairment	(204,419)	(12,974)
Net property and equipment	574,462	631,595	625,430
OTHER NONCURRENT ASSETS	6,978	5,455	4,951
TOTAL	688,128	760,939	751,258
CURRENT LIABILITIES:
Accounts payable	11,547	2,521	10,294
Accrued liabilities	42,842	53,731	49,824
Total current liabilities	57,822	56,252	60,118
ASSET RETIREMENT OBLIGATIONS	15,506	14,200	13,983	13,983
OTHER LONG-TERM LIABILITIES	592	614	128,676
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Preferred stock
Warrants			37,329
Common stock	253	250	247
Treasury stock	1,603
Additional paid-in-capital	524,755	514,305	510,905
Retained deficit	(75,147)	9,930
Total stockholders' equity	485,587	561,814	548,481
TOTAL	$ 688,128	$ 760,939	751,258
Reorganization Adjustments
CURRENT ASSETS:
Cash and cash equivalents			(197,990)
Accounts receivable:
Other current assets			(2,748)
Total current assets			(200,738)
PROPERTY AND EQUIPMENT:
OTHER NONCURRENT ASSETS			1,250
TOTAL			(199,488)
CURRENT LIABILITIES:
Accrued liabilities			(15,416)
Debt classified as current			(249,384)
Total current liabilities			(264,800)
OTHER LONG-TERM LIABILITIES			128,059
LIABILITIES SUBJECT TO COMPROMISE			(1,882,187)
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Warrants			37,329
Common stock			247
Treasury stock			3,134
Additional paid-in-capital			510,905
Retained deficit			2,159,221
Total stockholders' equity			1,819,440
TOTAL			(199,488)
Fresh Start Adjustments
CURRENT ASSETS:
Cash and cash equivalents			76,540
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting			(3,176,723)
Other property and equipment			(5,965)
Less accumulated depreciation, depletion, amortization and impairment			3,449,241
Net property and equipment			266,553
TOTAL			266,553
CURRENT LIABILITIES:
ASSET RETIREMENT OBLIGATIONS			(6,385)
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Retained deficit			272,938
Total stockholders' equity			272,938
TOTAL			266,553
Predecessor
CURRENT ASSETS:
Cash and cash equivalents			274,530	76,540	$ 81,093	$ 11,557
Accounts receivable:
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
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
ASSET RETIREMENT OBLIGATIONS			20,368
OTHER LONG-TERM LIABILITIES			617
LIABILITIES SUBJECT TO COMPROMISE			1,882,187
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Common stock			104
Treasury stock			(3,134)
Additional paid-in-capital			891,292
Retained deficit			(2,432,159)
Total stockholders' equity			(1,543,897)	$ (1)	$ (1,326,066)	$ 465,862
TOTAL			684,193
Predecessor | Reorganization Adjustments
STOCKHOLDERS' EQUITY:
Common stock			(104)
Treasury stock			(3,134)
Additional paid-in-capital			$ (891,292)

Fresh Start Accounting - Net ca

Fresh Start Accounting - Net cash payments (Details) - Reorganization Adjustments $ in Thousands	Oct. 21, 2016USD ($)
Fresh start accounting adjustments
Cash pay down of RBL	$ 81,324
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 pay down of RBL	(60,000)
Additional payment to lenders	60,000
Exit Facility
Fresh start accounting adjustments
Additional payment to lenders	$ 40,000

Fresh Start Accounting - Liabil

Fresh Start Accounting - Liabilities subject to compromise (Details) - USD ($) $ in Thousands	Oct. 21, 2016	Dec. 31, 2017	Dec. 31, 2016
Fresh start accounting adjustments
Warrants Issued Value	$ 37,329
Common stock, shares issued		25,272,969	24,994,867
Reorganization Adjustments
Fresh start accounting adjustments
Liabilities subject to compromise	1,882,187
Common stock issued	(511,152)
Permanent pay-down	81,324
Warrants Issued Value	37,329
Write-off of unamortized debt costs associated with RBL	(2,748)
Gain on settlement	$ 1,270,959
Common stock, shares issued	24,687,500
Reorganization Adjustments | Unsecured Note
Fresh start accounting adjustments
Warrants Issued Value	$ (7,575)
Reorganization Adjustments | Second lien notes
Fresh start accounting adjustments
Permanent pay-down	(60,000)
Reorganization Adjustments | Third Lien Notes
Fresh start accounting adjustments
Warrants Issued Value	$ (29,753)

Fresh Start Accounting - Reorga

Fresh Start Accounting - Reorganization adj effects (Details) - USD ($) $ in Thousands	Oct. 21, 2016	Dec. 31, 2017	Dec. 31, 2016
Fresh start accounting adjustments
Common stock-predecessor	$ (247)	$ (253)	$ (250)
Additional paid-in-capital	(510,905)	$ (524,755)	$ (514,305)
Reorganization Adjustments
Fresh start accounting adjustments
Gain on settlement of liabilities subject to compromise	1,270,959
Common stock-predecessor	(247)
Additional paid-in-capital	(510,905)
Predecessor
Fresh start accounting adjustments
Common stock-predecessor	(104)
Treasury stock	(3,134)
Additional paid-in-capital	(891,292)
Predecessor | Reorganization Adjustments
Fresh start accounting adjustments
Gain on settlement of liabilities subject to compromise	1,270,959
Common stock-predecessor	104
Treasury stock	(3,134)
Additional paid-in-capital	891,292
Net impact to Predecessor accumulated deficit	$ 2,159,221

Fresh Start Accounting - Reor53

Fresh Start Accounting - Reorganization property (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Oct. 21, 2016
Fresh start accounting adjustments
Accumulated depreciation, depletion, amortization and impairment	$ 204,419	$ 12,974
Fresh Start Adjustments
Fresh start accounting adjustments
Accumulated depreciation, depletion, amortization and impairment			$ (3,449,241)
Fresh Start Adjustments | Oil and Gas Properties
Fresh start accounting adjustments
Accumulated depreciation, depletion, amortization and impairment			3,400,000
Increase in oil and gas properties			269,700
Decrease in the asset retirement obligation			$ 6,400

Fresh Start Accounting - Reor54

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

Summary of Significant Accoun55

Summary of Significant Accounting Policies (Details)	1 Months Ended	2 Months Ended	10 Months Ended	11 Months Ended	12 Months Ended
	Dec. 31, 2017USD ($)locationitem	Dec. 31, 2016USD ($)location	Oct. 20, 2016USD ($)	Nov. 30, 2017item	Dec. 31, 2017USD ($)locationsegment	Dec. 31, 2015USD ($)	Oct. 21, 2016USD ($)
Policies
Number of Reportable Segments | segment					1
Cash and Cash Equivalents
Cash balance of FDIC insured amount	$ 250,000				$ 250,000
Cash balance of FDIC uninsured amount	70,400,000	$ 78,400,000			70,400,000
Accounts Receivable and Allowance for Doubtful Accounts
Allowance for doubtful accounts	0	$ 0			0
Unevaluated property costs transferred to the full cost pool	58,000,000				58,000,000
Proved Reserves
Provision for price and cost escalations	$ 0				0
Impairments of oil and gas properties					$ 125,300,000
Number of drilling rigs | item	1			2
Revision of Previous Estimates, development plan (in years)		5 years			5 years
Period of reductions lead to reduction of proved undeveloped inventory					5 years
Undeveloped Proved Inventory Location | location	139	274			139
Revision of Previous Estimates, development schedule (in years)		5 years			5 years
Accrued Liabilities
Accrued oil and gas capital expenditures	$ 9,081,000	$ 6,118,000			$ 9,081,000
Accrued revenue and royalty distributions	18,701,000	28,262,000			18,701,000
Accrued lease operating and workover expense	5,150,000	8,932,000			5,150,000
Accrued interest	108,000	254,000			108,000
Accrued taxes	2,758,000	2,537,000			2,758,000
Compensation and benefit related accruals	4,520,000	3,516,000			4,520,000
Other	2,524,000	4,112,000			2,524,000
Accrued liabilities	$ 42,842,000	$ 53,731,000			42,842,000		$ 49,824,000
Predecessor
Proved Reserves
Impairments of oil and gas properties			$ 232,108,000			$ 1,625,776,000
Accrued Liabilities
Accrued liabilities							$ 65,240,000
ASU 2014-09
Recent Accounting Pronouncements
Revenues from oil, natural gas and NGL sales					(15,800,000)
Less: net deductions and expenses					15,800,000
Mississippian | Predecessor
Accounts Receivable and Allowance for Doubtful Accounts
Unevaluated property costs transferred to the full cost pool						56,300,000
Anadarko Basin | Predecessor
Accounts Receivable and Allowance for Doubtful Accounts
Unevaluated property costs transferred to the full cost pool						200,000
Gulf Coast | Predecessor
Accounts Receivable and Allowance for Doubtful Accounts
Unevaluated property costs transferred to the full cost pool						$ 100,000
Carmen and Dacoma
Proved Reserves
Impairments of oil and gas properties					$ 125,300,000
Other Property and Equipment | Minimum
Policies
Estimated useful lives					2 years
Other Property and Equipment | Maximum
Policies
Estimated useful lives					10 years

