Amplify Energy (AMPY) 10-K 30 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Mar. 27, 2017	Jun. 30, 2016
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, 2016
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	Smaller Reporting Company
Entity Public Float			$ 1.2
Entity Common Stock, Shares Outstanding		24,994,867
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 76,838
Accounts receivable:
Oil and gas sales	36,988
Joint interest billing	4,281
Other	2,456
Other current assets	3,326
Total current assets	123,889
PROPERTY AND EQUIPMENT:
Proved properties	573,150
Unproved properties not being amortized	65,080
Other property and equipment	6,339
Less accumulated depreciation, depletion, amortization and impairment	(12,974)
Net property and equipment	631,595
OTHER NONCURRENT ASSETS	5,455
TOTAL	760,939
CURRENT LIABILITIES:
Accounts payable	2,521
Accrued liabilities	53,731
Total current liabilities	56,252
LONG-TERM LIABILITIES:
Asset retirement obligations	14,200
Long-term debt	128,059
Other long-term liabilities	614
Total long-term liabilities	142,873
COMMITMENTS AND CONTINGENCIES (Note 16)
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred stock
Warrants	37,329
Common stock	250
Additional paid-in-capital	514,305
Retained earnings (deficit)	9,930
Total stockholders' equity (deficit)	561,814
TOTAL	760,939
Predecessor
CURRENT ASSETS:
Cash and cash equivalents		$ 81,093
Accounts receivable:
Oil and gas sales		33,656
Joint interest billing		12,503
Other		17,506
Other current assets		1,044
Total current assets		145,802
PROPERTY AND EQUIPMENT:
Proved properties		3,666,403
Other property and equipment		14,798
Less accumulated depreciation, depletion, amortization and impairment		(3,157,332)
Net property and equipment		523,869
OTHER NONCURRENT ASSETS		9,496
TOTAL		679,167
CURRENT LIABILITIES:
Accounts payable		1,904
Accrued liabilities		91,712
Debt classified as current less unamortized debt issuance costs		1,890,944
Total current liabilities		1,984,560
LONG-TERM LIABILITIES:
Asset retirement obligations		18,708
Other long-term liabilities		1,965
Total long-term liabilities		20,673
COMMITMENTS AND CONTINGENCIES (Note 16)
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred stock
Common stock		110
Treasury stock		(3,081)
Additional paid-in-capital		888,247
Retained earnings (deficit)		(2,211,342)
Total stockholders' equity (deficit)		(1,326,066)
TOTAL		679,167
Predecessor | Preferred Stock
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred stock
Predecessor | Series A Preferred Stock
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred stock

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016
Common stock, par value (in dollars per share)		$ 0.01
Common stock, shares authorized		250,000,000
Common stock, shares issued		24,994,867
Common stock, shares outstanding		24,994,867
Warrants outstanding		6,625,554
Preferred Stock
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
Predecessor
Common stock, par value (in dollars per share)	$ 0.01
Common stock, shares authorized	100,000,000
Common stock, shares issued	10,962,105
Common stock, shares outstanding	10,865,814
Predecessor | Preferred Stock
Preferred stock, par value (in dollars per share)	$ 0.01
Preferred stock, shares authorized	49,675,000
Preferred stock, shares issued	0
Preferred stock, shares outstanding	0
Predecessor | Series A Preferred Stock
Preferred stock, par value (in dollars per share)	$ 0.01
Preferred stock, cumulative dividends (as a percent)	8.00%
Preferred stock, shares issued	0
Preferred stock, shares outstanding	0

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, 2015	Dec. 31, 2014
REVENUES :
Oil sales	$ 25,549
Natural gas liquid sales	8,391
Natural gas sales	13,635
Other	950
Total revenues	48,525
EXPENSES :
Lease operating and workover	15,324
Gathering and transportation	3,194
Severance and other taxes	1,286
Asset retirement accretion	210
Depreciation, depletion, and amortization	12,974
General and administrative	4,864
Total expenses	37,852
OPERATING INCOME (LOSS)	10,673
OTHER INCOME (EXPENSE):
Interest expense-net of amounts capitalized (Predecessor Period excludes interest expense of $89.5 million on senior and secured notes)	(743)
Total other income (expense)	(743)
INCOME (LOSS) BEFORE TAXES	9,930
NET INCOME (LOSS)	9,930
Participating securities - non-vested restricted stock	(280)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 9,650
Basic and diluted net loss per share attributable to common shareholders	$ 0.39
Basic and diluted weighted average number of common shares outstanding (Note 14)	25,009
Predecessor
REVENUES :
Oil sales		$ 112,628	$ 217,636	$ 466,655
Natural gas liquid sales		27,473	38,249	87,771
Natural gas sales		48,318	66,823	99,204
Gains on commodity derivative contracts - net			40,960	139,189
Other		4,809	1,477	1,364
Total revenues		193,228	365,145	794,183
EXPENSES :
Lease operating and workover		52,803	81,473	79,598
Gathering and transportation		14,362	15,546	13,404
Severance and other taxes		5,210	8,605	24,266
Asset retirement accretion		1,414	1,610	1,706
Depreciation, depletion, and amortization		62,302	198,643	269,935
Impairment in carrying value of oil and gas properties		232,108	1,625,776	86,471
General and administrative		22,362	38,703	48,733
Acquisition and transaction costs			330	4,129
Debt restructuring costs and advisory fees		7,590	36,141
Other			2,121	5,108
Total expenses		398,151	2,008,948	533,350
OPERATING INCOME (LOSS)		(204,923)	(1,643,803)	260,833
OTHER INCOME (EXPENSE):
Interest income		81	115	39
Interest expense-net of amounts capitalized (Predecessor Period excludes interest expense of $89.5 million on senior and secured notes)		(66,360)	(163,148)	(137,548)
Reorganization items, net (Note 3)		(1,594,281)
Total other income (expense)		1,528,002	(163,033)	(137,509)
INCOME (LOSS) BEFORE TAXES		1,323,079	(1,806,836)	123,324
Income tax benefit			9,641	(6,395)
NET INCOME (LOSS)		1,323,079	(1,797,195)	116,929
Preferred stock dividend			(948)	(10,378)
Participating securities - Series A Preferred Stock				(35,696)
Participating securities - non-vested restricted stock		(16,522)		(3,584)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		$ 1,306,557	$ (1,798,143)	$ 67,271
Basic and diluted net loss per share attributable to common shareholders		$ 122.74	$ (232.74)	$ 10.13
Basic and diluted weighted average number of common shares outstanding (Note 14)		10,645	7,726	6,644

CONSOLIDATED STATEMENTS OF OPE5

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) $ in Millions	10 Months Ended
	Oct. 20, 2016USD ($)
Predecessor
OTHER INCOME (EXPENSE):
Interest expense on senior and secured notes subject to compromise	$ 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, 2013	$ 3	$ 69		$ (664)	$ 871,667	$ (531,076)	$ 339,999
Increase (Decrease) in Stockholders' Equity
Share-based compensation | Predecessor		1			10,861		10,862
Acquisition of treasury stock | Predecessor				(1,928)			(1,928)
Net income (loss) | Predecessor						116,929	116,929
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
Issuance of successor common stock		247			510,905		511,152
Issuance of successor warrants			$ 37,329				37,329
Cancellation of predecessor equity | Predecessor		(104)		3,134	(891,292)	888,263	1
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

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, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 9,930
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Asset retirement accretion	210
Depreciation, depletion, and amortization	12,974
Share-based compensation, net of amounts capitalized to oil and gas properties	2,909
Amortization of deferred financing costs and write-off of debt issuance costs	63
Change in operating assets and liabilities:
Accounts receivable - oil and gas sales	(115)
Accounts receivable - JIB and other	(1,812)
Other current and noncurrent assets	1,783
Accounts payable	(1,555)
Accrued liabilities	(740)
Other	(3)
Net cash provided by operating activities	23,644
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(23,346)
Net cash used in investing activities	(23,346)
CASH FLOWS FROM FINANCING ACTIVITIES:
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	298
Cash and cash equivalents, beginning of period	76,540
Cash and cash equivalents, end of period	76,838	$ 76,540
Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		1,323,079	$ (1,797,195)	$ 116,929
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
(Gains) losses on commodity derivative contracts - net			(40,960)	(139,189)
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments			167,669	(18,332)
Asset retirement accretion		1,414	1,610	1,706
Depreciation, depletion, and amortization		62,302	198,643	269,935
Impairment in carrying value of oil and gas properties		232,108	1,625,776	86,471
Share-based compensation, net of amounts capitalized to oil and gas properties		2,564	4,408	8,618
Deferred income taxes			(9,641)	5,586
Amortization of deferred financing costs and write-off of debt issuance costs		4,587	11,316	7,857
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	33,322
Accounts receivable - JIB and other		22,002	22,833	(18,897)
Other current and noncurrent assets		(5,868)	590	3,191
Accounts payable		1,797	(4,176)	2,327
Accrued liabilities		55,160	(20,887)	(7,733)
Other		(743)	1,095	(247)
Net cash provided by operating activities		61,997	213,383	351,544
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment		(133,307)	(336,922)	(556,397)
Proceeds from the sale of oil and gas properties			42,366	152,133
Net cash used in investing activities		(133,307)	(294,556)	(404,264)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings			625,000
Proceeds from revolving credit facility		249,384	33,000	165,000
Repayment of long-term borrowings		(60,000)
Repayment of revolving credit facility		(121,324)	(468,150)	(131,000)
Deferred financing costs		(1,250)	(4,254)	(958)
Transaction costs for debt restructuring			(34,398)
Acquisition of treasury stock		(53)	(489)	(1,928)
Net cash provided by financing activities		66,757	150,709	31,114
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(4,553)	69,536	(21,606)
Cash and cash equivalents, beginning of period	$ 76,540	81,093	11,557	33,163
Cash and cash equivalents, end of period		$ 76,540	$ 81,093	$ 11,557

Organization and Business

Organization and Business	12 Months Ended
	Dec. 31, 2016
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 March 5, 2014, the Company executed a Purchase and Sale Agreement ("PSA") to sell all of its ownership interest in developed and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer for net proceeds of $147.7 million in cash (the "Pine Prairie Disposition"). Acreage subject to the transaction did not include acreage and production in the western part of Louisiana in Beauregard or Calcasieu Parishes or other undeveloped acreage held outside the Pine Prairie field. The sale closed on May 1, 2014. 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, although it continues to have approximately 4,431 net acres of undeveloped acreage under lease in Louisiana. 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, we filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code. On October 21, 2016, in connection with our emergence from Chapter 11 as discussed further below, our existing common shares traded under the symbol MPOY were cancelled and on October 24, 2016, our new common shares issued in connection with our successful reorganization and emergence from Chapter 11 were listed and began trading on the NYSE MKT under the symbol "MPO".

