Amplify Energy (AMPY) 10-K 30 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Mar. 28, 2016	Jun. 30, 2015
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, 2015
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	Non-accelerated Filer
Entity Public Float			$ 42
Entity Common Stock, Shares Outstanding		10,798,029
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 81,093	$ 11,557
Accounts receivable:
Oil and gas sales	33,656	69,161
Joint interest billing	12,503	42,407
Other	17,506	22,193
Commodity derivative contracts		126,709
Other current assets	1,044	1,098
Total current assets	145,802	273,125
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting	3,666,403	3,442,681
Other property and equipment	14,798	13,454
Less accumulated depreciation, depletion, amortization and impairment	(3,157,332)	(1,333,019)
Net property and equipment	523,869	2,123,116
OTHER ASSETS:
Deferred income taxes		35,821
Other noncurrent assets	9,496	15,113
Total other assets	9,496	50,934
TOTAL	679,167	2,447,175
CURRENT LIABILITIES:
Accounts payable	1,904	22,783
Accrued liabilities	91,712	183,831
Debt classified as current less unamortized debt issuance costs (Note 2)	1,890,944
Deferred income taxes		44,862
Total current liabilities	1,984,560	251,476
LONG-TERM LIABILITIES:
Asset retirement obligations	18,708	21,599
Long-term debt less unamortized debt issuance costs		1,706,532
Other long-term liabilities	1,965	1,706
Total long-term liabilities	$ 20,673	$ 1,729,837
COMMITMENTS AND CONTINGENCIES (Note 15)
STOCKHOLDERS' EQUITY (DEFICIT):
Common stock, $0.01 par value, 100,000,000 shares authorized; 10,962,105 shares issued and 10,865,814 shares outstanding at December 31, 2015 and 7,049,173 shares issued and 6,995,705 shares outstanding at December 31, 2014	$ 110	$ 70
Treasury stock	(3,081)	(2,592)
Additional paid-in-capital	888,247	882,528
Retained deficit	(2,211,342)	(414,147)
Total stockholders' equity (deficit)	(1,326,066)	465,862
TOTAL	$ 679,167	$ 2,447,175
Preferred Stock
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred stock
Series A Preferred Stock
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred stock		$ 3
Total stockholders' equity (deficit)		$ 3

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2015
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	7,049,173	10,962,105
Common stock, shares outstanding	6,995,705	10,865,814
Preferred Stock
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	49,675,000	49,675,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Series A Preferred Stock
Preferred stock, par value (in dollars per share)	$ 0.01
Preferred stock, liquidation value (in dollars per share)	$ 387,808
Preferred stock, cumulative dividends (as a percent)	8.00%
Preferred stock, shares issued	325,000	0
Preferred stock, shares outstanding	325,000	0

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES :
Oil sales	$ 217,636	$ 466,655	$ 387,226
Natural gas liquid sales	38,249	87,771	62,340
Natural gas sales	66,823	99,204	63,187
Gains (losses) on commodity derivative contracts - net	40,960	139,189	(44,284)
Other	1,477	1,364	1,037
Total revenues	365,145	794,183	469,506
EXPENSES :
Lease operating and workover	81,473	79,598	73,414
Gathering and transportation	15,546	13,404	5,455
Severance and other taxes	8,605	24,266	27,237
Asset retirement accretion	1,610	1,706	1,435
Depreciation, depletion, and amortization	198,643	269,935	250,396
Impairment in carrying value of oil and gas properties	1,625,776	86,471	453,310
General and administrative	38,703	48,733	53,250
Acquisition and transaction costs	330	4,129	11,803
Debt restructuring costs and advisory fees	36,141
Other	2,121	5,108	615
Total expenses	2,008,948	533,350	876,915
OPERATING INCOME (LOSS)	(1,643,803)	260,833	(407,409)
OTHER INCOME (EXPENSE):
Interest income	115	39	33
Interest expense - net of amounts capitalized	(163,148)	(137,548)	(83,138)
Total other expense	(163,033)	(137,509)	(83,105)
INCOME (LOSS) BEFORE TAXES	(1,806,836)	123,324	(490,514)
Income tax (expense) benefit	9,641	(6,395)	146,529
NET INCOME (LOSS)	(1,797,195)	116,929	(343,985)
Preferred stock dividend	(948)	(10,378)	(15,589)
Participating securities - Series A Preferred Stock		(35,696)
Participating securities - Non-vested Restricted Stock		(3,584)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (1,798,143)	$ 67,271	$ (359,574)
Basic and diluted net income (loss) per share attributable to common shareholders	$ (232.74)	$ 10.13	$ (54.68)
Basic and diluted weighted average number of common shares outstanding	7,726	6,644	6,576