Fair Value Measurements of Fi56

Fair Value Measurements of Financial Instruments (Details) $ in Thousands	Dec. 31, 2017USD ($)segment
Fair Value Measurements of Financial Instruments
Number of bank counterparties for company's commodity derivative contracts | segment	4
Recurring | Total | Commodity Derivatives
Derivative Assets:
Total assets	$ 4,384
Derivative Liabilities:
Gross Recognized Liabilities	(7,617)
Recurring | Total | Commodity Derivatives | Swaps | Oil
Derivative Liabilities:
Gross Recognized Liabilities	(3,679)
Recurring | Total | Commodity Derivatives | Swaps | Gas
Derivative Assets:
Total assets	821
Recurring | Total | Commodity Derivatives | Collars | Oil
Derivative Assets:
Total assets	952
Derivative Liabilities:
Gross Recognized Liabilities	(2,605)
Recurring | Total | Commodity Derivatives | Collars | Gas
Derivative Assets:
Total assets	2,611
Derivative Liabilities:
Gross Recognized Liabilities	(1,333)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives
Derivative Assets:
Total assets	4,384
Derivative Liabilities:
Gross Recognized Liabilities	(7,617)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Swaps | Oil
Derivative Liabilities:
Gross Recognized Liabilities	(3,679)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Swaps | Gas
Derivative Assets:
Total assets	821
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Collars | Oil
Derivative Assets:
Total assets	952
Derivative Liabilities:
Gross Recognized Liabilities	(2,605)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Collars | Gas
Derivative Assets:
Total assets	2,611
Derivative Liabilities:
Gross Recognized Liabilities	$ (1,333)

Risk Management and Derivativ57

Risk Management and Derivative Instruments- Hedging (Details) - Designated as Hedging Instrument - NYMEX	12 Months Ended
	Dec. 31, 2017MMBTU$ / bbl$ / MMBTUbbl
WTI | Swap Contract Quarter Ended December 31, 2017
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	276,000
Swap weighted average strike price	53.58
WTI | Swap Contract Quarter Ended March 31, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	99,000
Swap weighted average strike price	50.61
WTI | Swap Contract Quarter Ended June 30, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	145,600
Swap weighted average strike price	51.22
WTI | Swap Contract Quarter Ended September 30, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	92,000
Swap weighted average strike price	50.38
WTI | Swap Contract Quarter Ended December 31, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	92,000
Swap weighted average strike price	50.38
WTI | Collar Contract Quarter Ended December 31, 2017
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	46,000
Weighted average ceiling price	60
Weighted average floor price	50
WTI | Three Way Collar Contract Quarter Ended December 31, 2017
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	115,000
Weighted average ceiling price	62.80
Weighted average floor price	50
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended March 31, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	225,000
Weighted average ceiling price	62.14
Weighted average floor price	50
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended June 30, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	182,000
Weighted average ceiling price	60.65
Weighted average floor price	50
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended September 30, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	184,000
Weighted average ceiling price	59.93
Weighted average floor price	50
Weighted average sub-floor price	40
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
WTI | Three Way Collar Contract Quarter Ended March 31, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	45,000
Weighted average ceiling price	56.20
Weighted average floor price	50
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended June 30, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	45,500
Weighted average ceiling price	56.20
Weighted average floor price	50
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended September 30, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	46,000
Weighted average ceiling price	56.20
Weighted average floor price	50
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended December 31, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	46,000
Weighted average ceiling price	56.20
Weighted average floor price	50
Weighted average sub-floor price	40
HENRY HUB | Swap Contract Quarter Ended December 31, 2017
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,907,000
Swap weighted average strike price | $ / MMBTU	3.43
HENRY HUB | Swap Contract Quarter Ended March 31, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,350,000
Swap weighted average strike price | $ / MMBTU	3.47
HENRY HUB | Collar Contract Quarter Ended December 31, 2017
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	551,000
Weighted average ceiling price | $ / MMBTU	3.84
Weighted average floor price | $ / MMBTU	3.23
HENRY HUB | Three Way Collar Contract Quarter Ended December 31, 2017
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	610,000
Weighted average ceiling price | $ / MMBTU	4.30
Weighted average floor price | $ / MMBTU	3.25
Weighted average sub-floor price | $ / MMBTU	2.50
HENRY HUB | Three Way Collar Contract Quarter Ended March 31, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,530,000
Weighted average ceiling price | $ / MMBTU	4.38
Weighted average floor price | $ / MMBTU	3.25
Weighted average sub-floor price | $ / MMBTU	2.50
HENRY HUB | Three Way Collar Contract Quarter Ended June 30, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,365,000
Weighted average ceiling price | $ / MMBTU	3.40
Weighted average floor price | $ / MMBTU	3
Weighted average sub-floor price | $ / MMBTU	2.50
HENRY HUB | Three Way Collar Contract Quarter Ended September 30, 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
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
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

Risk Management and Derivativ58

Risk Management and Derivative Instruments- Balance Sheet Presentation (Details) $ in Thousands	Dec. 31, 2017USD ($)
Total derivative financial instruments - current liabilities	$ (3,433)
Total derivative financial instruments - noncurrent liabilities	(562)
Commodity Derivatives | Not designated as Hedging Instrument
Total derivative financial instruments - current assets	762
Total derivative financial instruments - current liabilities	(3,433)
Total derivative financial instruments - noncurrent liabilities	(562)
Total derivative fair value at period end	(3,233)
Derivative assets:
Gross Recognized Assets	4,384
Gross Amounts Offset, Assets	(3,622)
Net Recognized Fair Value Assets	762
Derivative liabilities:
Gross Recognized Liabilities	(7,617)
Gross Amounts Offset, Liabilities	3,622
Net Recognized Fair Value Liabilities	(3,995)
Current Assets | Commodity Derivatives | Not designated as Hedging Instrument
Derivative assets:
Gross Recognized Assets	3,479
Gross Amounts Offset, Assets	(2,717)
Net Recognized Fair Value Assets	762
Current Assets | Commodity Derivatives | Not designated as Hedging Instrument | Leasehold interest swap | Gas
Total derivative financial instruments - current assets	821
Current Assets | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Oil
Total derivative financial instruments - current assets	(760)
Current Assets | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Gas
Total derivative financial instruments - current assets	701
Non-Current Assets | Commodity Derivatives | Not designated as Hedging Instrument
Derivative assets:
Gross Recognized Assets	905
Gross Amounts Offset, Assets	(905)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument
Derivative liabilities:
Gross Recognized Liabilities	(6,150)
Gross Amounts Offset, Liabilities	2,717
Net Recognized Fair Value Liabilities	(3,433)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Leasehold interest swap | Oil
Total derivative financial instruments - current liabilities	(3,679)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Oil
Total derivative financial instruments - current liabilities	(370)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Gas
Total derivative financial instruments - current liabilities	616
Non-Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument
Derivative liabilities:
Gross Recognized Liabilities	(1,467)
Gross Amounts Offset, Liabilities	905
Net Recognized Fair Value Liabilities	(562)
Non-Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Oil
Total derivative financial instruments - noncurrent liabilities	(523)
Non-Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Gas
Total derivative financial instruments - noncurrent liabilities	$ (39)