Emergence from Voluntary Reorga

Emergence from Voluntary Reorganization under Chapter 11 Proceedings	12 Months Ended
	Dec. 31, 2016
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. The Exit Facility has an initial borrowing base of $170.0 million with no borrowing base redeterminations to occur until April 2018 (provided certain conditions are met) and semiannual borrowing base redeterminations each year on April 1 and October 1 thereafter. Until April 2018, unless the borrowing base is redetermined earlier, the amount available to be drawn under the Exit Facility is reduced by $40.0 million, and thereafter, the Company must maintain liquidity (as defined therein) equal to at least 20.0% of the effective borrowing base. In connection therewith, on the Effective Date, the Company made an additional payment of $40.0 million to lenders under its 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, 2016
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 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, to name a few. 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 is 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 1, 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 recorded for October 20, 2016 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, 2016
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 consolidated financial statements as of and for the year ended December 31, 2014 include the results of the Pine Prairie Disposition from January 1, 2014 through May 1, 2014, 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, 2016 and 2015 that exceeded the balance insured by the FDIC in the amount of $78.4 million and $87.2 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, 2016 and 2015, 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 (losses) on commodity derivative contracts—net." The related cash flow impact is reflected within cash flows from operating activities. Other Noncurrent Assets At December 31, 2016 and 2015, other noncurrent assets consisted of the following (in thousands): Successor Predecessor December 31, 2016 December 31, 2015 Deferred financing costs associated with the RBL $ — $ Deferred financing costs associated with the Exit Facility — Field equipment inventory Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Other noncurrent assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Predecessor Period, approximately $4.6 million in deferred financing costs associated with the RBL were impaired. For the year ended December 31, 2015, the Company recorded $2.0 million of losses on the sale of, or market value adjustments to, field equipment inventory. 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, its anticipated drilling plans and uncertainty regarding its ability to finance its future exploration activities at that time. At the Effective Date, the Company recorded $66.2 million in unevaluated property associated with fresh start accounting. See "—Note 3. Fresh Start Accounting" for further information. Oil and Gas Reserves Proved oil, NGLs and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board ("FASB"), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company depletes its oil and gas properties using the units-of-production method. Capitalized costs of oil and natural gas properties subject to amortization are depleted over proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. Impairment of Oil and Gas Properties/Ceiling Test The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit, or ceiling, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization ("DD&A") and the related deferred income taxes, may not exceed this ceiling. The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales prices received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations. For the Predecessor Period, the Company recorded an impairment of oil and gas properties of $232.1 million. For the years ended December 31, 2015 and 2014, the Company recorded impairments of oil and gas properties of $1.6 billion and $86.5 million, respectively. 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 for the Predecessor Period and the years ended December 31, 2015. For the year ended December 31, 2014, the primary factor affecting the impairment related to the transfer of unevaluated property costs to the full cost pool. 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 three to seven years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized. Accrued Liabilities At December 31, 2016 and 2015, accrued liabilities consisted of the following (in thousands): Successor Predecessor December 31, 2016 December 31, 2015 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 estimated fair value 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 fair value 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 a graded 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 and 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 gas revenues, whereby revenue is recognized for all oil, NGLs and 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, 2016, 2015 or 2014. 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 and 2014 relate to the Dequincy Divestiture and the Pine Prairie Disposition, respectively. 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. Earnings (Loss) Per Share Basic earnings (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 earnings (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 earnings per share calculations consist of unvested restricted stock awards, warrants and outstanding stock options for the Successor Period. Potentially dilutive securities for the diluted earnings 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 earnings per share. See "—Note 14. Earnings (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 standard permits the use of either the retrospective or cumulative effect transition method and early adoption is permitted. Currently, the Company has identified the population of contracts and formed an implementation team to determine the Company's implementation timelines, discuss implementation challenges, technical interpretations, industry-specific treatment of certain revenue contract types, and project status. The Company plans to review contracts for each revenue stream identified within the Company's business. Through this process, the Company will determine and document the expected changes in revenue recognition upon adoption of the revised guidance and then evaluate the potential information technology and internal control changes that will be required for adoption based on the findings from the Company's contract review process. The Company will conduct the contract review process throughout 2017 and, as a result, areas of impact may be identified. The Company cannot reasonably quantify the impact of adoption at this time. The Company expects to complete the assessment of ASU 2014-09, including the transition method, in the latter half of 2017. In August 2014, the FASB issued Accountings Standards Update 2014-15, "Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosures of Uncertainties about an Entity's Ability to Continue as a Going Concern" ("ASU 2014-15"). ASU 2014-15 provides guidance about management's responsibility to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern within one year after the date that the financial statements are issued. Certain disclosures are required should substantial doubt exist about the entities ability to continue as a going concern. This evaluation is performed each annual and interim reporting period to assess conditions or events within one year of the date that the financial statements are issued. The new standard was adopted by the Company at December 31, 2016. 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 consolidate 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 and does not expect to move beyond this stage until completion of its evaluation of ASU 2014-09, which is expected to occur in the latter half of 2017. In March 2016, the FASB issued ASU 2016-09, " Compensation—Stock Compensation (Topic 718) " ("ASU 2016-09"). ASU 2016-09 simplifies how certain aspects of share-based payments to employees are recorded. ASU 2016-09 requires that entities recognize the income tax effects of awards in the income statement when the awards vest or are settled, provides guidance on the classification of certain aspects of share-based payments on the statement of cash flows, changes the threshold for awards to qualify for equity classification, and allows an entity to make an accounting policy election to account for forfeitures when they occur. The new standard is effective for the Company beginning on January 1, 2017. As of December 31, 2016, the Company elected to early adopt the pronouncement and it did not have a material impact on its financial results. 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.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	12 Months Ended
	Dec. 31, 2016
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 with fair values based on inputs from actively quoted markets. The Company uses a discounted cash flow approach to estimate the fair values of its commodity derivative contracts, utilizing commodity futures price strips for the underlying commodities provided by a reputable third-party. • 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.

Risk Management and Derivative

Risk Management and Derivative Instruments	12 Months Ended
	Dec. 31, 2016
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 oil, NGLs and natural gas production. The Company has historically utilized various types of derivative financial instruments, including swaps and collars, to manage fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The oil, NGLs and gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that management believes have a high degree of historical correlation with actual prices received by the Company for its oil, NGLs and natural gas production. Although the Company has entered into derivative financial instruments in the past, the Company had no derivatives in place at December 31, 2016. Subsequent to December 31, 2016, the Company entered into various oil and natural gas derivative contracts that extend through March 2018, summarized as follows: Quarter Ended Quarter Ended Quarter Ended Quarter Ended Quarter Ended NYMEX WTI Fixed swaps Hedge position (Bbls) — Weighted average strike price $ $ $ $ $ — Collars Hedge position (Bbls) — Weighted average ceiling price $ $ $ $ $ — Weighted average floor price $ $ $ $ $ — Three way collars Hedge position (Bbls) — — Weighted average ceiling price $ — $ — $ $ $ Weighted average floor price $ — $ — $ $ $ Weighted average sub-floor price $ — $ — $ $ $ NYMEX HENRY HUB Fixed swaps Hedge position (MMBtu) — — Weighted average strike price $ — $ $ $ $ — Collars Hedge position (MMBtu) — — — — Weighted average ceiling price $ $ — $ — $ — $ — Weighted average floor price $ $ — $ — $ — $ — Three way collars Hedge position (MMBtu) — — — Weighted average ceiling price $ — $ — $ — $ $ Weighted average floor price $ — $ — $ — $ $ Weighted average sub-floor price $ — $ — $ — $ $ Commodity Derivative Contracts As of December 31, 2016 and 2015, 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 were 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 (losses) on commodity derivative contracts—net" within revenues in the consolidated statements of operations. The following table presents net cash received (paid) for commodity derivative contracts and unrealized net gains (losses) recorded by the Company related to the change in fair value of the derivative instruments in "Gains (losses) on commodity derivative contracts—net" for the periods presented (in thousands): Successor Predecessor For the Period For the Years Ended For the Period 2015 2014 Net cash received (paid) for commodity derivative contracts $ — $ — $ $ ) Unrealized net gains (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, 2016
Property and Equipment
Property and Equipment	7. Property and Equipment The Company's property and equipment as of December 31, 2016 and 2015 was as follows (in thousands): Successor Predecessor December 31, 2016 December 31, 2015 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 Successor Period and the Predecessor Period, depletion expense related to oil and gas properties was $12.6 million and $59.9 million, respectively and $7.00 and $6.84, per barrel of oil equivalent ("Boe"), respectively. For the years ended December 31, 2015 and 2014, depletion expense related to oil and gas properties was $195.2 million and $266.8 million, respectively and $16.26 and $22.75 per Boe, respectively. For the Successor Period, Predecessor Period and the years ended December 31, 2015 and 2014, depreciation expense related to other property and equipment was $0.4 million, $2.4 million, $3.5 million and $3.1 million, respectively. For the Successor Period and the years ended December 31, 2015 and 2014, interest capitalized to unevaluated properties was $0.7 million, $4.9 million and $12.4 million, respectively. The Company did not capitalized interest for the Predecessor Period. For the Successor Period, Predecessor Period and the years ended December 31, 2015 and 2014, the Company capitalized $1.4 million, $3.4 million, $7.3 million and $12.4 million, respectively, of internal costs to oil and gas properties, including $0.6 million, $0.5 million, $1.3 million and $2.2 million, respectively, of qualifying share based compensation expense, see "—Note 12. Equity and Share Based Compensation".

Acquisition and Divestitures of

Acquisition and Divestitures of Oil and Gas Properties	12 Months Ended
	Dec. 31, 2016
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. Pine Prairie Disposition On May 1, 2014, the Company closed on the sale of all of its ownership interest in developed and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer for a purchase price of $170.0 million in cash ($147.7 million net of standard post-closing adjustments). Acreage subject to the transaction did not include acreage and production in the western part of Louisiana in Beauregard and Calcasieu Parishes or other undeveloped acreage held outside the Pine Prairie field. Proceeds of $131.0 million were used to reduce amounts outstanding under the RBL, with the remainder retained for transaction expenses and working capital purposes. This amount was reflected as a reduction of oil and natural gas properties, with no gain or loss was recognized. 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. For the year ended December 31, 2014, acquisition and transaction costs of $4.1 million were incurred primarily as a result of the Pine Prairie Disposition and include advisory, legal, accounting, valuation and other professional and consulting fees related to the sale.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
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 asset retirement obligation at inception is capitalized as part of the carrying amount of the related long-lived asset. Asset retirement obligations approximated $14.2 million and $18.7 million as of December 31, 2016 and 2015, respectively. At December 31, 2016 and 2015, all asset retirement obligations represent long-term liabilities and are classified as such. The following table details the change in the asset retirement obligations for the Successor Period and the years ended December 31, 2015 and 2014, respectively (in thousands): Successor Predecessor For the Period For the Years Ended 2015 2014 Asset retirement obligations at beginning of period $ $ $ Liabilities incurred Revisions(1) — Liabilities settled — ) ) Liabilities eliminated through asset sale(2) — ) ) Current period accretion expense ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Asset retirement obligations at end of year $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Revisions during the year ended December 31, 2015 were the result of updates to the estimated abandonment dates of various wells. Revisions during the year ended December 31, 2014 were due primarily to an increase in estimated future abandonment costs based upon higher costs for oilfield services and materials in the Mississippian Lime and Anadarko Basin areas. (2) Liabilities eliminated through asset sales for the year ended December 31, 2015 is primarily related to the Dequincy Divestiture. Liabilities eliminated through asset sales for the year ended December 31, 2014 were related to the Pine Prairie Disposition. See discussion of the Dequincy Divestiture and Pine Prairie Disposition in "—Note 8. Acquisition and Divestitures of Oil and Gas Properties".