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT) - USD ($) $ in Thousands	Series A Preferred Stock	Common Stock	Treasury Stock	Additional Paid-in-Capital	Retained Deficit	Total
Balance at Dec. 31, 2012	$ 3	$ 67		$ 864,490	$ (187,091)	$ 677,469
Increase (Decrease) in Stockholders' Equity
Share-based compensation		2		7,177		7,179
Acquisition of treasury stock			$ (664)			(664)
Net income (loss)					(343,985)	(343,985)
Balance at Dec. 31, 2013	3	69	(664)	871,667	(531,076)	339,999
Increase (Decrease) in Stockholders' Equity
Share-based compensation		1		10,861		10,862
Acquisition of treasury stock			(1,928)			(1,928)
Net income (loss)					116,929	116,929
Balance at Dec. 31, 2014	3	70	(2,592)	882,528	(414,147)	465,862
Increase (Decrease) in Stockholders' Equity
Share-based compensation		3		5,753		5,756
Acquisition of treasury stock			(489)			(489)
Net income (loss)					(1,797,195)	(1,797,195)
Conversion of preferred shares	$ (3)	37		(34)
Balance at Dec. 31, 2015		$ 110	$ (3,081)	$ 888,247	$ (2,211,342)	$ (1,326,066)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (1,797,195)	$ 116,929	$ (343,985)
Adjustments to reconcile net loss to net cash provided by operating activities:
(Gains) losses on commodity derivative contracts - net	(40,960)	(139,189)	44,284
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments	167,669	(18,332)	(17,585)
Asset retirement accretion	1,610	1,706	1,435
Depreciation, depletion, and amortization	198,643	269,935	250,396
Impairment in carrying value of oil and gas properties	1,625,776	86,471	453,310
Share-based compensation, net of amounts capitalized to oil and gas properties	4,408	8,618	5,713
Deferred income taxes	(9,641)	5,586	(146,529)
Amortization of deferred financing costs	11,316	7,857	5,955
Paid-in-kind interest expense	6,415
Amortization of deferred gain on debt restructuring	(14,948)
Transaction costs for debt restructuring	34,398
Change in operating assets and liabilities:
Accounts receivable - oil and gas sales	26,437	33,322	(66,865)
Accounts receivable - JIB and other	22,833	(18,897)	(18,002)
Other current and noncurrent assets	590	3,191	(1,802)
Accounts payable	(4,176)	2,327	(4,350)
Accrued liabilities	(20,887)	(7,733)	75,903
Other	1,095	(247)	(290)
Net cash provided by operating activities	213,383	351,544	237,588
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(336,922)	(556,397)	(584,220)
Investment in acquired property			(620,112)
Proceeds from the sale of oil and gas properties	42,366	152,133
Net cash used in investing activities	(294,556)	(404,264)	(1,204,332)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings	625,000		700,000
Proceeds from revolving credit facility	33,000	165,000	341,450
Repayment of revolving credit facility	(468,150)	(131,000)	(34,300)
Deferred financing costs	(4,254)	(958)	(25,457)
Transaction costs for debt restructuring	(34,398)
Acquisition of treasury stock	(489)	(1,928)	(664)
Net cash provided by financing activities	150,709	31,114	981,029
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	69,536	(21,606)	14,285
Cash and cash equivalents, beginning of period	11,557	33,163	18,878
Cash and cash equivalents, end of period	81,093	11,557	33,163
SUPPLEMENTAL INFORMATION:
Non-cash investment in property and equipment	21,507	95,000	106,500
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 of $4.9 million, $12.4 million and $32.2 million, respectively	161,285	129,511	72,085
Cash paid for taxes		209
Pine Prairie Disposition
Non-cash components of Disposition:
Asset retirement obligation disposed		(7,652)
Accrual for miscellaneous liabilities assumed		(2,185)
Other noncurrent assets sold		371
Dequincy Divestiture
Non-cash components of Disposition:
Asset retirement obligation disposed	$ (4,699)
Eagle Property Acquisition
Non-cash components of Business Acquisition Purchase Price:
Deferred tax liability assumed			(727)
Accrual for additional consideration			(941)
Anadarko Basin Acquisition
Non-cash components of Business Acquisition Purchase Price:
Asset retirement obligations assumed			6,296
Accrual for miscellaneous liabilities assumed		$ (344)	$ 3,030

CONSOLIDATED STATEMENTS OF CAS7

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CONSOLIDATED STATEMENTS OF CASH FLOWS
Capitalized interest	$ 4.9	$ 12.4	$ 32.2