Risk Management and Derivativ59

Risk Management and Derivative Instruments - Gain Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2015
Gains (losses) on Commodity Derivative Contracts
Net cash received for commodity derivative contracts	$ (6,891)
Gains (losses) on commodity derivative contracts - net	3,659
Not designated as Hedging Instrument
Gains (losses) on Commodity Derivative Contracts
Net cash received for commodity derivative contracts	6,891
Unrealized net losses	(3,232)
Gains (losses) on commodity derivative contracts - net	$ 3,659
Predecessor
Gains (losses) on Commodity Derivative Contracts
Net cash received for commodity derivative contracts		$ (167,669)
Gains (losses) on commodity derivative contracts - net		40,960
Predecessor | Not designated as Hedging Instrument
Gains (losses) on Commodity Derivative Contracts
Net cash received for commodity derivative contracts		167,669
Unrealized net losses		(126,709)
Gains (losses) on commodity derivative contracts - net		$ 40,960

Property and Equipment (Details

Property and Equipment (Details) $ in Thousands	Jul. 26, 2017USD ($)	Dec. 31, 2016USD ($)$ / Boe	Oct. 20, 2016USD ($)$ / Boe	Dec. 31, 2017USD ($)$ / Boe	Dec. 31, 2015USD ($)$ / Boe	Oct. 21, 2016USD ($)
Oil and gas properties, on the basis of full cost accounting
Proved properties		$ 573,150		$ 765,308
Unproved properties not being amortized		65,080		7,065
Other property and equipment		6,339		6,508		$ 6,210
Less accumulated depreciation, depletion, amortization and impairment		(12,974)		(204,419)
Net property and equipment		631,595		574,462		625,430
Other information
Capitalized qualifying share-based compensation expense		637		1,995
Proceeds from the sale of oil and gas equipment				4,235
Oil and Gas Properties
Other information
Depletion expense related to oil and gas properties		$ 12,600		$ 63,400
Depletion expense (per Boe) | $ / Boe		7		7.85
Costs capitalized to unevaluated properties		$ 700		$ 2,400
Internal costs capitalized to oil and gas properties		1,400		5,300
Capitalized qualifying share-based compensation expense		600		2,000
Gain or loss recognized on disposal of certain oil and gas equipment				0
Oil and Gas Properties | Disposed of by sale
Other information
Proceeds from the sale of oil and gas equipment				1,400
Oil and Gas Properties | Property at Lincoln County, Oklahoma | Disposed of by sale
Other information
Proceeds from the sale of oil and gas equipment	$ 7,000
Net proceeds from the sale of oil and gas equipment	$ 2,900
Other Property and Equipment
Other information
Depreciation		$ 400		$ 2,400
Predecessor
Oil and gas properties, on the basis of full cost accounting
Other property and equipment						12,175
Less accumulated depreciation, depletion, amortization and impairment						(3,449,241)
Net property and equipment						$ 358,877
Other information
Capitalized qualifying share-based compensation expense			$ 476		$ 1,347
Proceeds from the sale of oil and gas equipment					42,366
Predecessor | Oil and Gas Properties
Other information
Depletion expense related to oil and gas properties			$ 59,900		$ 195,200
Depletion expense (per Boe) | $ / Boe			6.84		16.26
Costs capitalized to unevaluated properties					$ 4,900
Internal costs capitalized to oil and gas properties			$ 3,400		7,300
Capitalized qualifying share-based compensation expense			500		1,300
Predecessor | Other Property and Equipment
Other information
Depreciation			$ 2,400		$ 3,500

Acquisition and Divestitures 61

Acquisition and Divestitures of Oil and Gas Properties (Details) - USD ($) $ in Thousands	Apr. 21, 2015	Jun. 25, 2014	Jan. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Acquisition of Oil and Gas Properties
Proceeds from the sale of oil and gas properties				$ 4,235
Predecessor
Acquisition of Oil and Gas Properties
Proceeds from the sale of oil and gas properties						$ 42,366
Acquisition and transaction costs						330
Predecessor | Dequincy Divestiture
Acquisition of Oil and Gas Properties
Proceeds from the sale of oil and gas properties	$ 44,000
Net proceeds from sale of ownership interest	42,400
Gain (loss) on divestiture of business recognized	$ 0
Acquisition and transaction costs						$ 300
PetroQuest | Predecessor | Exploration agreement
Acquisition of Oil and Gas Properties
Undivided right, title and interest (as a percent)		50.00%
Cash consideration			$ 3,000
Additional cash consideration			$ 7,000
Additional non-interest consideration		$ 14,000
Unutilized portion of non-interest bearing consideration					$ 4,400

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2017	Dec. 31, 2015
Changes in asset retirement obligations
Asset retirement obligations at beginning of period	$ 13,983		$ 14,200
Liabilities incurred	7		571
Revisions			1,832
Liabilities settled			(744)
Liabilities eliminated through asset sale			(1,453)
Current period accretion expense	210		1,100
Asset retirement obligations at end of year	$ 14,200	$ 13,983	$ 15,506
Predecessor
Changes in asset retirement obligations
Current period accretion expense		$ 1,414		$ 1,610

Debt - Exit Facility (Details)

Debt - Exit Facility (Details) - Exit Facility $ in Millions	May 24, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Oct. 27, 2017USD ($)	May 23, 2017
Debt
Maximum borrowing capacity		$ 170	$ 170	$ 170
Proceeds from revolving credit facility		128.1	$ 128.1
Availability under the facility		$ 40
Weighted-average interest rate (as a percent)		6.30%	5.50%
Unamortized debt issuance costs		$ 1.2	$ 1.2
Commitment fee (as a percent)		0.50
Removal of cash collateral account amount with administrative agent	$ 40
Percentage of mortgage threshold	90.00%				95.00%
LIBOR Loans
Debt
Interest rate added to base rate (as a percent)		4.50%
LIBOR floor rate		1.00%
Minimum
Debt
Removed liquidity requirement of the then effective borrowing base	20.00%
EBITDA to interest expense coverage ratio		2.50
Maximum
Debt
Total net indebtedness to EBITDA		4
Senior Revolving Credit Facility, due 2018
Debt
Outstanding letters of credit amount		$ 1.9	$ 1.9

Debt - Reorganization (Details)

Debt - Reorganization (Details) - USD ($) $ / shares in Units, $ in Millions	Oct. 21, 2016	Dec. 31, 2017	Oct. 27, 2017	Dec. 31, 2016	Apr. 30, 2016
Second Lien Notes
2016 Reorganization
Permanent pay-down	$ 60
Second Lien Notes | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement
2016 Reorganization
Permanent pay-down	$ 60
Equity allocated to holders of debtors (as a percent)	96.25%
Third Lien Notes | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | 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
Warrant strike price (in dollars per share)	$ 24
Warrants expiration term	42 months
Unsecured Notes | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | Warrant B
2016 Reorganization
Equity allocated to holders of debtors (as a percent)	1.25%
Warrants to acquire common stock shares (in shares)	2,213,789
Warrant strike price (in dollars per share)	$ 46
Warrants expiration term	42 months
Exit Facility
2016 Reorganization
Maximum borrowing capacity		$ 170	$ 170	$ 170
Exit Facility | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement
2016 Reorganization
Permanent pay-down	$ 81.3
Anticipated borrowing base after emergence from bankruptcy	170
Maximum borrowing capacity	$ 170				$ 170

Debt - Debt Restructuring (Deta

Debt - Debt Restructuring (Details) - USD ($) $ in Thousands	Jun. 02, 2015	Jun. 02, 2015	May 21, 2015	Oct. 20, 2016	Dec. 31, 2017	Dec. 31, 2015	May 31, 2013	Oct. 01, 2012
Debt Restructuring
Gain (loss) on restructuring of debt					$ 0
Predecessor
Debt Restructuring
Borrowings						$ 625,000
Repayment of revolving credit facility				$ (121,324)		$ (468,150)
Second Lien Notes | Predecessor
Debt Restructuring
Borrowings			$ 625,000
Principle Balance Outstanding			625,000
Third Lien Notes | Predecessor
Debt Restructuring
Principle Balance Outstanding	$ 20,000	$ 20,000	504,100
2020 Senior Notes | Predecessor
Debt Restructuring
Principal amount extinguished		63,900
Exchanges	306,400	26,600	279,800
Principle Balance Outstanding								$ 600,000
2021 Senior Notes | Predecessor
Debt Restructuring
Principal amount extinguished		70,700
Exchanges	$ 352,300	$ 2,000	$ 350,300
Principle Balance Outstanding							$ 700,000
Unsecured Notes | Predecessor
Debt Restructuring
Percentage of exchanged debt's par value		70.00%	80.00%