Debt

Debt	12 Months Ended
	Dec. 31, 2016
Debt
Debt	10. Debt The Company's total debt, including debt classified as current, as of December 31, 2016 and 2015 is as follows (in thousands): Principal Unamortized Deferred Unamortized Debt Total Successor Predecessor Successor Predecessor Successor Predecessor Successor Predecessor 2016 2015 2016 2015 2016(1) 2015 2016 2015 Predecessor Credit Facility $ — $ — $ — $ — $ — $ — $ — $ — Successor Exit Facility — — — — — — 2020 Senior Notes — — — — ) — 2021 Senior Notes — — — — ) — Second Lien Notes — — — — — Third Lien Notes — — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total debt $ $ $ — $ $ — $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Unamortized debt issuance costs of $1.2 million associated with the Exit Facility are included in other noncurrent assets on the consolidated balance sheets. 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 below. 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. Exit Facility At December 31, 2016, the Company maintained the Exit Facility with a borrowing base of $170.0 million with no borrowing base redeterminations to occur until April 2018 (provided certain conditions are met) and semiannual borrowing base redeterminations each year on April 1 and October 1 thereafter. Until April 2018, unless the borrowing base is redetermined earlier, the amount available to be drawn under the Exit Facility is reduced by $40.0 million, and thereafter, the Company must maintain liquidity (as defined therein) equal to at least 20.0% of the effective borrowing base. At December 31, 2016, the Company had $128.1 million drawn on the Exit Facility and had outstanding letters of credit obligations totaling $1.9 million. As a result, at December 31, 2016 the Company had no amount of availability on the Exit Facility. The Exit Facility matures on September 30, 2020 and borrowings thereunder are secured by (i) first-priority mortgages on at least 95% of the Company's oil and gas properties, (ii) all other presently owned or after-acquired property (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing) and (iii) a perfected pledge on all equity interests. The Exit Facility bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. At December 31, 2016, the weighted average interest rate was 5.50%. 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. In addition to the aforementioned liquidity covenant, the Exit Facility, also contains various other financial covenants, including an EBITDA to interest expense coverage ratio limitation of 3.00:1.00, a ratio limitation of Total Net Indebtedness (as defined in the Exit Facility) to EBITDA of not more than 2.25:1.00 through April 1, 2018 and not more than 3.00:1.00 thereafter, and a limitation on Capital Expenditures (as defined) of $50.0 million for the 6 months ended December 31, 2016, $81.0 million for the year ended December 31, 2017, $85.0 million for the year ended December 31, 2018 and $78.0 million for the year ended December 31, 2019. The Exit Facility is also subject to a variety of other terms and conditions including conditions precedent to funding, restrictions on the payment of dividends and various other covenants and representations and warranties. As of December 31, 2016, the Company was in compliance with our debt covenants. The Company believes the carrying amount of the Credit Facility at December 31, 2016 approximates its fair value (Level 2) due to the variable nature of the Exit Facility interest rate. 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, 2016
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, 2016
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 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. At December 31, 2016, the Company had 24,994,867 shares of common stock issued and outstanding. Predecessor Period At December 31, 2015, the Company had 10,962,105 and 10,865,814 shares of its common stock issued and outstanding, respectively. On August 3, 2015, the Company completed a 1-for-10 reverse stock split of its outstanding common stock. To effect the reverse stock split, the Company filed a Certificate of Amendment to the Company's Restated Certificate of Incorporation, which provides for the reverse stock split and for the corresponding reduction in the Company's authorized capital stock to 100 million shares of common stock, $0.01 par value per share, following the reverse stock split. Share Activity The following table summarizes changes in the number of shares of common stock and treasury stock outstanding 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) — (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 the Warrants such that no payment of cash will be required in connection with such exercise (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, restricted stock, performance 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, 2016, 2,111,786 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, Restricted Stock Units, 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, 2016, the Company had 685,662 shares of restricted stock units outstanding to employees and non-employee directors pursuant to the 2016 LTIP, excluding restricted stock units issued to non-employee directors containing a market condition, which are discussed below. Restricted stock units 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 Effective Date, an additional one-sixth will vest on the twelve-month anniversary of the Effective Date, an additional one-third will vest on the twenty-four month anniversary of the Effective Date and the final one-third will vest on the thirty-six month anniversary of the Effective Date. Restricted stock units granted to non-employee directors vest on the first to occur of (i) December 31, 2017, (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. Restricted stock units 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 restricted stock units 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 years ended December 31, 2016, 2015 and 2014: 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) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ On December 31, 2016, the Company elected to early adopt ASU 2016-09 and chose to recognize the effect of awards for which the requisite service is not rendered when the actual award is forfeited. Previously, the Company estimated the forfeiture rate and applied it ratably to expense over the vesting period, recognizing any differences between estimated forfeitures and actual forfeitures at the end of the period. The share-based compensation costs (net of amounts capitalized to oil and gas properties) related to restricted stock units recognized as general and administrative expense by the Company for the Successor Period, Predecessor Period and the years ended December 31, 2015 and 2014, was $1.7 million, $2.6 million, $4.4 million, and $8.6 million, respectively. For the Successor Period, Predecessor Period and the years ended December 31, 2015 and 2014, the Company capitalized $0.4 million, $0.5 million, $1.3 million and $2.2 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 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. For the year ended December 31, 2014, approximately $2.9 million of the $8.6 million in share-based compensation was related to the accelerated vesting. Unrecognized expense as of December 31, 2016 for all outstanding restricted stock units under the 2016 LTIP Plan was $11.4 million and will be recognized over a weighted average period of 1.7 years. Stock Options On December 31, 2016, the Company had 627,806 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 Effective Date, an additional one-sixth will vest on the twelve-month anniversary of the Effective Date, an additional one-third will vest on the twenty four-month anniversary of the Effective Date and the final one-third will vest on the thirty six-month anniversary of the Effective 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 assumptions used to estimate the fair value of stock option awards are as follows: Awards Issued in 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 had no exercise history associated with stock options at the Effective Date, 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. (3) As the Company had no stock option history at the Effective Date, 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 38.5% to 65.9%. The following table summarizes the Company's 2016 LTIP non-vested stock option activity for the year ended December 31, 2016: Options Range of Weighted Weighted Stock options outstanding at October 21, 2016 (Successor) $ $ Granted $ $ Vested — — $ — — Forfeited ) $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Stock options outstanding at December 31, 2016 (Successor) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ On December 31, 2016, the Company elected to early adopt ASU 2016-09 and chose to recognize the effect of awards for which the requisite service is not rendered when the actual award is forfeited. 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 Successor Period was $0.8 million. For the Successor Period, the Company capitalized $0.2 million of qualifying stock option share-based compensation costs to oil and gas properties. Unrecognized expense as of December 31, 2016 for all outstanding stock options was $5.8 million and will be recognized over a weighted average period of 1.8 years. Non-Employee Director Restricted Stock Units Containing a Market Condition On November 23, 2016 the Company issued certain restricted stock units to our non-employee directors that contain a market vesting condition. These restricted stock units 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 restricted stock units 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 prepared by a third party in order to determine the fair value of these awards as of December 31, 2016. The assumptions used to estimate the fair value of restricted stock unit awards with a market condition at December 31, 2016 are as follows: Awards Issued in 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 had no relevant history at the Effective Date, 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 39.8% to 61.4%. The restricted stock unit awards issued to non-employee directors containing a market condition has a derived service period of one year. At December 31, 2016 the Company recorded a $0.1 million liability included within accrued liabilities on the consolidated balance sheet related to the market condition awards. As of December 31, 2016, unrecognized stock-based compensation related to market condition awards was $1.2 million and will be recognized over a weighted-average period of 0.9 years. The following table reflects the outstanding restricted stock unit awards containing a market conditions for the Successor Period: Shares Weighted Average Outstanding at October 21, 2016 (Successor) — $ — Granted $ Vested — $ — Forfeited — $ — ​ ​ ​ ​ ​ ​ ​ ​ Outstanding at December 31, 2016 (Successor) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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, 2016. Stock-Based Compensation Expense Summary The following summarizes stock-based compensation expense for the periods presented (in thousands): Successor Predecessor For the Period For the Years Ended For the Period 2015 2014 Restricted stock units (Predecessor) $ — $ $ $ Restricted stock units (Successor) — — — Stock options (Successor) — — — 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, 2016
Income Taxes
Income Taxes	13. Income Taxes Under the 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 will reduce the value of the Company's U.S. net operating losses and other assets. The actual reduction in tax attributes does not occur until the first day of the Company's tax year subsequent to the date of emergence, or January 1, 2017. The Company anticipates a full reduction of its federal and state NOL carryforwards and a reduction of the tax basis in its fixed assets effective January 1, 2017, pursuant to IRC section 108. The anticipated result of this reduction is reflected in the deferred tax table below. As of December 31, 2016, the Company has recorded a full valuation allowance against its net deferred tax assets of $160.8 million, of which $157.1 million relates to deferred tax assets on the Company's property and equipment. The Company's valuation allowance decreased by $532.6 million from December 31, 2015 to December 31, 2016, which was primarily a result of the reduction in the Company's tax attributes pursuant to IRC Section 108. As of December 31, 2016, the Company has not recorded a reserve for any uncertain tax positions. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company's tax position. No federal income tax payments are expected in the upcoming four quarterly reporting periods. Successor Predecessor For the Period For the Period For the Years Ended 2015 2014 (in thousands) (in thousands) Current United States $ — $ — $ — $ — State — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total current — — — Deferred United States — — ) State — — ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total deferred — — ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total income tax provision (benefit) $ — $ — $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The Company's estimated income tax expense differs from the amount derived by applying the statutory federal rate to pretax income principally due the effect of the following items: Successor Predecessor For the Period For the Period Years Ended 2015 2014 (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 ) ) ) 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): Successor Predecessor As of As of Deferred tax assets—current Derivative instruments and other $ — $ — Less valuation allowance — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total deferred tax assets, current $ — $ — Deferred tax assets—noncurrent Federal tax loss carryforwards — State tax loss carryforwards — Employee benefit plans Oil and gas properties and equipment Debt restructuring — Other — Less valuation allowance ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total deferred tax assets, noncurrent $ — $ — Deferred tax liabilities—current Derivative instruments and other — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total deferred tax liabilities—current $ — $ — Deferred tax liabilities—noncurrent Oil and gas properties and equipment — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total deferred tax liabilities, noncurrent $ — $ — Reflected in the accompanying balance sheet as: Net deferred tax asset, current $ — $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax liability, current $ — $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax asset, noncurrent $ — $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax liability, noncurrent $ — $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Earnings (Loss) Per Share

Earnings (Loss) Per Share	12 Months Ended
	Dec. 31, 2016
Earnings (Loss) Per Share
Earnings (Loss) Per Share	14. Earnings (Loss) Per Share Successor The following table provides a reconciliation of net income attributable to common shareholders and weighted average common shares outstanding for basic and diluted earnings per share for the Successor Period: For the Period (in thousands, except Net Earnings: Net income $ Participating securities—non-vested restricted stock ) ​ ​ ​ ​ ​ Basic and diluted earnings $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Common Shares: Common shares outstanding—basic(1) Dilutive effect of potential common shares — ​ ​ ​ ​ ​ Common shares outstanding—diluted ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net Earnings Per Share: Basic $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Diluted $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Antidilutive stock options(2) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Antidilutive warrants(3) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Weighted-average common shares outstanding for basic and diluted earnings per share purposes includes 17,533 shares of common stock that, while not issued and outstanding at December 31, 2016, are required by the Plan to be issued. (2) Amount represents options to purchase common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive. (3) Amount represents warrants to purchase common stock that are excluded from the diluted net earnings 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 years ended December 31, 2015 and 2014: For the Period Years Ended December 31, 2015 2014 (in thousands, except per share amounts) Net income (loss) $ $ ) $ 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, 2016
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, historically, 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 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. For the year ended December 31, 2014, four purchasers accounted for 28%, 18%, 15% and 12% respectively, of the Company's revenue. Substantially all of the Company's accounts receivable result from the sale of oil, natural gas and natural gas liquids. At December 31, 2016, two purchasers accounted for approximately 44% and 26%, respectively, of the accounts receivable balance. At December 31, 2015, three purchasers accounted for approximately 33%, 29%, and 14%, 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 and had no derivative instruments in place at December 31, 2016 or 2015.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies
Commitments and Contingencies	16. Commitments and Contingencies Contractual Obligations At December 31, 2016, contractual obligations for drilling contracts, long-term operating leases and other contracts are as follows (in thousands): Total 2017 2018 2019 2020 2021 and Drilling contracts $ — $ — $ — $ — $ — $ — Non-cancellable office lease commitments ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net minimum commitments $ $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Successor Period, the Predecessor Period and years ended December 31, 2015 and 2014, the Company expensed $0.1 million, $4.3 million, $2.3 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, 2016 and 2015, the Company's total accrual for all loss contingencies was $1.1 million.

Supplemental Information to Con

Supplemental Information to Consolidated Statement of Cash Flows	12 Months Ended
	Dec. 31, 2016
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 Period Period Years Ended 2015 2014 SUPPLEMENTAL INFORMATION: Non-cash investment in property and equipment $ $ $ $ Non-cash components of Pine Prairie Disposition: —Asset retirement obligation disposed $ — $ — $ — $ ) —Accrual for miscellaneous liabilities assumed $ — $ — $ — $ ) —Other noncurrent assets sold $ — $ — $ — $ 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 Successor Period and the years ended December 31, 2015 and 2014 of $0.7 million, $4.9 million and $12.4 million, respectively (no capitalized interest for the Predecessor Period) $ $ $ $ Cash paid for reorganization items $ — $ $ — $ — Cash paid for taxes $ — $ — $ — $

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions
Related Party Transactions	18. Related Party Transactions 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 Successor Period or the years ended December 31, 2015 and 2014.

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Dec. 31, 2016
Supplemental Oil and Gas Disclosures (Unaudited)
Supplemental Oil and Gas Disclosures (Unaudited)	Note 19. 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 Successor Period, Predecessor Period and years ended December 31, 2015 and 2014 (in thousands): Successor Predecessor For the Period For the Period For the Year 2015 2014 Acquisition costs: Proved properties $ — $ — $ — $ — Unproved properties Exploration costs — — — Development costs ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total costs incurred $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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, 2016 and 2015 (in thousands): Successor Predecessor December 31, 2016 December 31, 2015 Proved properties $ $ Unproved properties not being amortized — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross capitalized costs Less: Accumulated depreciation, depletion, amortization and impairment ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net capitalized costs $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ At December 31, 2016, the Company had $65.1 million of oil and gas property costs that are not being amortized, inclusive of $0.7 million of capitalized interest. The value of the Company's oil and gas properties not being amortized were determined as part of its application of fresh start accounting and are entirely associated with the Company's Mississippian Lime area. We expect the majority of these costs associated with the Company's Mississippian Lime area will be evaluated and either impaired or become subject to depletion within ten years. Estimated Quantities of Proved Oil and Natural Gas Reserves The reserve estimates at December 31, 2016 and 2015 for the Mississippian Lime and Anadarko Basin areas and at December 31, 2014 for the Anadarko Basin area were based on reports prepared by Cawley, Gillespie & Associates, Inc., independent reserve engineers. The reserve estimates at December 31, 2014 for the Gulf Coast area and for the Mississippian Lime area were based on a report prepared by Netherland, Sewell and 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, 2016, 2015 and 2014: Oil NGL Gas Total 2014 (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, 2014 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved developed reserves, December 31, 2014 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved undeveloped reserves, December 31, 2014 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Revision of Previous Estimates For the Successor Period, the Company had positive revisions of 55,172 MBoe associated with its proved undeveloped reserves. 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 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. For the year ended December 31, 2014, the Company had net negative revisions of 22,925 MBoe related to proved undeveloped reserves, of which 3,084 MBoe related to reductions in our Gulf Coast area, and 22,138 MBoe related to reductions in our Anadarko Basin area, partially offset by 2,297 MBoe in positive revisions in the Mississippian Lime area. These net negative revisions in the Gulf Coast were primarily due to our lack of future development plans in this area. The net negative revisions in the Anadarko Basin were primarily due to our current drilling plans, which did not allow for development of these proved undeveloped reserves within five years of their initial booking. Extensions, Discoveries and Other Additions 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 years ended December 31, 2015 and 2014, the Company had 4,249 MBoe, 6,398 MBoe and 77,035 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, 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. For the year ended December 31, 2014, the Company had 16,391 MBoe in sales of reserves in place related to the Pine Prairie Disposition, which closed on May 1, 2014. 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, 2015 2014 Oil and Natural Gas Prices: Oil (per barrel) $ $ $ NGL (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, 2016, 2015, and 2014 (in thousands): Successor Predecessor Year Ended December 31, At December 31, 2015 2014 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 Successor Period, Predecessor Period and the years ended December 31, 2015 and 2014 (in thousands): Successor Predecessor For the Period For the Period Year Ended December 31, 2015 2014 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	12 Months Ended
	Dec. 31, 2016
Selected Quarterly Financial Data
Selected Quarterly Financial Data	Note 20. 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) 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 2015 (Predecessor) Total revenues $ $ $ $ Operating loss ) ) ) ) Net 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 Accoun28