Organization and Business

Organization and Business	12 Months Ended
	Dec. 31, 2015
Organization and Business
Organization and Business	1. Organization and Business Midstates Petroleum Company, Inc., through its wholly-owned subsidiary Midstates Petroleum Company LLC, the only subsidiary of Midstates Petroleum Company, Inc., engages in the business of drilling for, and production of, oil, natural gas liquids ("NGLs") and natural gas. 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, and for historical periods prior to April 25, 2012, refer to Midstates Petroleum Holdings LLC and its subsidiary, unless the context indicates otherwise. The term "Holdings LLC" refers solely to Midstates Petroleum Holdings LLC prior to the corporate reorganization. On October 1, 2012, the Company closed on the acquisition of all of Eagle Energy Production, LLC's producing properties as well as its developed and undeveloped acreage primarily in the Mississippian Lime liquids play in Oklahoma and Kansas for $325.0 million in cash and 325,000 shares of the Company's Series A Preferred Stock with an initial liquidation preference value of $1,000 per share (the "Eagle Property Acquisition"). The Company funded the cash portion of the Eagle Property Acquisition purchase price with a portion of the net proceeds from the private placement of the 2020 Senior Notes (as defined below). On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas and Oklahoma from Panther Energy Company, LLC and its partners for approximately $618.0 million in cash (the "Anadarko Basin Acquisition"), before customary post-closing adjustments. The Company funded the purchase price with a portion of the net proceeds from the private placement of the 2021 Senior Notes (as defined below). 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 reserves 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 does have approximately 11,757 net acres of undeveloped acreage under lease in Louisiana. At December 31, 2015, the Company had oil and gas operations and properties in Oklahoma, Texas and Louisiana. The Company operates a significant portion of its oil and natural gas properties and is engaged in the exploration, development and production of oil, NGLs and natural gas. 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.