Debt - Credit Facilities (Detai

Debt - Credit Facilities (Details) - USD ($) $ in Thousands	Oct. 20, 2016	Jun. 02, 2015	Jun. 02, 2015	May 21, 2015	Feb. 29, 2016	Oct. 20, 2016	Dec. 31, 2015	Oct. 21, 2016	Apr. 01, 2016	May 31, 2013	Oct. 01, 2012
Senior Revolving Credit Facility, due 2018
Debt
Permanent pay-down								$ 121,300
Second Lien Notes
Debt
Permanent pay-down								$ 60,000
Predecessor
Debt
Proceeds from Lines of Credit						$ 249,384	$ 33,000
Predecessor | Senior Revolving Credit Facility, due 2018
Debt
Maximum borrowing capacity	$ 750,000					750,000			$ 170,000
Borrowing base	$ 252,000					$ 252,000
Proceeds from Lines of Credit					$ 249,200
Amount of reduction in borrowing base under exit facility									$ 82,000
Commitment fee, option one (as a percent)	0.375%
Commitment fee, option two (as a percent)	0.50%
Predecessor | Senior Revolving Credit Facility, due 2018 | Minimum | LIBOR Loans
Debt
Interest rate added to base rate (as a percent)	2.00%
Predecessor | Senior Revolving Credit Facility, due 2018 | Maximum | LIBOR Loans
Debt
Interest rate added to base rate (as a percent)	3.00%
Predecessor | 2020 Senior Notes
Debt
Aggregate principal amount borrowed											$ 600,000
Exchanges		$ 306,400	$ 26,600	$ 279,800
Interest rate (as a percent)		10.75%	10.75%
Predecessor | 2021 Senior Notes
Debt
Aggregate principal amount borrowed										$ 700,000
Exchanges		$ 352,300	$ 2,000	350,300
Interest rate (as a percent)		9.25%	9.25%							9.25%
Predecessor | Second Lien Notes
Debt
Aggregate principal amount borrowed				$ 625,000
Interest rate (as a percent)				10.00%
Predecessor | Third Lien Notes
Debt
Aggregate principal amount borrowed		$ 20,000	$ 20,000	$ 504,100
Interest rate (as a percent)				12.00%
Cash interest rate				10.00%
PIK Interest				2.00%

Preferred Stock (Details)

Preferred Stock (Details) - $ / shares	Oct. 01, 2012	Dec. 31, 2015	Dec. 31, 2017
Series A Preferred Stock
Preferred stock, shares issued			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%
Additional shares of common stock to be issued upon conversion		3,738,424
Number of shares into which each Series A Preferred Share gets converted	11.5

Equity and Share-Based Compen68

Equity and Share-Based Compensation - Common Shares (Details)	Oct. 21, 2016Vote$ / sharesshares	Oct. 20, 2016shares	Dec. 31, 2016$ / sharesshares	Oct. 20, 2016shares	Dec. 31, 2017$ / sharesshares	Dec. 31, 2015shares	Nov. 09, 2016shares	Nov. 08, 2016shares
Common Shares
Common Stock, Shares, Issued			24,994,867		25,272,969
Common stock, shares outstanding			24,994,867		25,173,346
Common stock, shares authorized			250,000,000		250,000,000
Preferred stock, shares authorized					50,000,000
Preferred stock, par value (in dollars per share) | $ / shares					$ 0.01
Common stock, par value (in dollars per share) | $ / shares			$ 0.01		$ 0.01
Aggregate number of common shares outstanding			24,994,867		25,173,346
Bankruptcy Reorganization Chapter 11 | Plan Support Agreement
Common Shares
Number of votes per share entitled to holders | Vote	1
Common Stock
Common Shares
Common Stock, Shares, Issued					25,272,969
Common stock, shares outstanding					25,173,346
Aggregate number of common shares outstanding					25,173,346
Changes in number of shares outstanding
Share count at the beginning of the period (in shares)			24,687,500		24,994,867
Issuance of successor common stock (in shares)			307,367
Grants of restricted stock (in shares)					278,102
Share count at the end of the period (in shares)	24,687,500		24,994,867		25,272,969
Common Stock | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement
Common Shares
Common Stock, Shares, Issued	24,687,500						294,967
Number of shares available for future issuance							17,533
Common stock, shares authorized							250,000,000
Common stock, par value (in dollars per share) | $ / shares	$ 0.01
Common Stock | Employee And Non Employee Directors
Common Shares
Common Stock, Shares, Issued								12,400
Preferred Stock | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement
Common Shares
Preferred stock, shares authorized							50,000,000
Preferred stock, par value (in dollars per share) | $ / shares	$ 0.01
Treasury Stock
Changes in number of shares outstanding
Acquisition of treasury stock (in shares)					(99,623)
Share count at the end of the period (in shares)					(99,623)
Predecessor | Common Stock
Changes in number of shares outstanding
Share count at the beginning of the period (in shares)	10,914,780			10,962,105		7,049,173
Issuance of successor common stock (in shares)	24,687,500
Grants of restricted stock (in shares)						268,677
Forfeitures of restricted stock (in shares)				(47,325)		(94,159)
Fractional share adjustment due to reverse stock split (in shares)						(10)
Issuance of common stock for Series A Preferred Stock conversion (in shares)						3,738,424
Cancellation of common stock (in shares)		(10,914,780)
Share count at the end of the period (in shares)		10,914,780		10,914,780		10,962,105
Predecessor | Treasury Stock
Changes in number of shares outstanding
Treasury Stock, Shares, Beginning Balance	(148,649)			(96,291)		(53,467)
Acquisition of treasury stock (in shares)				(52,358)		(42,824)
Cancellation of treasury stock (in shares)		148,649
Treasury Stock, Shares, Ending Balance		(148,649)		(148,649)		(96,291)

Equity and Share-Based Compen69

Equity and Share-Based Compensation - Warrants (Details) - Bankruptcy Reorganization Chapter 11 - Plan Support Agreement	Oct. 21, 2016$ / sharesshares
Unsecured Note | Warrant B
Warrants
Number of warrants issued (in shares)	2,213,789
Warrants to acquire common stock shares (in shares)	2,213,789
Warrant strike price (in dollars per share) | $ / shares	$ 46
Third Lien Notes | Warrants
Warrants
Number of warrants issued (in shares)	4,411,765
Warrants to acquire common stock shares (in shares)	4,411,765
Warrant strike price (in dollars per share) | $ / shares	$ 24

Equity and Share-Based Compen70

Equity and Share-Based Compensation - Emergence from Bankruptcy and 2016 Long Term Incentive Plan (Details) - USD ($) $ in Thousands	Oct. 21, 2016	Dec. 31, 2016	Dec. 31, 2017
Share-Based Compensation
Share-based compensation costs recognized		$ 2,909	$ 9,196
2016 LTIP
Share-Based Compensation
Number of shares available for future issuance	3,513,950
Number of shares authorized			2,129,011
Bankruptcy Reorganization Chapter 11 | Plan Support Agreement
Share-Based Compensation
Share-based compensation costs recognized	$ 1,300