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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 consolidated financial statements as of and for the year ended December 31, 2014 include the results of the Pine Prairie Disposition from January 1, 2014 through May 1, 2014, 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, 2016 and 2015 that exceeded the balance insured by the FDIC in the amount of $78.4 million and $87.2 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, 2016 and 2015, 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 (losses) on commodity derivative contracts—net." The related cash flow impact is reflected within cash flows from operating activities.
Other Noncurrent Assets	Other Noncurrent Assets At December 31, 2016 and 2015, other noncurrent assets consisted of the following (in thousands): Successor Predecessor December 31, 2016 December 31, 2015 Deferred financing costs associated with the RBL $ — $ Deferred financing costs associated with the Exit Facility — Field equipment inventory Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Other noncurrent assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Predecessor Period, approximately $4.6 million in deferred financing costs associated with the RBL were impaired. For the year ended December 31, 2015, the Company recorded $2.0 million of losses on the sale of, or market value adjustments to, field equipment inventory.
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, its anticipated drilling plans and uncertainty regarding its ability to finance its future exploration activities at that time. At the Effective Date, the Company recorded $66.2 million in unevaluated property associated with fresh start accounting. See "—Note 3. Fresh Start Accounting" for further information. Oil and Gas Reserves Proved oil, NGLs and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board ("FASB"), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company depletes its oil and gas properties using the units-of-production method. Capitalized costs of oil and natural gas properties subject to amortization are depleted over proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. Impairment of Oil and Gas Properties/Ceiling Test The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit, or ceiling, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization ("DD&A") and the related deferred income taxes, may not exceed this ceiling. The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales prices received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations. For the Predecessor Period, the Company recorded an impairment of oil and gas properties of $232.1 million. For the years ended December 31, 2015 and 2014, the Company recorded impairments of oil and gas properties of $1.6 billion and $86.5 million, respectively. 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 for the Predecessor Period and the years ended December 31, 2015. For the year ended December 31, 2014, the primary factor affecting the impairment related to the transfer of unevaluated property costs to the full cost pool. 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 three to seven years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.
Accrued Liabilities	Accrued Liabilities At December 31, 2016 and 2015, accrued liabilities consisted of the following (in thousands): Successor Predecessor December 31, 2016 December 31, 2015 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 estimated fair value 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 fair value 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 a graded 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 and 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 gas revenues, whereby revenue is recognized for all oil, NGLs and 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, 2016, 2015 or 2014.
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 and 2014 relate to the Dequincy Divestiture and the Pine Prairie Disposition, respectively. 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.
Earnings (Loss) Per Share	Earnings (Loss) Per Share Basic earnings (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 earnings (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 earnings per share calculations consist of unvested restricted stock awards, warrants and outstanding stock options for the Successor Period. Potentially dilutive securities for the diluted earnings 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 earnings per share. See "—Note 14. Earnings (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 standard permits the use of either the retrospective or cumulative effect transition method and early adoption is permitted. Currently, the Company has identified the population of contracts and formed an implementation team to determine the Company's implementation timelines, discuss implementation challenges, technical interpretations, industry-specific treatment of certain revenue contract types, and project status. The Company plans to review contracts for each revenue stream identified within the Company's business. Through this process, the Company will determine and document the expected changes in revenue recognition upon adoption of the revised guidance and then evaluate the potential information technology and internal control changes that will be required for adoption based on the findings from the Company's contract review process. The Company will conduct the contract review process throughout 2017 and, as a result, areas of impact may be identified. The Company cannot reasonably quantify the impact of adoption at this time. The Company expects to complete the assessment of ASU 2014-09, including the transition method, in the latter half of 2017. In August 2014, the FASB issued Accountings Standards Update 2014-15, "Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosures of Uncertainties about an Entity's Ability to Continue as a Going Concern" ("ASU 2014-15"). ASU 2014-15 provides guidance about management's responsibility to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern within one year after the date that the financial statements are issued. Certain disclosures are required should substantial doubt exist about the entities ability to continue as a going concern. This evaluation is performed each annual and interim reporting period to assess conditions or events within one year of the date that the financial statements are issued. The new standard was adopted by the Company at December 31, 2016. 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 consolidate 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 and does not expect to move beyond this stage until completion of its evaluation of ASU 2014-09, which is expected to occur in the latter half of 2017. In March 2016, the FASB issued ASU 2016-09, " Compensation—Stock Compensation (Topic 718) " ("ASU 2016-09"). ASU 2016-09 simplifies how certain aspects of share-based payments to employees are recorded. ASU 2016-09 requires that entities recognize the income tax effects of awards in the income statement when the awards vest or are settled, provides guidance on the classification of certain aspects of share-based payments on the statement of cash flows, changes the threshold for awards to qualify for equity classification, and allows an entity to make an accounting policy election to account for forfeitures when they occur. The new standard is effective for the Company beginning on January 1, 2017. As of December 31, 2016, the Company elected to early adopt the pronouncement and it did not have a material impact on its financial results. 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.

Fresh Start Accounting (Tables)

Fresh Start Accounting (Tables)	12 Months Ended
	Dec. 31, 2016
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 is 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	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	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	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 1, 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 recorded for October 20, 2016 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 Accoun30

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Summary of Significant Accounting Policies
Schedule of the components of other noncurrent assets	At December 31, 2016 and 2015, other noncurrent assets consisted of the following (in thousands): Successor Predecessor December 31, 2016 December 31, 2015 Deferred financing costs associated with the RBL $ — $ Deferred financing costs associated with the Exit Facility — Field equipment inventory Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Other noncurrent assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of accrued liabilities	At December 31, 2016 and 2015, accrued liabilities consisted of the following (in thousands): Successor Predecessor December 31, 2016 December 31, 2015 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 $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Risk Management and Derivativ31

Risk Management and Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Risk Management and Derivative Instruments
Schedule of derivative contracts	Quarter Ended Quarter Ended Quarter Ended Quarter Ended Quarter Ended NYMEX WTI Fixed swaps Hedge position (Bbls) — Weighted average strike price $ $ $ $ $ — Collars Hedge position (Bbls) — Weighted average ceiling price $ $ $ $ $ — Weighted average floor price $ $ $ $ $ — Three way collars Hedge position (Bbls) — — Weighted average ceiling price $ — $ — $ $ $ Weighted average floor price $ — $ — $ $ $ Weighted average sub-floor price $ — $ — $ $ $ NYMEX HENRY HUB Fixed swaps Hedge position (MMBtu) — — Weighted average strike price $ — $ $ $ $ — Collars Hedge position (MMBtu) — — — — Weighted average ceiling price $ $ — $ — $ — $ — Weighted average floor price $ $ — $ — $ — $ — Three way collars Hedge position (MMBtu) — — — Weighted average ceiling price $ — $ — $ — $ $ Weighted average floor price $ — $ — $ — $ $ Weighted average sub-floor price $ — $ — $ — $ $
Schedule of net cash received (paid) for commodity derivative contracts and unrealized net gains (losses) related to the change in fair value of derivative instruments - net for the periods	The following table presents net cash received (paid) for commodity derivative contracts and unrealized net gains (losses) recorded by the Company related to the change in fair value of the derivative instruments in "Gains (losses) on commodity derivative contracts—net" for the periods presented (in thousands): Successor Predecessor For the Period For the Years Ended For the Period 2015 2014 Net cash received (paid) for commodity derivative contracts $ — $ — $ $ ) Unrealized net gains (losses) — — ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gains on commodity derivative contracts—net $ — $ — $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property and Equipment
Schedule of property and equipment	The Company's property and equipment as of December 31, 2016 and 2015 was as follows (in thousands): Successor Predecessor December 31, 2016 December 31, 2015 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, 2016
Asset Retirement Obligations
Schedule of changes in the Company's AROs	The following table details the change in the asset retirement obligations for the Successor Period and the years ended December 31, 2015 and 2014, respectively (in thousands): Successor Predecessor For the Period For the Years Ended 2015 2014 Asset retirement obligations at beginning of period $ $ $ Liabilities incurred Revisions(1) — Liabilities settled — ) ) Liabilities eliminated through asset sale(2) — ) ) Current period accretion expense ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Asset retirement obligations at end of year $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Revisions during the year ended December 31, 2015 were the result of updates to the estimated abandonment dates of various wells. Revisions during the year ended December 31, 2014 were due primarily to an increase in estimated future abandonment costs based upon higher costs for oilfield services and materials in the Mississippian Lime and Anadarko Basin areas. (2) Liabilities eliminated through asset sales for the year ended December 31, 2015 is primarily related to the Dequincy Divestiture. Liabilities eliminated through asset sales for the year ended December 31, 2014 were related to the Pine Prairie Disposition. See discussion of the Dequincy Divestiture and Pine Prairie Disposition in "—Note 8. Acquisition and Divestitures of Oil and Gas Properties".

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt
Schedule of the Company's total debt	The Company's total debt, including debt classified as current, as of December 31, 2016 and 2015 is as follows (in thousands): Principal Unamortized Deferred Unamortized Debt Total Successor Predecessor Successor Predecessor Successor Predecessor Successor Predecessor 2016 2015 2016 2015 2016(1) 2015 2016 2015 Predecessor Credit Facility $ — $ — $ — $ — $ — $ — $ — $ — Successor Exit Facility — — — — — — 2020 Senior Notes — — — — ) — 2021 Senior Notes — — — — ) — Second Lien Notes — — — — — Third Lien Notes — — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total debt $ $ $ — $ $ — $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Unamortized debt issuance costs of $1.2 million associated with the Exit Facility are included in other noncurrent assets on the consolidated balance sheets.

Equity and Share-Based Compen35

Equity and Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Equity and Share-Based Compensation
Summary of changes in the number of common stock and treasury stock	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) — (1) Treasury stock represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory withholding requirements.
Summary of non-vested share 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) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of assumptions used to estimate fair value of stock options	Awards Issued in 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 had no exercise history associated with stock options at the Effective Date, 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. (3) As the Company had no stock option history at the Effective Date, 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 38.5% to 65.9%.
Summary of non-vested stock option activity	Options Range of Weighted Weighted Stock options outstanding at October 21, 2016 (Successor) $ $ Granted $ $ Vested — — $ — — Forfeited ) $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Stock options outstanding at December 31, 2016 (Successor) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of assumptions used to estimate fair value of restricted stock units with market condition	Awards Issued in 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 had no relevant history at the Effective Date, 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 39.8% to 61.4%.
Schedule of outstanding restricted stock unit awards containing market condition	Shares Weighted Average Outstanding at October 21, 2016 (Successor) — $ — Granted $ Vested — $ — Forfeited — $ — ​ ​ ​ ​ ​ ​ ​ ​ Outstanding at December 31, 2016 (Successor) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Summary of share-based compensation expense	The following summarizes stock-based compensation expense for the periods presented (in thousands): Successor Predecessor For the Period For the Years Ended For the Period 2015 2014 Restricted stock units (Predecessor) $ — $ $ $ Restricted stock units (Successor) — — — Stock options (Successor) — — — 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, 2016
Income Taxes
Schedule of income tax provision (benefit)	Successor Predecessor For the Period For the Period For the Years Ended 2015 2014 (in thousands) (in thousands) Current United States $ — $ — $ — $ — State — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total current — — — Deferred United States — — ) State — — ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total deferred — — ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total income tax provision (benefit) $ — $ — $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of difference between the Company's estimated income tax from amount derived by applying statutory federal rate to pretax income	Successor Predecessor For the Period For the Period Years Ended 2015 2014 (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 ) ) ) 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): Successor Predecessor As of As of Deferred tax assets—current Derivative instruments and other $ — $ — Less valuation allowance — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total deferred tax assets, current $ — $ — Deferred tax assets—noncurrent Federal tax loss carryforwards — State tax loss carryforwards — Employee benefit plans Oil and gas properties and equipment Debt restructuring — Other — Less valuation allowance ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total deferred tax assets, noncurrent $ — $ — Deferred tax liabilities—current Derivative instruments and other — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total deferred tax liabilities—current $ — $ — Deferred tax liabilities—noncurrent Oil and gas properties and equipment — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total deferred tax liabilities, noncurrent $ — $ — Reflected in the accompanying balance sheet as: Net deferred tax asset, current $ — $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax liability, current $ — $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax asset, noncurrent $ — $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax liability, noncurrent $ — $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Earnings (Loss) Per Share (Tabl

Earnings (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2016
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 (in thousands, except Net Earnings: Net income $ Participating securities—non-vested restricted stock ) ​ ​ ​ ​ ​ Basic and diluted earnings $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Common Shares: Common shares outstanding—basic(1) Dilutive effect of potential common shares — ​ ​ ​ ​ ​ Common shares outstanding—diluted ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net Earnings Per Share: Basic $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Diluted $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Antidilutive stock options(2) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Antidilutive warrants(3) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Weighted-average common shares outstanding for basic and diluted earnings per share purposes includes 17,533 shares of common stock that, while not issued and outstanding at December 31, 2016, are required by the Plan to be issued. (2) Amount represents options to purchase common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive. (3) Amount represents warrants to purchase common stock that are excluded from the diluted net earnings 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 Years Ended December 31, 2015 2014 (in thousands, except per share amounts) Net income (loss) $ $ ) $ 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, 2016
Commitments and Contingencies
Schedule of contractual obligations for drilling contracts, long-term operating leases, and other contracts	At December 31, 2016, contractual obligations for drilling contracts, long-term operating leases and other contracts are as follows (in thousands): Total 2017 2018 2019 2020 2021 and Drilling contracts $ — $ — $ — $ — $ — $ — Non-cancellable office lease commitments ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net minimum commitments $ $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Supplemental Information to C39

Supplemental Information to Consolidated Statement of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Information to Consolidated Statement of Cash Flows
Schedule of summarized interest and income taxes and supplemental non-cash investing and financing activities	The following table summarizes interest and income taxes paid for the periods presented and supplemental non-cash investing and financing activities (in thousands): Successor Predecessor Period Period Years Ended 2015 2014 SUPPLEMENTAL INFORMATION: Non-cash investment in property and equipment $ $ $ $ Non-cash components of Pine Prairie Disposition: —Asset retirement obligation disposed $ — $ — $ — $ ) —Accrual for miscellaneous liabilities assumed $ — $ — $ — $ ) —Other noncurrent assets sold $ — $ — $ — $ 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 Successor Period and the years ended December 31, 2015 and 2014 of $0.7 million, $4.9 million and $12.4 million, respectively (no capitalized interest for the Predecessor Period) $ $ $ $ Cash paid for reorganization items $ — $ $ — $ — Cash paid for taxes $ — $ — $ — $

Supplemental Oil and Gas Disc40

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
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 Successor Period, Predecessor Period and years ended December 31, 2015 and 2014 (in thousands): Successor Predecessor For the Period For the Period For the Year 2015 2014 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, 2016 and 2015 (in thousands): Successor Predecessor December 31, 2016 December 31, 2015 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 2014 (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, 2014 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved developed reserves, December 31, 2014 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved undeveloped reserves, December 31, 2014 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of benchmark prices used to determine estimated proved reserves	Successor Predecessor At December 31, At December 31, 2015 2014 Oil and Natural Gas Prices: Oil (per barrel) $ $ $ NGL (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, 2016, 2015, and 2014 (in thousands): Successor Predecessor Year Ended December 31, At December 31, 2015 2014 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 Successor Period, Predecessor Period and the years ended December 31, 2015 and 2014 (in thousands): Successor Predecessor For the Period For the Period Year Ended December 31, 2015 2014 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 41

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2016
Selected Quarterly Financial Data
Schedule of selected quarterly financial data	First Second Third Fourth (in thousands, except per share amounts) 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 2015 (Predecessor) Total revenues $ $ $ $ Operating loss ) ) ) ) Net 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) - Predecessor $ in Millions	Apr. 21, 2015USD ($)a	May 01, 2014USD ($)
Pine Prairie Disposition
Acquisition information
Net proceeds from disposition		$ 147.7
Dequincy Divestiture
Acquisition information
Net proceeds from sale of ownership interest	$ 42.4
Area of undeveloped acreage under lease (in acres) | a	4,431

Emergence from Voluntary Reor43

Emergence from Voluntary Reorganization under Chapter 11 Proceedings (Details) $ / shares in Units, $ in Millions

Dec. 31, 2016USD ($)itemshares

Oct. 21, 2016USD ($)$ / sharesshares

Nov. 09, 2016shares

Oct. 20, 2016USD ($)

Apr. 30, 2016USD ($)

Apr. 01, 2016USD ($)

Dec. 31, 2015shares

Oct. 01, 2015

Aug. 03, 2015shares

Jun. 02, 2015

May 21, 2015

May 31, 2013

2016 Reorganization

Common stock, shares issued

24,994,867

Common stock, shares authorized

250,000,000

Percentage of Management Equity Incentive Plan

10.00%

Common Stock

2016 Reorganization

Common stock, shares issued

24,994,867

Exit Facility

2016 Reorganization

Maximum borrowing capacity | $

$ 170

Number of additional borrowing base redeterminations at company request per 6 month period following each scheduled borrowing base redetermination | item

0

Reduction of borrowing base under the Exit Facility | $

$ 40

Exit Facility | Minimum

2016 Reorganization

Liquidity of the Company (as a percent)

20

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

Predecessor

2016 Reorganization

Common stock, shares issued

10,962,105

Common stock, shares authorized

100,000,000

Predecessor | Common Stock

2016 Reorganization

Common stock, shares issued

10,962,105

Common stock, shares authorized

100,000,000

2020 Senior Notes | Predecessor

2016 Reorganization

Debt Instrument, Interest Rate, Stated Percentage

10.75%

10.75%

2021 Senior Notes | Predecessor

2016 Reorganization

Debt Instrument, Interest Rate, Stated Percentage

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

Second Lien Notes | Predecessor

2016 Reorganization

Debt Instrument, Interest Rate, Stated Percentage

10.00%

Third Lien Notes | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | Warrants

2016 Reorganization

Warrants to acquire common stock shares (in shares)

4,411,765

Warrant strike price (in dollars per share) | $ / shares

$ 24

Warrants expiration term

42 months

Third Lien Notes | Predecessor

2016 Reorganization

Debt Instrument, Interest Rate, Stated Percentage

12.00%

Unsecured Notes | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | Warrant B

2016 Reorganization

Warrants to acquire common stock shares (in shares)

2,213,789

Warrant strike price (in dollars per share) | $ / shares

$ 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

Reduction of borrowing base under the Exit Facility | $

$ 82

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, 2015	Dec. 31, 2014
Fresh start accounting adjustments
Reorganization value	$ 751,300
Valuation of Oil and Gas Properties
Federal statutory rate		35.00%
Fair value of probable and possible reserves	66,200
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%	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, 2016	Oct. 20, 2016
Fresh start accounting adjustments
Plus: Cash and cash equivalents	$ 76,540	$ 76,838	$ 76,540
Common Stock, Par or Stated Value Per Share		$ 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
Common Stock, Par or Stated Value 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 rate utilized (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 rate utilized (as a percent)	1.04%
Expected life (in years)	3 years 6 months
Expected volatility (as a percent)	55.00%
Warrant strike price (in dollars per share)	$ 24
Calculated fair value	$ 6.74
Warrants | Unsecured Notes
Assumptions used to estimate fair value of warrants
Risk free rate utilized (as a percent)	1.04%
Expected life (in years)	3 years 6 months
Expected volatility (as a percent)	55.00%
Warrant strike price (in dollars per share)	$ 46
Calculated fair value	$ 3.42

Fresh Start Accounting - Ente47

Fresh Start Accounting - Enterprise to Reorg values (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Oct. 21, 2016	Oct. 20, 2016
Fresh start accounting adjustments
Plus: Cash and cash equivalents	$ 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, Total		$ 751,258

Fresh Start Accounting - Balanc

Fresh Start Accounting - Balance sheet effects (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Oct. 21, 2016	Oct. 20, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CURRENT ASSETS:
Cash and cash equivalents	$ 76,838	$ 76,540	$ 76,540
Accounts receivable:
Oil and gas sales	36,988	33,895
Joint interest billing	4,281	4,739
Other	2,456	26
Other current assets	3,326	5,677
Total current assets	123,889	120,877
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting		619,220
Other property and equipment	6,339	6,210
Less accumulated depreciation, depletion, amortization and impairment	(12,974)
Net property and equipment	631,595	625,430
OTHER NONCURRENT ASSETS	5,455	4,951
TOTAL	760,939	751,258
CURRENT LIABILITIES:
Accounts payable	2,521	10,294
Accrued liabilities	53,731	49,824
Total current liabilities	56,252	60,118
ASSET RETIREMENT OBLIGATIONS	14,200	13,983
OTHER LONG-TERM LIABILITIES	614	128,676
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred stock
Warrants		37,329
Common stock	250	247
Additional paid-in-capital	514,305	510,905
Retained deficit	9,930
Total stockholders' equity (deficit)	561,814	548,481
TOTAL	$ 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 less unamortized debt issuance costs		(249,384)
Total current liabilities		(264,800)
OTHER LONG-TERM LIABILITIES		128,059
LIABILITIES SUBJECT TO COMPROMISE (Note 2)		(1,882,187)
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY (DEFICIT):
Warrants		37,329
Common stock		247
Treasury stock		3,134
Additional paid-in-capital		510,905
Retained deficit		2,159,221
Total stockholders' equity (deficit)		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 (DEFICIT):
Retained deficit		272,938
Total stockholders' equity (deficit)		272,938
TOTAL		266,553
Predecessor
CURRENT ASSETS:
Cash and cash equivalents		274,530	76,540	$ 81,093	$ 11,557	$ 33,163
Accounts receivable:
Oil and gas sales		33,895		33,656
Joint interest billing		4,739		12,503
Other		26		17,506
Other current assets		8,425		1,044
Total current assets		321,615		145,802
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting		3,795,943
Other property and equipment		12,175		14,798
Less accumulated depreciation, depletion, amortization and impairment		(3,449,241)		(3,157,332)
Net property and equipment		358,877		523,869
OTHER NONCURRENT ASSETS		3,701		9,496
TOTAL		684,193		679,167
CURRENT LIABILITIES:
Accounts payable		10,294		1,904
Accrued liabilities		65,240		91,712
Debt classified as current less unamortized debt issuance costs		249,384		1,890,944
Total current liabilities		324,918		1,984,560
ASSET RETIREMENT OBLIGATIONS		20,368		18,708	21,599	26,308
OTHER LONG-TERM LIABILITIES		617		1,965
LIABILITIES SUBJECT TO COMPROMISE (Note 2)		1,882,187
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred stock
Common stock		104		110
Treasury stock		(3,134)
Treasury stock				3,081
Additional paid-in-capital		891,292		888,247
Retained deficit		(2,432,159)		(2,211,342)
Total stockholders' equity (deficit)		(1,543,897)	$ (1)	(1,326,066)	$ 465,862	$ 339,999
TOTAL		684,193		$ 679,167
Predecessor | Reorganization Adjustments
STOCKHOLDERS' EQUITY (DEFICIT):
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) - USD ($) $ in Thousands	Oct. 21, 2016	Dec. 31, 2016
Exit Facility
Fresh start accounting adjustments
Debt issuance costs associated with the Exit Facility		$ 1,187
Reorganization Adjustments
Fresh start accounting adjustments
Permanent pay-down	$ 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
Reorganization Adjustments | Second lien notes
Fresh start accounting adjustments
Permanent pay-down	(60,000)
Additional payment to lenders	60,000
Reorganization Adjustments | 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, 2016
Fresh start accounting adjustments
Warrants Issued Value	$ 37,329
Common stock, shares issued		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 of liabilities subject to compromise	$ 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, 2016	Dec. 31, 2015
Fresh start accounting adjustments
Common stock-predecessor	$ (247)	$ (250)
Additional paid-in-capital	(510,905)	$ (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)		$ (110)
Treasury stock	(3,134)
Additional paid-in-capital	(891,292)		$ (888,247)
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 - Reor52

Fresh Start Accounting - Reorganization property (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Oct. 21, 2016
Fresh start accounting adjustments
Accumulated depreciation, depletion, amortization and impairment	$ 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 - Reor53

Fresh Start Accounting - Reorganization items (Details) - Predecessor - USD ($) $ in Thousands	10 Months Ended
	Oct. 20, 2016	Dec. 31, 2015
Reorganization items
Unamortized Debt Issuance Costs		$ (24,640)
Gain on reorganization items, net	$ (1,594,281)
2020 Senior Notes
Reorganization items
Unamortized Debt Issuance Costs		(11,344)
2021 Senior Notes
Reorganization items
Unamortized Debt Issuance Costs		$ (13,296)
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 Accoun54

Summary of Significant Accounting Policies (Details)	10 Months Ended	12 Months Ended
	Oct. 20, 2016USD ($)	Dec. 31, 2016USD ($)segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Oct. 21, 2016USD ($)
Number of reportable segments | segment		1
Cash and Cash Equivalents
Cash balance of FDIC insured amount		$ 250,000
Cash balance of FDIC uninsured amount		78,400,000
Accounts Receivable and Allowance for Doubtful Accounts
Allowance for doubtful accounts		0
Other Noncurrent Assets
Field equipment inventory		2,619,000
Other		1,649,000
Other noncurrent assets		5,455,000			$ 4,951,000
Fair value of probable and possible reserves					66,200,000
Proved Reserves
Provision for price and cost escalations		0
Accrued Liabilities
Accrued oil and gas capital expenditures		6,118,000
Accrued revenue and royalty distributions		28,262,000
Accrued lease operating and workover expense		8,932,000
Accrued interest		254,000
Accrued taxes		2,537,000
Compensation and benefit related accruals		3,516,000
Other		4,112,000
Accrued liabilities		53,731,000			49,824,000
Assets:
OTHER NONCURRENT ASSETS		$ 5,455,000			4,951,000
Predecessor
Cash and Cash Equivalents
Cash balance of FDIC uninsured amount			$ 87,200,000
Accounts Receivable and Allowance for Doubtful Accounts
Allowance for doubtful accounts			0
Other Noncurrent Assets
Field equipment inventory			3,225,000
Other			166,000
Other noncurrent assets			9,496,000		3,701,000
Losses on the sale of field equipment inventory	$ 4,600,000		2,000,000
Proved Reserves
Impairments of oil and gas properties	$ 232,108,000		1,625,776,000	$ 86,471,000
Accrued Liabilities
Accrued oil and gas capital expenditures			19,984,000
Accrued revenue and royalty distributions			27,939,000
Accrued lease operating and workover expense			9,281,000
Accrued interest			20,193,000
Accrued taxes			1,272,000
Compensation and benefit related accruals			8,414,000
Other			4,629,000
Accrued liabilities			91,712,000		65,240,000
Assets:
OTHER NONCURRENT ASSETS			9,496,000		$ 3,701,000
Mississippian | Predecessor
Other Noncurrent Assets
Unevaluated property costs transferred to the full cost pool			56,300,000
Anadarko Basin | Predecessor
Other Noncurrent Assets
Unevaluated property costs transferred to the full cost pool			200,000
Gulf Coast | Predecessor
Other Noncurrent Assets
Unevaluated property costs transferred to the full cost pool			100,000
Other Property and Equipment | Minimum
Estimated useful lives		3 years
Other Property and Equipment | Maximum
Estimated useful lives		7 years
Revolving Credit Facility | Predecessor
Other Noncurrent Assets
Deferred financing costs associated with the Credit Facility			$ 6,105,000
Exit Facility
Other Noncurrent Assets
Deferred financing costs associated with the Credit Facility		$ 1,187,000

Risk Management and Derivativ55

Risk Management and Derivative Instruments - By Nature (Details)	Dec. 31, 2016item
Not designated as Hedging Instrument | Commodity Derivatives
Risk Management and Derivative Instruments
Number of derivative instruments held	0