Equity and Share-Based Compen71

Equity and Share-Based Compensation - Restricted Stock Units (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 21, 2017	Oct. 21, 2016	Oct. 20, 2016	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2017	Sep. 30, 2017	Oct. 20, 2016	Dec. 31, 2017	Dec. 31, 2015
Additional information
Director awards									57,856
Share-based compensation costs recognized				$ 2,909					$ 9,196
Total share-based compensation expense				2,909					9,196
Capitalized qualifying share-based compensation costs to oil and gas properties				$ 637					$ 1,995
Restricted Stock Units
Restricted Stock
Non-vested shares outstanding at the beginning of the period (in shares)					686,324				685,662
Granted (in shares)					2,035				85,389
Vested (in shares)	(109,820)								(335,958)
Forfeited (in shares)					(2,697)				(110,109)
Non-vested shares outstanding at the end of the period (in shares)		686,324		685,662	685,662	324,984			324,984
Weighted Average Grant Date Fair Value
Non-vested shares outstanding at the beginning of the period (in dollars per share)					$ 19.66				$ 19.66
Granted (in dollars per share)					20.97				16.50
Vested (in dollars per share)									19.65
Forfeited (in dollars per share)					19.66				19.66
Non-vested shares outstanding at the end of the period (in dollars per share)		$ 19.66		$ 19.66	$ 19.66	$ 18.84			$ 18.84
Additional information
Vested (in shares)	109,820								335,958
Director awards									57,856
Capitalized qualifying share-based compensation costs to oil and gas properties				$ 400					$ 1,300
Restricted Stock Units | General and administrative expense
Additional information
Share-based compensation costs recognized				$ 1,700					5,800
Restricted Stock Units | Mr. Brace (Former President and CEO)
Additional information
Accelerated compensation expense						$ 1,200	$ 1,200
Restricted Stock Units | 2016 LTIP
Additional information
Unrecognized expense for share-based compensation						$ 3,500			$ 3,500
Weighted-average period for over which unrecognized expense will be recognized									1 year 4 months 24 days
Restricted Stock Units | 2016 LTIP | Employees
Share-Based Compensation
Vesting period									3 years
Predecessor
Additional information
Share-based compensation costs recognized								$ 2,564		$ 4,408
Total share-based compensation expense								2,564		4,408
Capitalized qualifying share-based compensation costs to oil and gas properties								$ 476		$ 1,347
Predecessor | Restricted Stock Units
Restricted Stock
Non-vested shares outstanding at the beginning of the period (in shares)		108,313		108,313				318,031		306,202
Granted (in shares)		686,324								268,677
Vested (in shares)								(162,393)		(162,689)
Forfeited (in shares)			(108,313)					(47,325)		(94,159)
Non-vested shares outstanding at the end of the period (in shares)			108,313					108,313		318,031
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		$ 52.76
Granted (in dollars per share)		$ 19.66								12.29
Vested (in dollars per share)								23.09		54.39
Forfeited (in dollars per share)			$ 20.08					19.02		38.69
Non-vested shares outstanding at the end of the period (in dollars per share)			$ 20.08					$ 20.08		$ 21.46
Additional information
Vested (in shares)								162,393		162,689
Capitalized qualifying share-based compensation costs to oil and gas properties								$ 500		$ 1,300
Predecessor | Restricted Stock Units | Severance
Additional information
Total share-based compensation expense										1,500
Predecessor | Restricted Stock Units | General and administrative expense
Additional information
Share-based compensation costs recognized								$ 2,600		$ 4,400
Awards vesting on the six-month anniversary of the Effective Date | Restricted Stock Units | 2016 LTIP | Employees
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant									16.67%
Awards vesting on the twelve-month anniversary of the Effective Date | Restricted Stock Units | 2016 LTIP | Employees
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant									16.67%
Awards vesting on the twenty four-month anniversary of the Effective Date | Restricted Stock Units | 2016 LTIP | Employees
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant									33.33%
Awards vesting on the thirty six-month anniversary of the Effective Date | Restricted Stock Units | 2016 LTIP | Employees
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant									33.33%

Equity and Share-Based Compen72

Equity and Share-Based Compensation - Stock Options (Details) $ / shares in Units, $ in Thousands	Nov. 01, 2017	Oct. 21, 2017shares	Oct. 21, 2016$ / sharesshares	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2016$ / sharesshares	Dec. 31, 2017USD ($)item$ / sharesshares	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)item$ / sharesshares
Additional information
Share-based compensation costs recognized | $				$ 2,909				$ 9,196
Capitalized qualifying share-based compensation costs to oil and gas properties | $				$ 637				$ 1,995
Stock Options
Weighted average assumptions used to estimate fair value of stock option awards
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 per stock option (in dollars per share)				$ 10.88	$ 10.88	$ 11.43		$ 11.43
Change in expected option life (in years)								2 years
Increase in expense due to change in expected term | $				$ 100				$ 900
Decrease in expense due to change in expected term | $				$ (200)				$ (1,100)
Number of peer companies to estimate volatility | item						6		6
Expected volatility rate, minimum (as a percent)				38.50%				36.90%
Expected volatility rate, maximum (as a percent)				65.90%				68.20%
Additional information
Capitalized qualifying share-based compensation costs to oil and gas properties | $				$ 200				$ 700
Minimum
Weighted Average Exercise Price
Vested and exercisable at end of period (in dollars per share)						$ 19.08		$ 19.08
Maximum
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant	120.00%
Weighted Average Exercise Price
Vested and exercisable at end of period (in dollars per share)						$ 20.97		$ 20.97
2016 LTIP
Weighted Average Remaining Contractual Term (Years)
Vested and exercisable options, aggregate intrinsic value | $						$ 0		$ 0
2016 LTIP | Stock Options
Share-Based Compensation
Vesting period								3 years
Expiration period (in years)								10 years
Options
Stock options outstanding at beginning of period (in shares) | shares					628,468			627,806
Granted (in shares) | shares					2,035			4,000
Vested (in shares) | shares				0
Forfeited (in shares) | shares					(2,697)			(132,283)
Stock options outstanding at end of period (in shares) | shares			628,468	627,806	627,806	245,845		245,845
Vested and exercisable at end of period (in shares) | shares						253,678		253,678
Weighted Average Exercise Price
Stock options outstanding at beginning of period (in dollars per share)					$ 19.66			$ 19.66
Granted (in dollars per share)					20.97			19.08
Forfeited (in dollars per share)					19.66			19.66
Stock options outstanding at end of period (in dollars per share)			$ 19.66	$ 19.66	$ 19.66	$ 19.66		19.66
Vested and exercisable at end of period (in dollars per share)						$ 19.66		$ 19.66
Weighted Average Remaining Contractual Term (Years)
Granted (in years)					8 years 10 months 24 days			9 years 2 months 12 days
Stock options outstanding at end of period (in years)			8 years 9 months 18 days		8 years 9 months 18 days			8 years 10 months 24 days
Vested and exercisable at end of period (in years)								8 years 9 months 18 days
Additional information
Vested (in shares) | shares				0
Unrecognized expense for share-based compensation | $						$ 1,300		$ 1,300
Weighted-average period for over which unrecognized expense will be recognized								1 year 3 months 18 days
2016 LTIP | Stock Options | $19.08-20.97
Options
Vested (in shares) | shares		(109,820)						(253,678)
Exercise price (Lower limit)								$ 19.08
Exercise price (Upper limit)								20.97
Weighted Average Exercise Price
Weighted average vested price of vested options (in dollars per share)								$ 19.66
Additional information
Vested (in shares) | shares		109,820						253,678
Awards vesting on the six-month anniversary of the Effective Date | 2016 LTIP | Stock Options
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant								16.67%
Awards vesting on the twelve-month anniversary of the Effective Date | 2016 LTIP | Stock Options
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant								16.67%
Awards vesting on the twenty four-month anniversary of the Effective Date | 2016 LTIP | Stock Options
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant								33.33%
Awards vesting on the thirty six-month anniversary of the Effective Date | 2016 LTIP | Stock Options
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant								33.33%
General and administrative expense | Stock Options
Additional information
Share-based compensation costs recognized | $				$ 800				$ 2,600
Mr. Brace (Former President and CEO) | Stock Options
Additional information
Accelerated compensation expense | $						$ 700	$ 700

Equity and Share-Based Compen73

Equity and Share-Based Compensation - Non-Employee Director Restricted Stock Units Containing a Market Condition (Details) - Restricted Stock Units with Market Condition - Non-employee directors $ / shares in Units, $ in Millions	Nov. 23, 2016	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2017USD ($)item$ / sharesshares
Share-Based Compensation
Trailing average share price period based on common stock (in days)	60 days
Assumptions used to estimate fair value of restricted stock unit awards with market condition
Risk-free interest rate (as a percent)		1.89%	2.06%
Expected volatility (as a percent)		60.00%	54.80%
Market Price Hurdle (in dollars per share)		$ 30	$ 30
Calculated fair value per restricted stock unit (in dollars per share)		$ 17.71	$ 11.54
Number of peer companies to estimate volatility | item			6
Expected volatility rate, minimum (as a percent)		39.80%	55.10%
Expected volatility rate, maximum (as a percent)		61.40%	89.00%
Service period (in years)			1 year
Unrecognized expense for share-based compensation | $			$ 0
Shares
Non-vested shares outstanding at the beginning of the period (in shares) | shares			76,296
Granted (in shares) | shares		76,296
Non-vested shares outstanding at the end of the period (in shares) | shares		76,296	76,296
Weighted Average Grant Date Fair Value
Non-vested shares outstanding at the beginning of the period (in dollars per share)			$ 17.71
Granted (in dollars per share)		$ 17.71
Non-vested shares outstanding at the end of the period (in dollars per share)		$ 17.71	$ 17.71
Accrued liabilities
Assumptions used to estimate fair value of restricted stock unit awards with market condition
Liability related to market condition awards | $		$ 0.1	$ 0.9