Risk Management and Derivativ56

Risk Management and Derivative Instruments- Hedging (Details) - Designated as Hedging Instrument - NYMEX	Dec. 31, 2016MMBTU$ / MMBTU$ / bblbbl
WTI | Swap Contract Quarter Ended March 31, 2017
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	105,500
Swap weighted average strike price	55.17
WTI | Swap Contract Quarter Ended June 30, 2017
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	227,500
Swap weighted average strike price	55.12
WTI | Swap Contract Quarter Ended September 30, 2017
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	207,000
Swap weighted average strike price	55.29
WTI | Swap Contract Quarter Ended December 31, 2017
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	207,000
Swap weighted average strike price	55.29
WTI | Collar Contract Quarter Ended March 31, 2017
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	74,500
Weighted average floor price	50
Weighted average ceiling price	59.68
WTI | Collar Contract Quarter Ended June 30, 2017
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	136,500
Weighted average floor price	50
Weighted average ceiling price	59.73
WTI | Collar Contract Quarter Ended September 30, 2017
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	46,000
Weighted average floor price	50
Weighted average ceiling price	60
WTI | Collar Contract Quarter Ended December 31, 2017
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	46,000
Weighted average floor price	50
Weighted average ceiling price	60
WTI | Three Way Collar Contract Quarter Ended September 30, 2017
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	115,000
Weighted average floor price	50
Weighted average ceiling price	62.80
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended December 31, 2017
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	115,000
Weighted average floor price	50
Weighted average ceiling price	62.80
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	135,000
Weighted average floor price	50
Weighted average ceiling price	63.50
Weighted average sub-floor price	40
HENRY HUB | Swap Contract Quarter Ended June 30, 2017
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	2,912,000
Swap weighted average strike price | $ / MMBTU	3.38
HENRY HUB | Swap Contract Quarter Ended September 30, 2017
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	2,944,000
Swap weighted average strike price | $ / MMBTU	3.38
HENRY HUB | Swap Contract Quarter Ended December 31, 2017
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	992,000
Swap weighted average strike price | $ / MMBTU	3.38
HENRY HUB | Collar Contract Quarter Ended March 31, 2017
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,298,000
Weighted average floor price | $ / MMBTU	3.10
Weighted average ceiling price | $ / MMBTU	3.70
HENRY HUB | Three Way Collar Contract Quarter Ended December 31, 2017
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	610,000
Weighted average floor price | $ / MMBTU	3.25
Weighted average ceiling price | $ / MMBTU	4.30
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	900,000
Weighted average floor price | $ / MMBTU	3.25
Weighted average ceiling price | $ / MMBTU	4.30
Weighted average sub-floor price | $ / MMBTU	2.50

Risk Management and Derivativ57

Risk Management and Derivative Instruments - Gain Loss (Details) - Predecessor - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Gains (losses) on Commodity Derivative Contracts
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments	$ (167,669)	$ 18,332
Gains on commodity derivative contracts - net	40,960	139,189
Not designated as Hedging Instrument
Gains (losses) on Commodity Derivative Contracts
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments	167,669	(18,332)
Unrealized net gains (losses)	(126,709)	157,521
Gains on commodity derivative contracts - net	$ 40,960	$ 139,189

Property and Equipment (Details

Property and Equipment (Details) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)$ / Boe	Oct. 20, 2016USD ($)$ / Boe	Dec. 31, 2015USD ($)$ / Boe	Dec. 31, 2014USD ($)$ / Boe	Oct. 21, 2016USD ($)
Property and equipment
Proved properties	$ 573,150
Unproved properties not being amortized	65,080
Other property and equipment	6,339				$ 6,210
Less accumulated depreciation, depletion, amortization and impairment	(12,974)
Net property and equipment	631,595				625,430
Other information
Capitalized qualifying share-based compensation expense	637
Other Property and Equipment
Other information
Depreciation	400
Oil and Gas Properties
Other information
Depletion expense related to oil and gas properties	$ 12,600
Depletion expense (per Boe) | $ / Boe	7
Costs capitalized to unevaluated properties	$ 700
Internal costs capitalized to oil and gas properties	1,400
Capitalized qualifying share-based compensation expense	$ 600
Predecessor
Property and equipment
Proved properties			$ 3,666,403
Other property and equipment			14,798		12,175
Less accumulated depreciation, depletion, amortization and impairment			(3,157,332)		(3,449,241)
Net property and equipment			523,869		$ 358,877
Other information
Capitalized qualifying share-based compensation expense		$ 476	1,347	$ 2,244
Predecessor | Other Property and Equipment
Other information
Depreciation		2,400	3,500	3,100
Predecessor | Oil and Gas Properties
Other information
Depletion expense related to oil and gas properties		$ 59,900	$ 195,200	$ 266,800
Depletion expense (per Boe) | $ / Boe		6.84	16.26	22.75
Costs capitalized to unevaluated properties			$ 4,900	$ 12,400
Internal costs capitalized to oil and gas properties		$ 3,400	7,300	12,400
Capitalized qualifying share-based compensation expense		$ 500	$ 1,300	$ 2,200

Acquisition and Divestitures 59

Acquisition and Divestitures of Oil and Gas Properties (Details) - Predecessor - USD ($) $ in Thousands	Apr. 21, 2015	Jun. 25, 2014	May 01, 2014	Jan. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Acquisition of Oil and Gas Properties
Proceeds from the sale of oil and gas properties						$ 42,366	$ 152,133
Acquisition and transaction costs						330	4,129
Petro Quest | 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
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
Pine Prairie Disposition
Acquisition of Oil and Gas Properties
Proceeds from the sale of oil and gas properties			$ 170,000
Gain (loss) on divestiture of business recognized			0
Net proceeds from disposition			147,700
Acquisition and transaction costs							$ 4,100
Pine Prairie Disposition | Revolving Credit Facility
Acquisition of Oil and Gas Properties
Repayment of debt			$ 131,000

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	2 Months Ended		10 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2015	Dec. 31, 2014
Changes in Company's asset retirement obligations
Asset retirement obligations - beginning of period	$ 13,983
Liabilities incurred	7
Current period accretion expense	210	$ 210
Asset retirement obligations - end of period	14,200	$ 14,200
Predecessor
Changes in Company's asset retirement obligations
Asset retirement obligations - beginning of period	$ 20,368		$ 18,708	$ 21,599	$ 26,308
Liabilities incurred				127	996
Revisions				570	288
Liabilities settled				(279)	(47)
Liabilities eliminated through asset sales				(4,919)	(7,652)
Current period accretion expense			$ 1,414	1,610	1,706
Asset retirement obligations - end of period				$ 18,708	$ 21,599

Debt (Details)

Debt (Details) $ / shares in Units, $ in Thousands	Oct. 21, 2016USD ($)$ / sharesshares	Dec. 31, 2016USD ($)	Oct. 20, 2016USD ($)	Apr. 30, 2016USD ($)	Dec. 31, 2015USD ($)	Jun. 02, 2015USD ($)	May 21, 2015USD ($)	May 31, 2013USD ($)	Oct. 01, 2012USD ($)
Debt
Principal		$ 128,059
Total debt		128,059
Exit Facility
Debt
Principal		128,059
Total debt		128,059
2016 Reorganization
Maximum borrowing capacity		170,000
Debt issuance costs associated with the Exit Facility		$ 1,187
Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | Exit Facility
2016 Reorganization
Permanent pay-down	$ 81,300
Anticipated borrowing base after emergence from bankruptcy	170,000
Maximum borrowing capacity	170,000			$ 170,000
Predecessor
Debt
Principal					$ 1,795,930
Unamortized Deferred Gain on Debt Forgiven					(119,654)
Unamortized Debt Issuance Costs					(24,640)
Total debt					1,890,944
2020 Senior Notes | Predecessor
Debt
Principal					293,625				$ 600,000
Unamortized Debt Issuance Costs					(11,344)
Total debt					282,281
2021 Senior Notes | Predecessor
Debt
Principal					347,652			$ 700,000
Unamortized Debt Issuance Costs					(13,296)
Total debt					334,356
Second Lien Notes
2016 Reorganization
Permanent pay-down	60,000
Second Lien Notes | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement
2016 Reorganization
Permanent pay-down	$ 60,000
Equity allocated to holders of debt (as a percent)	96.25
Second Lien Notes | Predecessor
Debt
Principal					625,000
Unamortized Deferred Gain on Debt Forgiven					(42,293)
Total debt					667,293
Third Lien Notes | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | Warrants
2016 Reorganization
Equity allocated to holders of debt (as a percent)	2.5
Warrants to acquire common stock shares (in shares) | shares	4,411,765
Warrant strike price (in dollars per share) | $ / shares	$ 24
Warrants expiration term	42 months
Third Lien Notes | Predecessor
Debt
Principal					529,653	$ 20,000	$ 504,100
Unamortized Deferred Gain on Debt Forgiven					(77,361)
Total debt					$ 607,014
Unsecured Notes | Bankruptcy Reorganization Chapter 11 | Plan Support Agreement | Warrant B
2016 Reorganization
Equity allocated to holders of debt (as a percent)	1.25
Warrants to acquire common stock shares (in shares) | shares	2,213,789
Warrant strike price (in dollars per share) | $ / shares	$ 46
Warrants expiration term	42 months
Senior Revolving Credit Facility, due 2018
2016 Reorganization
Permanent pay-down	$ 121,300
Senior Revolving Credit Facility, due 2018 | Predecessor
2016 Reorganization
Maximum borrowing capacity			$ 750,000

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, 2016	Dec. 31, 2015	Dec. 31, 2014	May 31, 2013	Oct. 01, 2012
Debt Restructuring
Gain (loss) on restructuring of debt					$ 0
Principle Balance Outstanding					$ 128,059
Predecessor
Debt Restructuring
Borrowings						$ 625,000
Repayment of revolving credit facility				$ (121,324)		(468,150)	$ (131,000)
Amortization of Forgiven Debt				$ (8,246)		(14,948)
Unamortized Deferred Gain on Debt Forgiven						119,654
Principle Balance Outstanding						1,795,930
Predecessor | Second Lien Notes
Debt Restructuring
Borrowings			$ 625,000
Unamortized Deferred Gain on Debt Forgiven						42,293
Principle Balance Outstanding						625,000
Predecessor | Third Lien Notes
Debt Restructuring
Unamortized Deferred Gain on Debt Forgiven						77,361
Principle Balance Outstanding	$ 20,000	$ 20,000	504,100			529,653
Predecessor | 2020 Senior Notes
Debt Restructuring
Principal amount extinguished		63,900
Exchanges	306,400	26,600	279,800
Principle Balance Outstanding						293,625			$ 600,000
Predecessor | 2021 Senior Notes
Debt Restructuring
Principal amount extinguished		70,700
Exchanges	$ 352,300	$ 2,000	$ 350,300
Principle Balance Outstanding						$ 347,652		$ 700,000
Predecessor | Unsecured Notes
Debt Restructuring
Percentage of exchanged debt's par value		70.00%	80.00%

Debt - Exit Facility and Credit

Debt - Exit Facility and Credit Facilities (Details) $ in Thousands	Dec. 31, 2016USD ($)item	Oct. 20, 2016USD ($)	Jun. 02, 2015USD ($)	Jun. 02, 2015USD ($)	May 21, 2015USD ($)	Feb. 29, 2016USD ($)	Oct. 20, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Oct. 21, 2016USD ($)	Apr. 01, 2016USD ($)	Oct. 01, 2015	May 31, 2013USD ($)	Oct. 01, 2012USD ($)
Debt
Aggregate principal amount borrowed	$ 128,059
Exit Facility
Debt
Maximum borrowing capacity	170,000
Proceeds from revolving credit facility	128,100
Availability under the facility	0
Amount Of Reduction In Borrowing Base Under Exit Facility	40,000
Capital expenditure limitation for the 6 months ended December 31, 2016	50,000
Capital expenditure limitation for the year ended December 31, 2017	81,000
Capital expenditure limitation for the year ended December 31, 2018	85,000
Capital expenditure limitation for the year ended December 31, 2019	$ 78,000
Number of additional borrowing base redeterminations at company request per 6 month period following each scheduled borrowing base redetermination | item	0
Aggregate principal amount borrowed	$ 128,059
Weighted-average interest rate (as a percent)	5.50%
EBITDA to interest expense coverage ratio	3
Commitment fee (as a percent)	0.50
Exit Facility | LIBOR Loans
Debt
Interest rate added to base rate (as a percent)	4.50%
LIBOR floor rate	1.00%
Exit Facility | Minimum
Debt
Liquidity of the Company (as a percent)	20
Percentage of first priority mortgages to secure the Company's oil and gas properties	95.00%
Exit Facility | Maximum
Debt
Total net indebtedness to EBITDA	2.25
Total net indebtedness to EBITDA after April 1, 2018	3
Senior Revolving Credit Facility, due 2018
Debt
Permanent pay-down										$ 121,300
Senior Revolving Credit Facility, due 2018 | Exit Facility
Debt
Outstanding letters of credit amount	$ 1,900
Second Lien Notes
Debt
Permanent pay-down										$ 60,000
Predecessor
Debt
Proceeds from revolving credit facility							$ 249,384	$ 33,000	$ 165,000
Aggregate principal amount borrowed								1,795,930
Predecessor | Senior Revolving Credit Facility, due 2018
Debt
Maximum borrowing capacity		$ 750,000					750,000
Borrowing base		$ 252,000					$ 252,000
Proceeds from revolving credit facility						$ 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								293,625						$ 600,000
Exchanges			$ 306,400	$ 26,600	$ 279,800
Interest rate (as a percent)			10.75%	10.75%								10.75%
Predecessor | 2021 Senior Notes
Debt
Aggregate principal amount borrowed								347,652					$ 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			$ 529,653
Interest rate (as a percent)					12.00%
Cash interest rate					10.00%
PIK Interest					2.00%

Preferred Stock (Details)

Preferred Stock (Details) - Predecessor - Series A Preferred Stock - $ / shares	Oct. 01, 2012	Sep. 30, 2015
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%
Number of shares into which each Series A Preferred Share gets converted	11.5
Additional shares of common stock to be issued upon conversion		3,738,424

Equity and Share-Based Compen65

Equity and Share-Based Compensation - Common Shares (Details)	Oct. 21, 2016Vote$ / sharesshares	Oct. 20, 2016shares	Aug. 03, 2015$ / sharesshares	Dec. 31, 2016$ / sharesshares	Oct. 20, 2016shares	Dec. 31, 2015$ / sharesshares	Nov. 09, 2016shares	Nov. 08, 2016shares
Common Shares
Common stock, shares issued				24,994,867
Common stock, shares authorized				250,000,000
Common stock, par value (in dollars per share) | $ / shares				$ 0.01
Common stock, shares outstanding				24,994,867
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				24,994,867
Common stock, shares outstanding				24,994,867
Changes in number of shares outstanding
Share count at the beginning of the period (in shares)				24,687,500
Issuance of successor common stock (in shares)	24,687,500			307,367
Share count at the beginning of the period (in shares)	24,687,500			24,994,867
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
Predecessor
Common Shares
Common stock, shares issued						10,962,105
Common stock, shares authorized						100,000,000
Common stock, par value (in dollars per share) | $ / shares						$ 0.01
Common stock, shares outstanding						10,865,814
Predecessor | Common Stock
Common Shares
Common stock, shares issued						10,962,105
Common stock, shares authorized			100,000,000
Common stock, par value (in dollars per share) | $ / shares			$ 0.01
Common stock, shares outstanding						10,865,814
Stock split ratio			1
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
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 beginning 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 Compen66

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 Compen67

Equity and Share-Based Compensation - Emergence from Bankruptcy and 2016 Long Term Incentive Plan (Details) - USD ($) $ in Thousands	Oct. 21, 2016	Dec. 31, 2016
Share-Based Compensation
Share-based compensation costs recognized		$ 2,909
2016 LTIP
Share-Based Compensation
Number of shares available for future issuance	3,513,950
Number of shares authorized		2,111,786
Plan Support Agreement | Bankruptcy Reorganization Chapter 11
Share-Based Compensation
Share-based compensation costs recognized	$ 1,300

Equity and Share-Based Compen68

Equity and Share-Based Compensation - Restricted Stock Units (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 21, 2016	Oct. 20, 2016	Dec. 31, 2016	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2015	Dec. 31, 2014
Additional information
Share-based compensation costs recognized				$ 2,909
Total share-based compensation expense				2,909
Capitalized qualifying share-based compensation costs to oil and gas properties				$ 637
Restricted Stock Units
Restricted Stock
Non-vested shares outstanding at the beginning of the period (in shares)			686,324
Granted (in shares)			2,035
Forfeited (in shares)			(2,697)
Non-vested shares outstanding at the end of the period (in shares)	686,324		685,662	685,662
Weighted Average Grant Date Fair Value
Non-vested shares outstanding at the beginning of the period (in dollars per share)			$ 19.66
Granted (in dollars per share)			20.97
Forfeited (in dollars per share)			19.66
Non-vested shares outstanding at the end of the period (in dollars per share)	$ 19.66		$ 19.66	$ 19.66
Additional information
Capitalized qualifying share-based compensation costs to oil and gas properties				$ 400
Restricted Stock Units | General and administrative expense
Additional information
Share-based compensation costs recognized				1,700
Restricted Stock Units | 2016 LTIP
Additional information
Unrecognized expense for share-based compensation			$ 11,400	$ 11,400
Weighted-average period for over which unrecognized expense will be recognized				1 year 8 months 12 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	$ 8,619
Total share-based compensation expense					2,564	4,408	8,618
Capitalized qualifying share-based compensation costs to oil and gas properties					$ 476	$ 1,347	$ 2,244
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	306,202
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	$ 52.76
Additional information
Capitalized qualifying share-based compensation costs to oil and gas properties					$ 500	$ 1,300	$ 2,200
Predecessor | Restricted Stock Units | Severance
Additional information
Total share-based compensation expense						1,500	2,900
Predecessor | Restricted Stock Units | General and administrative expense
Additional information
Share-based compensation costs recognized					$ 2,600	$ 4,400	$ 8,600
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 Compen69

Equity and Share-Based Compensation - Stock Options (Details) $ / shares in Units, $ in Thousands	Dec. 31, 2016USD ($)item$ / sharesshares	Oct. 21, 2016$ / sharesshares	Dec. 31, 2016USD ($)item$ / sharesshares
Additional information
Share-based compensation costs recognized | $			$ 2,909
Stock Options
Assumptions used to estimate fair value of stock option awards
Risk-free interest rate (as a percent)			1.38%
Expected option life (in years)			5 years 11 months 16 days
Expected volatility (as a percent)			60.00%
Calculated fair value per stock option (in dollars per share) | $ / shares	$ 10.88		$ 10.88
Change in expected option life (in years)			2 years
Increase in expense due to change in expected term | $	$ 900		$ 100
Decrease in expense due to change in expected term | $	$ (1,100)		$ (200)
Number of peer companies to estimate volatility | item	6		6
Expected volatility rate, minimum (as a percent)			38.50%
Expected volatility rate, maximum (as a percent)			65.90%
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	628,468
Granted (in shares) | shares			2,035
Forfeited (in shares) | shares			(2,697)
Stock options outstanding at end of period (in shares) | shares	627,806		627,806
Weighted Average Exercise Price
Stock options outstanding at beginning of period (in dollars per share) | $ / shares		$ 19.66	$ 19.66
Granted (in dollars per share) | $ / shares			20.97
Forfeited (in dollars per share) | $ / shares			19.66
Stock options outstanding at end of period (in dollars per share) | $ / shares	$ 19.66		$ 19.66
Weighted Average Remaining Contractual Term (Years)
Granted (in years)		9 years 9 months 18 days	9 years 10 months 24 days
Stock options outstanding at end of period (in years)			9 years 9 months 18 days
Additional information
Unrecognized expense for share-based compensation | $	$ 5,800		$ 5,800
Weighted-average period for over which unrecognized expense will be recognized			1 year 9 months 18 days
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

Equity and Share-Based Compen70

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 ($)item$ / sharesshares	Dec. 31, 2016USD ($)item$ / 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%
Expected volatility (as a percent)			60.00%
Market Price Hurdle (in dollars per share)		$ 30	$ 30
Calculated fair value per restricted stock unit (in dollars per share)		$ 17.71	$ 17.71
Number of peer companies to estimate volatility | item		6	6
Expected volatility rate, minimum (as a percent)			39.80%
Expected volatility rate, maximum (as a percent)			61.40%
Service period (in years)			1 year
Unrecognized expense for share-based compensation | $		$ 1.2	$ 1.2
Weighted-average period for over which unrecognized expense will be recognized			10 months 24 days
Shares
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
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	$ 0.1

Equity and Share-Based Compen71

Equity and Share-Based Compensation - Unrestricted Common Share Awards (Details) - USD ($) $ in Thousands	Oct. 21, 2016	Dec. 31, 2016
Share-Based Compensation
Share-based compensation costs recognized		$ 2,909
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

Equity and Share-Based Compen72

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, 2015	Dec. 31, 2014
Stock-Based Compensation Expense Summary
Total stock-based compensation	$ 3,546
Less: amounts capitalized to oil and natural gas properties	(637)
Net stock-based compensation	2,909
Restricted Stock Units
Stock-Based Compensation Expense Summary
Total stock-based compensation	2,114
Less: amounts capitalized to oil and natural gas properties	(400)
Stock Options
Stock-Based Compensation Expense Summary
Total stock-based compensation	1,046
Less: amounts capitalized to oil and natural gas properties	(200)
Restricted Stock Units with Market Condition
Stock-Based Compensation Expense Summary
Total stock-based compensation	142
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	$ 10,863
Less: amounts capitalized to oil and natural gas properties		(476)	(1,347)	(2,244)
Net stock-based compensation		2,564	4,408	8,619
Predecessor | Restricted Stock Units
Stock-Based Compensation Expense Summary
Total stock-based compensation		3,040	5,755	10,863
Less: amounts capitalized to oil and natural gas properties		$ (500)	$ (1,300)	$ (2,200)

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes
Estimated Amount of Cancellation of Indebtedness Income			$ 1,200,000
Income (loss) before taxes	$ 9,930
Income tax payments expected in the upcoming four quarterly reporting periods			0
Valuation allowance	160,800		160,800
Decreased valuation allowance			532,600
Reconciliation of income tax expense
Income (loss) before taxes	$ 9,930
Statutory rate	35.00%
Income tax provision (benefit) computed at statutory rate	$ 3,475
Reconciling items:
State income taxes, net of federal benefit	296
Valuation allowance in light of the impairment of oil and gas properties	(3,876)
Change in state rate	(1)
Deferred tax true-ups	74
Other, net	32
Deferred tax assets - noncurrent
Employee benefit plans	3,649		3,649
Oil and gas properties and equipment	157,113		157,113
Other	27		27
Less valuation allowance	(160,789)		(160,789)
Property and equipment
Income Taxes
Valuation allowance	$ 157,100		$ 157,100
Predecessor
Income Taxes
Income (loss) before taxes		$ 1,323,079		$ (1,806,836)	$ 123,324
Current
State					809
Total current					809
Deferred
United States				(3,864)	3,863
State				(5,777)	1,723
Total deferred				(9,641)	5,586
Total income tax provision (benefit)				9,641	(6,395)
Reconciliation of income tax expense
Income (loss) before taxes		$ 1,323,079		$ (1,806,836)	$ 123,324
Statutory rate		35.00%		35.00%	35.00%
Income tax provision (benefit) computed at statutory rate		$ 463,078		$ (632,393)	$ 43,164
Reconciling items:
State income taxes, net of federal benefit		39,424		(65,904)	4,398
Valuation allowance in light of the impairment of oil and gas properties		(528,706)		689,419	(42,134)
Change in state rate		(153)		(612)	(414)
Bankruptcy items		12,262
Deferred tax true-ups		9,891
Other, net		$ 4,204		(151)	1,381
Total income tax provision (benefit)				(9,641)	$ 6,395
Deferred tax assets - noncurrent
Federal tax loss carryforwards				146,641
State tax loss carryforwards				13,848
Employee benefit plans				1,160
Oil and gas properties and equipment				465,028
Debt restructuring				66,693
Less valuation allowance				$ (693,370)

Earnings (Loss) Per Share (Deta

Earnings (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
	Oct. 20, 2016	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Oct. 20, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings (Loss) Per Share
Net income (loss)		$ 9,930
Participating securities - non-vested restricted stock		(280)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		$ 9,650
Basic and diluted weighted average number of common shares outstanding		25,009,000
Basic and diluted net income (loss) per share (in dollars per share)		$ 0.39
Common shares outstanding - basic		25,009,300
Common shares outstanding - diluted		25,009,300
Basic (in dollars per share)		$ 0.39
Diluted (in dollars per share)		$ 0.39
Shares of common stock to be issued by required Plan		17,533,000
Stock Options
Earnings (Loss) Per Share
Antidilutive securities (in shares)		627,000
Warrants
Earnings (Loss) Per Share
Antidilutive securities (in shares)		6,626,000
Predecessor
Earnings (Loss) Per Share
Net income (loss)	$ 1,531,775		$ (38,384)	$ 8,962	$ (179,274)	$ (510,862)	$ (494,342)	$ (598,437)	$ (193,554)	$ 1,323,079	$ (1,797,195)	$ 116,929
Preferred Dividend											(948)	(10,378)
Net income (loss) attributable to shareholders										1,323,079	(1,798,143)	106,551
Participating securities - Series A Preferred Stock												(35,696)
Participating securities - non-vested restricted stock										(16,522)		(3,584)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 1,515,351		$ (38,384)	$ 8,864	$ (179,274)	$ (510,862)	$ (494,490)	$ (599,106)	$ (193,685)	$ 1,306,557	$ (1,798,143)	$ 67,271
Basic and diluted weighted average number of common shares outstanding	10,657,000		10,657,000	10,653,000	10,621,000	10,537,000	6,835,000	6,774,000	6,726,000	10,645,000	7,726,000	6,644,000
Basic and diluted net income (loss) per share (in dollars per share)	$ 142.19		$ (3.60)	$ 0.83	$ (16.88)	$ (48.48)	$ (72.34)	$ (88.44)	$ (28.80)	$ 122.74	$ (232.74)	$ 10.13

Concentrations of Credit Risk (

Concentrations of Credit Risk (Details)	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016derivativeitem	Oct. 20, 2016item	Dec. 31, 2016derivative	Dec. 31, 2015derivativeitem	Dec. 31, 2014item
Concentrations of Credit Risk
Short-term contracts usual term			1 month
Number of derivatives held | derivative	0		0
Revenue | Customer concentration
Concentrations of Credit Risk
Number of purchasers	2
Revenue | Customer concentration | Purchaser one
Concentrations of Credit Risk
Concentration risk (as a percent)	40.00%
Revenue | Customer concentration | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)	29.00%
Accounts receivable | Customer concentration
Concentrations of Credit Risk
Number of purchasers	2
Accounts receivable | Customer concentration | Purchaser one
Concentrations of Credit Risk
Concentration risk (as a percent)	44.00%
Accounts receivable | Customer concentration | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)	26.00%
Predecessor
Concentrations of Credit Risk
Number of derivatives held | derivative				0
Predecessor | Revenue | Customer concentration
Concentrations of Credit Risk
Number of purchasers		2		2	4
Predecessor | Revenue | Customer concentration | Purchaser one
Concentrations of Credit Risk
Concentration risk (as a percent)		46.00%		43.00%	28.00%
Predecessor | Revenue | Customer concentration | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)		29.00%		25.00%	18.00%
Predecessor | Revenue | Customer concentration | Purchaser three
Concentrations of Credit Risk
Concentration risk (as a percent)					15.00%
Predecessor | Revenue | Customer concentration | Purchaser four
Concentrations of Credit Risk
Concentration risk (as a percent)					12.00%
Predecessor | Accounts receivable | Customer concentration
Concentrations of Credit Risk
Number of purchasers				3
Predecessor | Accounts receivable | Customer concentration | Purchaser one
Concentrations of Credit Risk
Concentration risk (as a percent)				33.00%
Predecessor | Accounts receivable | Customer concentration | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)				29.00%
Predecessor | Accounts receivable | Customer concentration | Purchaser three
Concentrations of Credit Risk
Concentration risk (as a percent)				14.00%