Equity and Share-Based Compen74

Equity and Share-Based Compensation - Chief Executive Officer Restricted Stock Units Containing a Market Condition (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 01, 2017	Dec. 31, 2016	Dec. 31, 2017
Assumptions used to estimate fair value of restricted stock unit awards with market condition
Share-based compensation costs recognized		$ 2,909	$ 9,196
Maximum
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)	120.00%
Restricted Stock Units with Market Condition | Chief Executive Officer
Share-Based Compensation
RSUs granted based on actual TSR (as a percentage)	50.00%
RSUs granted based on relative TSR (as a percentage)	50.00%
Assumptions used to estimate fair value of restricted stock unit awards with market condition
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 per stock option (in dollars per share)	$ 10.92
Service period (in years)	3 years
Unrecognized expense for share-based compensation			$ 1,400
Weighted-average period for over which unrecognized expense will be recognized			2 years 9 months 18 days
Restricted Stock
Granted (in shares)			135,778
Non-vested shares outstanding at the end of the period (in shares)			135,778
Weighted Average Grant Date Fair Value
Granted (in dollars per share)			$ 10.92
Non-vested shares outstanding at the end of the period (in dollars per share)			$ 10.92
First 50% of RSUs granted based on actual TSR | Chief Executive Officer
Share-Based Compensation
Days considered for calculation of average stock price	20 days
Remaining 50% of RSUs granted based on relative TSR | Chief Executive Officer | 25% or greater CAGR
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)	120.00%
Remaining 50% of RSUs granted based on relative TSR | Chief Executive Officer | 20% or greater CAGR
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)	100.00%
Remaining 50% of RSUs granted based on relative TSR | Chief Executive Officer | 15% or greater CAGR
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)	50.00%
Remaining 50% of RSUs granted based on relative TSR | Chief Executive Officer | Less than 15% CAGR
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)	0.00%
Remaining 50% of RSUs granted based on relative TSR | Chief Executive Officer | Top 5% or better Relative TSR to Peer Group
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)	120.00%
Remaining 50% of RSUs granted based on relative TSR | Chief Executive Officer | Top 33.5% or Better Relative TSR To Peer Group
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)	100.00%
Remaining 50% of RSUs granted based on relative TSR | Chief Executive Officer | Top 50% or better Relative TSR to Peer Group
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)	50.00%
Remaining 50% of RSUs granted based on relative TSR | Chief Executive Officer | Less than 50% of Relative TSR to Peer Group
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)	0.00%
General and administrative expense | Restricted Stock Units with Market Condition | Chief Executive Officer
Assumptions used to estimate fair value of restricted stock unit awards with market condition
Share-based compensation costs recognized			$ 100

Equity and Share-Based Compen75

Equity and Share-Based Compensation - Unrestricted Common Share Awards (Details) - USD ($) $ in Thousands	Nov. 07, 2016	Dec. 31, 2016	Dec. 31, 2017
Share-Based Compensation
Share-based compensation costs recognized		$ 2,909	$ 9,196
Unrestricted Common Share Awards | Employees and non-employee directors
Share-Based Compensation
Granted (in shares)	12,400
Share-based compensation costs recognized		200
Unrecognized expense for share-based compensation		$ 0	$ 0

Equity and Share-Based Compen76

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, 2017	Dec. 31, 2015
Stock-Based Compensation Expense Summary
Total stock-based compensation	$ 3,546		$ 11,191
Less: amounts capitalized to oil and natural gas properties	(637)		(1,995)
Net stock-based compensation	2,909		9,196
Restricted Stock Units
Stock-Based Compensation Expense Summary
Total stock-based compensation	2,114		7,083
Less: amounts capitalized to oil and natural gas properties	(400)		(1,300)
Stock Options
Stock-Based Compensation Expense Summary
Total stock-based compensation	1,046		3,289
Less: amounts capitalized to oil and natural gas properties	(200)		(700)
Restricted Stock Units with Market Condition | Non-employee directors
Stock-Based Compensation Expense Summary
Total stock-based compensation	142		736
Restricted Stock Units with Market Condition | Chief Executive Officer
Stock-Based Compensation Expense Summary
Total stock-based compensation			$ 83
Unrestricted Common Share Awards
Stock-Based Compensation Expense Summary
Total stock-based compensation	$ 244
Predecessor
Stock-Based Compensation Expense Summary
Total stock-based compensation		$ 3,040		$ 5,755
Less: amounts capitalized to oil and natural gas properties		(476)		(1,347)
Net stock-based compensation		2,564		4,408
Predecessor | Restricted Stock Units
Stock-Based Compensation Expense Summary
Total stock-based compensation		3,040		5,755
Less: amounts capitalized to oil and natural gas properties		$ (500)		$ (1,300)

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Oct. 20, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes
Estimated Amount of Cancellation of Indebtedness Income						$ 1,200,000
Estimated deduction associated with cost of qualified asset		$ 10,900
Valuation allowance	$ 160,789	120,091			$ 120,091	160,789
Valuation allowance related to property and equipment		72,600			72,600
Increase in valuation allowance					32,500
Decrease in valuation allowance due to Tax act					73,200
Income tax payments expected in the upcoming four quarterly reporting periods					0
Reconciliation of income tax expense
Income (loss) before taxes	$ 9,930				$ (85,077)
Statutory rate	35.00%				35.00%
Income tax provision (benefit) computed at statutory rate	$ 3,475				$ (29,777)
Reconciling items:
State income taxes, net of federal benefit	296				(2,864)
Change in valuation allowance	(3,876)				(40,700)
Adjustment to deferred tax assets and liabilities for enacted change in federal tax rate					73,182
Change in state rate	(1)				(606)
Deferred tax true-ups	74				(140)
Other, net	32				905
Deferred tax assets
Federal tax loss carryforwards		36,429			36,429
Derivative instruments and other		813			813
State tax loss carryforwards		7,195			7,195
Employee benefit plans	3,649	3,053			3,053	3,649
Oil and gas properties and equipment	157,113	72,568			72,568	157,113
Other	27	33			33	27
Less valuation allowance	$ (160,789)	$ (120,091)			$ (120,091)	$ (160,789)
Predecessor
Deferred
United States							$ (3,864)
State							(5,777)
Total deferred							(9,641)
Total income tax provision (benefit)							(9,641)
Reconciliation of income tax expense
Income (loss) before taxes			$ 1,323,079				$ (1,806,836)
Statutory rate			35.00%				35.00%
Income tax provision (benefit) computed at statutory rate			$ 463,078				$ (632,393)
Reconciling items:
State income taxes, net of federal benefit			39,424				(65,904)
Change in valuation allowance			(528,706)				689,419
Change in state rate			(153)				(612)
Bankruptcy items			12,262
Deferred tax true-ups			9,891
Other, net			$ 4,204				(151)
Total income tax provision (benefit)							$ (9,641)
Forecast
Reconciliation of income tax expense
Statutory rate				21.00%