Commitments and Contingencies76

Commitments and Contingencies (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 20, 2016	Dec. 31, 2015	Dec. 31, 2014
Net minimum commitments
2,017	$ 642
2,018	654
2,019	666
2,020	677
2021 and beyond	3,992
Total	6,631
Office rent	100
Loss Contingency Accrual	1,100
Non-cancellable office lease commitments
Net minimum commitments
2,017	642
2,018	654
2,019	666
2,020	677
2021 and beyond	3,992
Total	$ 6,631
Predecessor
Net minimum commitments
Office rent		$ 4,300	$ 2,300	$ 2,300
Loss Contingency Accrual			$ 1,100

Supplemental Information to C77

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, 2015	Dec. 31, 2014
SUPPLEMENTAL INFORMATION:
Non-cash investment in property and equipment	$ 8,135
Cash paid for interest, net of capitalized interest for the Successor Period and the years ended December 31, 2015 and 2014 of $0.7 million, $4.9 million and $12.4 million, respectively (no capitalized interest for the Predecessor Period)	426
Capitalized interest	$ 700
Predecessor
SUPPLEMENTAL INFORMATION:
Non-cash investment in property and equipment		$ 12,995	$ 21,507	$ 95,000
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 Successor Period and the years ended December 31, 2015 and 2014 of $0.7 million, $4.9 million and $12.4 million, respectively (no capitalized interest for the Predecessor Period)		6,709	161,285	129,511
Cash paid for reorganization items		36,325
Cash paid for taxes				209
Capitalized interest		0	4,900	12,400
Predecessor | Pine Prairie Disposition
SUPPLEMENTAL INFORMATION:
Asset retirement obligation disposed				(7,652)
Accrual for miscellaneous liabilities assumed				(2,185)
Other noncurrent assets sold				$ 371
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) - Dixie Electric - Electrical equipment and related services - USD ($) $ in Millions	2 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transactions
Amount paid to related party	$ 0	$ 1.7
Predecessor
Related Party Transactions
Amount paid to related party			$ 0	$ 0

Supplemental Oil and Gas Disc79

Supplemental Oil and Gas Disclosures - 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, 2015	Dec. 31, 2014
Acquisition costs:
Unproved properties	$ 1,430
Development costs	17,708
Total costs incurred	$ 19,138
Predecessor
Acquisition costs:
Unproved properties		$ 6,869	$ 8,448	$ 25,576
Exploration costs				672
Development costs		121,668	274,978	525,941
Total costs incurred		$ 128,537	$ 283,426	$ 552,189

Supplemental Oil and Gas Disc80

Supplemental Oil and Gas Disclosures - Capitalized Costs (Details) - USD ($) $ in Thousands	2 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs, Net
Proved properties	$ 573,150
Unproved properties not being amortized	65,080
Gross capitalized costs	638,230
Less: Accumulated depreciation, depletion, amortization and impairment	(12,587)
Net capitalized costs	625,643
Mississippian Lime area
Capitalized Costs, Net
Unproved properties not being amortized	65,100
Capitalized interest	$ 700
Maximum period considered for depletion (in years)	10 years
Predecessor
Capitalized Costs, Net
Proved properties		$ 3,666,403
Gross capitalized costs		3,666,403
Less: Accumulated depreciation, depletion, amortization and impairment		(3,148,240)
Net capitalized costs		$ 518,163

Supplemental Oil and Gas Disc81

Supplemental Oil and Gas Disclosures - 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, 2015MBoeMMcfMBbls	Dec. 31, 2014MBoeMMcfMBbls
Proved Reserves, Total
Beginning Balance | MBoe	65,318
Revision of previous estimates | MBoe	55,172
Extensions, discoveries and other additions | MBoe	58,296
Production | MBoe	(1,798)
Net proved reserves | MBoe	176,988
Proved developed reserves | MBoe	69,622
Proved undeveloped reserves | MBoe	107,366
Oil
Proved Reserves
Beginning Balance	20,226
Revision of previous estimates	19,137
Extensions, discoveries and other additions	22,571
Production	(544)
Net proved reserves	61,390
Proved developed reserves	19,698
Proved undeveloped reserves	41,692
NGL
Proved Reserves
Beginning Balance	14,694
Revision of previous estimates	11,421
Extensions, discoveries and other additions	11,186
Production	(429)
Net proved reserves	36,872
Proved developed reserves	16,349
Proved undeveloped reserves	20,523
Gas
Proved Reserves
Beginning Balance | MMcf	182,383
Revision of previous estimates | MMcf	147,688
Extensions, discoveries and other additions | MMcf	147,236
Production | MMcf	(4,948)
Net proved reserves | MMcf	472,359
Proved developed reserves | MMcf	201,454
Proved undeveloped reserves | MMcf	270,905
Predecessor
Proved Reserves, Total
Beginning Balance | MBoe		73,540	153,744	127,755
Revision of previous estimates | MBoe		(3,706)	(75,700)	(22,925)
Extensions, discoveries and other additions | MBoe		4,249	6,398	77,035
Sales of reserves in place | MBoe			(5,019)	(16,391)
Purchases of reserves in place | MBoe			6,118
Production | MBoe		(8,765)	(12,001)	(11,730)
Net proved reserves | MBoe		65,318	73,540	153,744
Proved developed reserves | MBoe		65,318	69,110	73,620
Proved undeveloped reserves | MBoe			4,430	80,124
Predecessor | Oil
Proved Reserves
Beginning Balance		24,713	58,242	54,899
Revision of previous estimates		(3,089)	(30,490)	(11,563)
Extensions, discoveries and other additions		1,566	2,189	30,232
Sales of reserves in place			(2,871)	(10,182)
Purchases of reserves in place			2,437
Production		(2,964)	(4,794)	(5,144)
Net proved reserves		20,226	24,713	58,242
Proved developed reserves		20,226	23,006	27,181
Proved undeveloped reserves			1,707	31,061
Predecessor | NGL
Proved Reserves
Beginning Balance		16,245	32,528	26,156
Revision of previous estimates		(459)	(15,495)	(4,444)
Extensions, discoveries and other additions		840	1,371	15,414
Sales of reserves in place			(843)	(2,181)
Purchases of reserves in place			1,157
Production		(1,932)	(2,473)	(2,417)
Net proved reserves		14,694	16,245	32,528
Proved developed reserves		14,694	15,376	16,443
Proved undeveloped reserves			869	16,085
Predecessor | Gas
Proved Reserves
Beginning Balance | MMcf		195,492	377,845	280,198
Revision of previous estimates | MMcf		(946)	(178,287)	(41,510)
Extensions, discoveries and other additions | MMcf		11,052	17,026	188,336
Sales of reserves in place | MMcf			(7,834)	(24,166)
Purchases of reserves in place | MMcf			15,145
Production | MMcf		(23,215)	(28,403)	(25,013)
Net proved reserves | MMcf		182,383	195,492	377,845
Proved developed reserves | MMcf		182,383	184,365	179,972
Proved undeveloped reserves | MMcf			11,127	197,873

Supplemental Oil and Gas Disc82

Supplemental Oil and Gas Disclosures - Revision of Previous Estimates, Extensions, Discoveries and Other Additions and Sales of Reserves in Place (Details) $ in Millions	2 Months Ended		10 Months Ended	12 Months Ended
	Dec. 31, 2016MBoe	Dec. 31, 2016	Oct. 20, 2016MBoe	Dec. 31, 2015USD ($)MBoe	Dec. 31, 2014MBoe
Estimated Quantities of Proved Oil and Natural Gas Reserves
Revision of Previous Estimates, development schedule (in years)		5 years
Revision of Previous Estimates, development plan (in years)		5 years
Revision of previous estimates	55,172
Extensions, Discoveries and Other Additions, development schedule (in years)		5 years
Extensions, Discoveries and Other Additions, development plan (in years)		5 years
Predecessor
Estimated Quantities of Proved Oil and Natural Gas Reserves
Revision of previous estimates			(3,706)	(75,700)	(22,925)
Sales of reserves in place				5,019	16,391
Predecessor | Dequincy Divestiture
Estimated Quantities of Proved Oil and Natural Gas Reserves
Sales of reserves in place				2,307
Predecessor | Gulf Coast area
Estimated Quantities of Proved Oil and Natural Gas Reserves
Revision of previous estimates					3,084
Predecessor | Anadarko Basin area
Estimated Quantities of Proved Oil and Natural Gas Reserves
Revision of previous estimates					22,138
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)				77,362
Amount of transfer of proved undeveloped reserves | $				$ 179
Partially offset due to positive revisions (in MBoe)					2,297
Predecessor | Mississippian Lime area | Interest rate swap
Estimated Quantities of Proved Oil and Natural Gas Reserves
Sales of reserves in place				2,712

Supplemental Oil and Gas Disc83

Supplemental Oil and Gas Disclosures - Benchmark Prices Used to Determine Estimated Proved Reserves (Details)	Dec. 31, 2016$ / MMBTU$ / bbl	Dec. 31, 2015$ / MMBTU$ / bbl	Dec. 31, 2014$ / MMBTU$ / bbl
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)	42.75
NGL
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)	15.29
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	2.48
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)		50.28	94.99
Predecessor | NGL
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)		17.44	39.17
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	4.35

Supplemental Oil and Gas Disc84

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows from Projected Production (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Oct. 21, 2016	Oct. 20, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Standardized measure of discounted future net cash flows
Future cash inflows	$ 4,186,389
Future production costs	(2,078,640)
Future development costs	(692,533)
Future income tax expense	(106,563)
Future net cash flows	1,308,653
10% annual discount for estimated timing of cash flows	(778,703)
Standardized measure of discounted future net cash flows	$ 529,950	$ 349,905
Predecessor
Standardized measure of discounted future net cash flows
Future cash inflows				$ 1,902,184	$ 8,405,916
Future production costs				(1,024,314)	(2,669,000)
Future development costs				(47,532)	(751,353)
Future income tax expense					(1,113,908)
Future net cash flows				830,338	3,871,655
10% annual discount for estimated timing of cash flows				(317,519)	(1,998,294)
Standardized measure of discounted future net cash flows			$ 349,905	$ 512,819	$ 1,873,361	$ 1,790,446

Supplemental Oil and Gas Disc85

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, 2015	Dec. 31, 2014
Changes in Standardized Measure of Discounted Future Net Cash Flows
Net changes in prices and production costs	$ 78,103
Net changes in future development costs	2,022
Sales of oil and natural gas, net	(27,292)
Extensions	102,087
Revisions of previous quantity estimates	102,623
Accretion of discount	5,832
Net change in income taxes	(48,206)
Changes in timing, other	(35,124)
Standardized measure, end of period	529,950
Predecessor
Changes in Standardized Measure of Discounted Future Net Cash Flows
Standardized measure, beginning of period	$ 349,905	$ 512,819	$ 1,873,361	$ 1,790,446
Net changes in prices and production costs		(113,313)	(960,245)	(190,256)
Net changes in future development costs		175	57,357	66,828
Sales of oil and natural gas, net		(116,043)	(232,630)	(536,362)
Extensions		29,871	38,550	1,094,606
Purchases of reserves in place			34,369
Divestiture of reserves			(77,445)	(390,264)
Revisions of previous quantity estimates		(22,194)	(1,174,997)	(205,233)
Previously estimated development costs incurred		29,975	198,564	160,663
Accretion of discount		42,735	238,639	206,783
Net change in income taxes			513,024	(230,401)
Changes in timing, other		(14,120)	4,272	106,551
Standardized measure, end of period		$ 349,905	$ 512,819	$ 1,873,361

Selected Quarterly Financial 86

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	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Oct. 20, 2016	Dec. 31, 2015	Dec. 31, 2014
Total revenues		$ 48,525
Operating income (loss)		10,673
Net income (loss)		9,930
Net income (loss) available to common shareholders		$ 9,650
Net income (loss) per share
Basic and diluted net income (loss) per share		$ 0.39
Shares used in computation
Basic and diluted weighted average number of common shares outstanding		25,009
Predecessor
Total revenues	$ 14,514		$ 64,193	$ 62,559	$ 51,961	$ 68,830	$ 110,363	$ 74,754	$ 111,198	$ 193,228	$ 365,145	$ 794,183
Operating income (loss)	(4,101)		(12,944)	(52,759)	(135,119)	(470,328)	(453,790)	(553,584)	(166,101)	(204,923)	(1,643,803)	260,833
Net income (loss)	1,531,775		(38,384)	8,962	(179,274)	(510,862)	(494,342)	(598,437)	(193,554)	1,323,079	(1,797,195)	116,929
Net income (loss) available to common shareholders	$ 1,515,351		$ (38,384)	$ 8,864	$ (179,274)	$ (510,862)	$ (494,490)	$ (599,106)	$ (193,685)	$ 1,306,557	$ (1,798,143)	$ 67,271
Net income (loss) per share
Basic and diluted net income (loss) per share	$ 142.19		$ (3.60)	$ 0.83	$ (16.88)	$ (48.48)	$ (72.34)	$ (88.44)	$ (28.80)	$ 122.74	$ (232.74)	$ 10.13
Shares used in computation
Basic and diluted weighted average number of common shares outstanding	10,657		10,657	10,653	10,621	10,537	6,835	6,774	6,726	10,645	7,726	6,644