Income (Loss) Per Share (Detail

Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended							10 Months Ended	12 Months Ended		14 Months Ended
	Oct. 20, 2016	Dec. 31, 2016	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Oct. 20, 2016	Dec. 31, 2017	Dec. 31, 2015	Dec. 31, 2017
Income (Loss) Per Share
Net income (loss)		$ 9,930	$ (120,967)	$ 3,663	$ 13,742	$ 18,485					$ (85,077)
Participating securities-non-vested restricted stock		(280)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		$ 9,650	$ (120,967)	$ 3,581	$ 13,382	$ 17,939					$ (85,077)
Common shares outstanding - basic		25,009									25,119
Common shares outstanding - diluted		25,009									25,119
Basic (in dollars per share)		$ 0.39									$ (3.39)
Diluted (in dollars per share)		$ 0.39									$ (3.39)
Shares of common stock to be issued by required Plan													17,533
Basic and diluted weighted average number of common shares outstanding		25,009,000	25,253,000	25,116,000	25,093,000	25,012,000					25,119,000
Basic and diluted net income (loss) per share attributable to common shareholders		$ 0.39	$ (4.78)	$ 0.14	$ 0.53	$ 0.72					$ (3.39)
Directors shares for calculation of earnings per share											57,856
Stock Options
Income (Loss) Per Share
Antidilutive securities (in shares)		627,000									466,000
Warrants
Income (Loss) Per Share
Antidilutive securities (in shares)		6,626,000									6,626,000
Predecessor
Income (Loss) Per Share
Net income (loss)	$ 1,531,775						$ (38,384)	$ 8,962	$ (179,274)	$ 1,323,079		$ (1,797,195)
Preferred Dividend												(948)
Net income (loss) attributable to shareholders										1,323,079		(1,798,143)
Participating securities-non-vested restricted stock										(16,522)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 1,515,351						$ (38,384)	$ 8,864	$ (179,274)	$ 1,306,557		$ (1,798,143)
Basic and diluted weighted average number of common shares outstanding	10,657,000						10,657,000	10,653,000	10,621,000	10,645,000		7,726,000
Basic and diluted net income (loss) per share attributable to common shareholders	$ 142.19						$ (3.60)	$ 0.83	$ (16.88)	$ 122.74		$ (232.74)

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenue | Purchaser one
Concentrations of Credit Risk
Concentration risk (as a percent)	40.00%		37.00%
Revenue | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)	29.00%		25.00%
Revenue | Purchaser three
Concentrations of Credit Risk
Concentration risk (as a percent)			14.00%
Accounts receivable | Purchaser one
Concentrations of Credit Risk
Concentration risk (as a percent)			42.00%	44.00%
Accounts receivable | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)			35.00%	26.00%
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%			43.00%
Predecessor | Revenue | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)		29.00%			25.00%

Commitments and Contingencies80

Commitments and Contingencies (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2017	Dec. 31, 2015
Net minimum commitments
2,018			$ 654
2,019			665
2,020			678
2,021			690
2022 and beyond			3,302
Total			5,989
Office rent	$ 100		600
Loss Contingency Accrual	$ 1,100		1,100
Non-cancellable office lease commitments
Net minimum commitments
2,018			654
2,019			665
2,020			678
2,021			690
2022 and beyond			3,302
Total			5,989
Insurance Claims
Net minimum commitments
Insurance reimbursement claim			$ 1,900
Predecessor
Net minimum commitments
Office rent		$ 4,300		$ 2,300

Supplemental Information to C81

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, 2017	Dec. 31, 2015
SUPPLEMENTAL INFORMATION:
Non-cash investment in property and equipment	$ 8,135		$ 17,164
Cash paid for interest, net of capitalized interest for the year ended December 31, 2017, Successor Period and the year ended December 31, 2015 of $2.4 million, $0.7 million and $4.9 million, respectively (no capitalized interest for the Predecessor Period)	426		5,353
Capitalized interest	$ 700		$ 2,400
Predecessor
SUPPLEMENTAL INFORMATION:
Non-cash investment in property and equipment		$ 12,995		$ 21,507
Non-cash exchange of third lien notes for 2020 senior notes and 2021 senior notes				524,121
Cash paid for interest, net of capitalized interest for the year ended December 31, 2017, Successor Period and the year ended December 31, 2015 of $2.4 million, $0.7 million and $4.9 million, respectively (no capitalized interest for the Predecessor Period)		6,709		161,285
Cash paid for reorganization items		36,325
Capitalized interest				4,900
Predecessor | Dequincy Divestiture
SUPPLEMENTAL INFORMATION:
Asset retirement obligation disposed				$ (4,699)
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
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

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2017	Dec. 31, 2015	Oct. 21, 2016
Related Party Transactions
Accounts payable	$ 2,521		$ 11,547		$ 10,294
EcoStim
Related Party Transactions
Percentage of outstanding membership interest of related party in another related party			25.40%
EcoStim | Well stimulation and completion services
Related Party Transactions
Accounts payable			$ 2,100
Amount paid to related party	$ 0		$ 11,600
Predecessor
Related Party Transactions
Accounts payable					$ 10,294
Predecessor | EcoStim | Well stimulation and completion services
Related Party Transactions
Amount paid to related party		$ 0		$ 0
Predecessor | Dixie Electric | Electrical equipment and related services
Related Party Transactions
Amount paid to related party		$ 1,700		$ 0

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent event $ in Millions	Jan. 24, 2018USD ($)
Subsequent Events
Severance costs	$ 1.6
2016 LTIP
Subsequent Events
Costs incurred due to vesting of shares granted to employees	$ 1.4

Supplemental Oil and Gas Disc84

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, 2017	Dec. 31, 2015
Acquisition costs:
Unproved properties	$ 1,430		$ 11,964
Development costs	17,708		128,424
Total costs incurred	19,138		140,388
General and administrative expense
Acquisition costs:
Development costs	1,400		5,300
Capitalized interest expenses
Acquisition costs:
Development costs	$ 700		$ 2,400
Predecessor
Acquisition costs:
Unproved properties		$ 6,869		$ 8,448
Development costs		121,668		274,978
Total costs incurred		128,537		283,426
Predecessor | General and administrative expense
Acquisition costs:
Development costs		$ 3,400		7,300
Predecessor | Capitalized interest expenses
Acquisition costs:
Development costs				$ 4,900

Supplemental Oil and Gas Disc85

Supplemental Oil and Gas Disclosures (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Capitalized Costs, Net
Proved properties	$ 765,308	$ 573,150
Unproved properties not being amortized	7,065	65,080
Gross capitalized costs	772,373	638,230
Less: Accumulated depreciation, depletion, amortization and impairment	(201,722)	(12,587)
Net capitalized costs	570,651	$ 625,643
Mississippian Lime area
Capitalized Costs, Net
Unproved properties not being amortized	$ 7,100
Maximum period considered for depletion (in years)	5 years

Supplemental Oil and Gas Disc86

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, 2017MBoeMMcfMBbls	Dec. 31, 2015MBoeMMcfMBbls
Proved Reserves, Total
Beginning Balance | MBoe	65,318		176,988
Revision of previous estimates | MBoe	55,172		(76,350)
Extensions, discoveries and other additions | MBoe	58,296		18,464
Sales of reserves in place | MBoe			(2,071)
Production | MBoe	(1,798)		(8,084)
Net proved reserves | MBoe	176,988	65,318	108,947
Proved developed reserves | MBoe	69,622		64,490
Proved undeveloped reserves | MBoe	107,366		44,457
Oil
Proved Reserves
Beginning Balance	20,226		61,390
Revision of previous estimates	19,137		(33,608)
Extensions, discoveries and other additions	22,571		5,819
Sales of reserves in place			(99)
Production	(544)		(2,368)
Net proved reserves	61,390	20,226	31,134
Proved developed reserves	19,698		17,268
Proved undeveloped reserves	41,692		13,866
NGL
Proved Reserves
Beginning Balance	14,694		36,872
Revision of previous estimates	11,421		(13,010)
Extensions, discoveries and other additions	11,186		4,003
Sales of reserves in place			(723)
Production	(429)		(1,949)
Net proved reserves	36,872	14,694	25,193
Proved developed reserves	16,349		15,464
Proved undeveloped reserves	20,523		9,729
Gas
Proved Reserves
Beginning Balance | MMcf	182,383		472,359
Revision of previous estimates | MMcf	147,688		(178,388)
Extensions, discoveries and other additions | MMcf	147,236		51,849
Sales of reserves in place | MMcf			(7,495)
Production | MMcf	(4,948)		(22,606)
Net proved reserves | MMcf	472,359	182,383	315,719
Proved developed reserves | MMcf	201,454		190,550
Proved undeveloped reserves | MMcf	270,905		125,169
Predecessor
Proved Reserves, Total
Beginning Balance | MBoe	65,318	73,540		153,744
Revision of previous estimates | MBoe		(3,706)		(75,700)
Extensions, discoveries and other additions | MBoe		4,249		6,398
Sales of reserves in place | MBoe				(5,019)
Purchases of reserves in place | MBoe				6,118
Production | MBoe		(8,765)		(12,001)
Net proved reserves | MBoe		65,318		73,540
Proved developed reserves | MBoe		65,318		69,110
Proved undeveloped reserves | MBoe				4,430
Predecessor | Oil
Proved Reserves
Beginning Balance	20,226	24,713		58,242
Revision of previous estimates		(3,089)		(30,490)
Extensions, discoveries and other additions		1,566		2,189
Sales of reserves in place				(2,871)
Purchases of reserves in place				2,437
Production		(2,964)		(4,794)
Net proved reserves		20,226		24,713
Proved developed reserves		20,226		23,006
Proved undeveloped reserves				1,707
Predecessor | NGL
Proved Reserves
Beginning Balance	14,694	16,245		32,528
Revision of previous estimates		(459)		(15,495)
Extensions, discoveries and other additions		840		1,371
Sales of reserves in place				(843)
Purchases of reserves in place				1,157
Production		(1,932)		(2,473)
Net proved reserves		14,694		16,245
Proved developed reserves		14,694		15,376
Proved undeveloped reserves				869
Predecessor | Gas
Proved Reserves
Beginning Balance | MMcf	182,383	195,492		377,845
Revision of previous estimates | MMcf		(946)		(178,287)
Extensions, discoveries and other additions | MMcf		11,052		17,026
Sales of reserves in place | MMcf				(7,834)
Purchases of reserves in place | MMcf				15,145
Production | MMcf		(23,215)		(28,403)
Net proved reserves | MMcf		182,383		195,492
Proved developed reserves | MMcf		182,383		184,365
Proved undeveloped reserves | MMcf				11,127

Supplemental Oil and Gas Disc87

Supplemental Oil and Gas Disclosures (Unaudited) - Revision of Previous Estimates, Extensions, Discoveries and Other Additions and Sales of Reserves in Place (Details) $ in Millions	1 Months Ended	2 Months Ended	10 Months Ended	11 Months Ended	12 Months Ended
	Dec. 31, 2017locationitem	Dec. 31, 2016MBoelocation	Oct. 20, 2016MBoe	Nov. 30, 2017item	Dec. 31, 2017MBoelocation	Dec. 31, 2015USD ($)MMBTUMBoe
Estimated Quantities of Proved Oil and Natural Gas Reserves
Number of drilling rigs | item	1			2
Revision of previous estimates		55,172			(76,350)
Revision of Previous Estimates, development schedule (in years)		5 years			5 years
Revision of Previous Estimates, development plan (in years)		5 years			5 years
Extensions, discoveries and other additions		58,296			18,464
Period of reductions lead to reduction of proved undeveloped inventory					5 years
Undeveloped Proved Inventory Location | location	139	274			139
Extensions, Discoveries and Other Additions, development schedule (in years)		5 years
Extensions, Discoveries and Other Additions, development plan (in years)		5 years
Sales of reserves in place					2,071
Predecessor
Estimated Quantities of Proved Oil and Natural Gas Reserves
Revision of previous estimates			(3,706)			(75,700)
Extensions, discoveries and other additions			4,249			6,398
Sales of reserves in place						5,019
Purchases of reserves in place						6,118
Predecessor | Dequincy Divestiture
Estimated Quantities of Proved Oil and Natural Gas Reserves
Sales of reserves in place						2,307
Predecessor | Mississippian Lime area
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 | Mississippian Lime area | Leasehold interest swap
Estimated Quantities of Proved Oil and Natural Gas Reserves
Sales of reserves in place						2,712

Supplemental Oil and Gas Disc88

Supplemental Oil and Gas Disclosures (Unaudited) - Benchmark Prices Used to Determine Estimated Proved Reserves (Details)	Dec. 31, 2017$ / bbl$ / MMBTU	Dec. 31, 2016$ / bbl$ / MMBTU	Dec. 31, 2015$ / bbl$ / MMBTU
Oil
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
Unweighted average resulting price (in dollars per bbl & British thermal units) | $ / bbl	51.34	42.75
Gas
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
Unweighted average resulting price (in dollars per bbl & British thermal units) | $ / MMBTU	2.98	2.48
Predecessor | Oil
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
Unweighted average resulting price (in dollars per bbl & British thermal units) | $ / bbl			50.28
Predecessor | Gas
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
Unweighted average resulting price (in dollars per bbl & British thermal units) | $ / MMBTU			2.59

Supplemental Oil and Gas Disc89

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows from Projected Production (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Oct. 21, 2016	Oct. 20, 2016	Dec. 31, 2015	Dec. 31, 2014
Standardized measure of discounted future net cash flows
Future cash inflows	$ 3,023,929	$ 4,186,389
Future production costs	(1,536,332)	(2,078,640)
Future development costs	(370,972)	(692,533)
Future income tax expense	(16,289)	(106,563)
Future net cash flows	1,100,336	1,308,653
10% annual discount for estimated timing of cash flows	(551,093)	(778,703)
Standardized measure of discounted future net cash flows	$ 549,243	$ 529,950	$ 349,905
Predecessor
Standardized measure of discounted future net cash flows
Future cash inflows					$ 1,902,184
Future production costs					(1,024,314)
Future development costs					(47,532)
Future net cash flows					830,338
10% annual discount for estimated timing of cash flows					(317,519)
Standardized measure of discounted future net cash flows				$ 349,905	$ 512,819	$ 1,873,361

Supplemental Oil and Gas Disc90

Supplemental Oil and Gas Disclosures - 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, 2017	Dec. 31, 2015
Changes in Standardized Measure of Discounted Future Net Cash Flows
Standardized measure, beginning of period			$ 529,950
Net changes in prices and production costs	$ 78,103		173,991
Net changes in future development costs	2,022		(29,711)
Sales of oil and natural gas, net	(27,292)		(148,746)
Extensions	102,087		92,776
Divestiture of reserves			(8,079)
Revisions of previous quantity estimates	102,623		(152,517)
Previously estimated development costs incurred			7,909
Accretion of discount	5,832		57,816
Net change in income taxes	(48,206)		39,316
Changes in timing, other	(35,124)		(13,462)
Standardized measure, end of period	529,950		$ 549,243
Predecessor
Changes in Standardized Measure of Discounted Future Net Cash Flows
Standardized measure, beginning of period	$ 349,905	$ 512,819		$ 1,873,361
Net changes in prices and production costs		(113,313)		(960,245)
Net changes in future development costs		175		57,357
Sales of oil and natural gas, net		(116,043)		(232,630)
Extensions		29,871		38,550
Purchases of reserves in place				34,369
Divestiture of reserves				(77,445)
Revisions of previous quantity estimates		(22,194)		(1,174,997)
Previously estimated development costs incurred		29,975		198,564
Accretion of discount		42,735		238,639
Net change in income taxes				513,024
Changes in timing, other		(14,120)		4,272
Standardized measure, end of period		$ 349,905		$ 512,819

Selected Quarterly Financial 91

Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended							10 Months Ended	12 Months Ended
	Oct. 20, 2016	Dec. 31, 2016	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Oct. 20, 2016	Dec. 31, 2017	Dec. 31, 2015
Total revenues		$ 48,525	$ 53,344	$ 49,715	$ 60,679	$ 65,015					$ 228,753
Operating income (loss)		10,673	(119,238)	5,312	14,970	19,462					(79,494)
Net income (loss)		9,930	(120,967)	3,663	13,742	18,485					(85,077)
Net income (loss) available to common shareholders		$ 9,650	$ (120,967)	$ 3,581	$ 13,382	$ 17,939					$ (85,077)
Net income (loss) per share
Basic and diluted net income (loss) per share		$ 0.39	$ (4.78)	$ 0.14	$ 0.53	$ 0.72					$ (3.39)
Shares used in computation
Basic and diluted weighted average number of common shares outstanding		25,009	25,253	25,116	25,093	25,012					25,119
Predecessor
Total revenues	$ 14,514						$ 64,193	$ 62,559	$ 51,961	$ 193,228		$ 365,145
Operating income (loss)	(4,101)						(12,944)	(52,759)	(135,119)	(204,923)		(1,643,803)
Net income (loss)	1,531,775						(38,384)	8,962	(179,274)	1,323,079		(1,797,195)
Net income (loss) available to common shareholders	$ 1,515,351						$ (38,384)	$ 8,864	$ (179,274)	$ 1,306,557		$ (1,798,143)
Net income (loss) per share
Basic and diluted net income (loss) per share	$ 142.19						$ (3.60)	$ 0.83	$ (16.88)	$ 122.74		$ (232.74)
Shares used in computation
Basic and diluted weighted average number of common shares outstanding	10,657						10,657	10,653	10,621	10,645		7,726