Liquidity and Ability to Contin

Liquidity and Ability to Continue as a Going Concern	12 Months Ended
	Dec. 31, 2015
Liquidity and Ability to Continue as a Going Concern
Liquidity and Ability to Continue as a Going Concern	2. Liquidity and Ability to Continue as a Going Concern The Company's decisions on capital structure, hedging and drilling are based upon widely available information of anticipated future commodity pricing and expected economic conditions. The unexpected substantial decrease in oil and gas prices that began in the second half of 2014 and continued throughout 2015 and into 2016 has resulted in materially lower operating cash flows than expected. The Company's hedging contracts helped to mitigate the impact of lower commodity prices during 2015 and the Company received cash settlements of these derivatives of $167.7 million, which comprised 78.6% of its cash provided by operations during 2015. However, all of the Company's hedging contracts expired during 2015, and as a result, the Company will not receive any cash derivative settlements for 2016 or future periods, which will materially lower cash provided by operations in those future periods as compared to its historical operating cash flows. As a result of the commodity price decline and the Company's substantial debt burden, the Company took steps to increase its liquidity and amend certain debt covenants during 2015. On April 21, 2015, the Company closed on the Dequincy Divestiture for approximately $44.0 million, before customary post-closing adjustments. Additionally, on May 21, 2015, the Company sold $625.0 million of 10.0% Second Lien Notes due 2020 (the "Second Lien Notes") and utilized a portion of the proceeds to repay the outstanding balance of its reserve based revolving credit facility (the "Credit Facility") of approximately $468.2 million. Further, the Company exchanged approximately $504.1 million of 12.0% Third Lien Notes due 2020 (the "Third Lien Notes") for approximately $279.8 million of the 10.75% Senior Unsecured Notes due 2020 (the "2020 Senior Notes") and $350.3 million of the 9.25% Senior Unsecured Notes due 2021(the "2021 Senior Notes", together with the 2020 Senior Notes the "Unsecured Notes", and together with the Second Lien Notes and the Third Lien Notes the "Senior Notes"), representing an exchange at 80.0% of the exchanged Unsecured Notes' par value. Furthermore, 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. For further information regarding the Second Lien Notes, Third Lien Notes and updates to the Company's debt covenants, see "—Note 9. Debt." These transactions increased the liquidity position of the Company; however, due to depressed commodity prices, the Company continues to face the risk of a liquidity shortfall. The terms of the Credit Facility and the indentures governing the Senior Notes require that some or all of the proceeds from asset sales, if any, must be used to permanently reduce outstanding debt, which could substantially reduce the amount of proceeds ultimately retained and therefore reduce the impact to the Company's liquidity as a result of any such sale. Further, the covenants in these debt instruments impose limitations on the amount and type of additional indebtedness the Company can incur, which may significantly reduce its ability to obtain liquidity through the incurrence of additional indebtedness. The ability to refinance any of the existing indebtedness on commercially reasonably terms will likely be materially and adversely impacted by the current conditions in the energy industry and the Company's financial condition. The Company has substantial interest payment obligations related to its debt over the next twelve months. As of December 31, 2015, payments due on contractual obligations during the next twelve months were approximately $188.0 million comprised of approximately $179.5 million of interest payments on the Senior Notes and other operating expenses such as fixed drilling commitments and operating leases. As a result of the sustained commodity price decline and the Company's substantial debt burden, the Company believes that forecasted cash and available credit capacity will not be sufficient to meet commitments as they come due over the next twelve months, and it will not be able to remain in compliance with current debt covenants unless it is able to successfully increase liquidity or deleverage. The uncertainty associated with the ability to meet commitments as they come due or to repay outstanding debt raises substantial doubt about the Company's ability to continue as a going concern. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern. The Company is required to receive an unqualified auditors' opinion in relation to the 2015 consolidated financial statements. The failure to receive an unqualified opinion is an event of default under the Credit Facility that must be cured within 30 days of such event or waived by the lenders under the Credit Facility. In consideration of the uncertainty mentioned above, the report of the Company's independent registered public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31, 2015 in this Annual Report on Form 10-K contains an explanatory paragraph regarding an event of default under the Credit Facility, a projected additional debt covenant violation, and resulting lack of liquidity, which raises substantial doubt about the Company's ability to continue as a going concern. The report of the Company's independent registered public accounting firm that accompanied its consolidated financial statements for the year ended December 31, 2014 also contained an explanatory paragraph regarding a projected debt covenant violation and resulting lack of liquidity raising substantial doubt about its ability to continue as a going concern; however, the Company obtained a waiver from its lenders under the Credit Facility waiving any default as a result of receiving such explanatory paragraph in 2014. The Company has not received a similar waiver from its lenders under the Credit Facility for the explanatory paragraph to its 2015 independent registered public accounting firm report. As a result, the Company is in default under its Credit Facility. A failure to cure this default within 30 days will result in the acceleration of all of the Company's indebtedness under the Credit Facility. If the lenders under the Company's Credit Facility accelerate the loans outstanding thereunder, the Company will then also be in default under the indentures governing its Senior Notes, in which case the lenders under the indentures governing its Senior Notes could accelerate the repayment thereof. If lenders, and subsequently noteholders, accelerate the Company's outstanding indebtedness, it will become immediately due and payable and the Company will not have sufficient liquidity to repay those amounts. If we are unable to reach an agreement with our creditors prior to any of the above described accelerations, we could be required to immediately file for protection under Chapter 11 of the U.S. Bankruptcy Code. The Company's long-term debt with maturities summarized in Note 9 is reflected as a current liability in its consolidated balance sheet at December 31, 2015. The classification as a current liability is based on the uncertainty regarding the Company's ability to cure the default discussed above and to comply with certain restrictive covenants contained in its Credit Facility and cross default/cross acceleration provisions in the indentures governing the Senior Notes. In order to increase the Company's liquidity to levels sufficient to meet the Company's commitments, the Company is currently undertaking a number of actions, including minimizing capital expenditures, aggressively managing working capital and further reducing its recurring operating expenses. The Company believes that even after taking these actions, it will not have sufficient liquidity to satisfy its debt service obligations, meet other financial obligations, and comply with its debt covenants. The Company has engaged financial and legal advisors to, among other things, assist with analyzing various strategic alternatives to address its liquidity and capital structure. The Company believes a filing under Chapter 11 of the U.S. Bankruptcy Code may provide the most expeditious manner in which to effect a capital structure solution. There can be no assurance the Company will be able to restructure its capital structure on terms acceptable to the Company, its creditors, or at all. In February 2016, the Company borrowed approximately $249.2 million under the Credit Facility, which represented the remaining undrawn amount that was available under the Credit Facility and as a result, as of February 9, 2016, the Company had a cash balance of approximately $335.7 million. The Company's next scheduled interest payment is April 1, 2016 for $15.8 million to the holders of the 2020 Senior Notes and the Company is currently evaluating whether such interest payment will be made. If the payment is not made by April 1, 2016, the Company would have 30 days to cure such payment default before an event of default occurs. Financial Ratio Covenants The Credit Facility contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of Total Senior Indebtedness (as defined therein) to EBITDA (as defined therein) of not more than 1.0 to 1.0 and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. The Credit Facility also limits the Company's ability to make any dividends, distributions or redemptions. Borrowing Base Redetermination The borrowing base under the Credit Facility is subject to semiannual redeterminations in April and October and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by us or the administrative agent, acting on behalf of lenders holding at least two-thirds of the outstanding loans and other obligations. If commodity prices remain depressed or deteriorate further, the borrowing base under the Credit Facility will likely be reduced. Since the Credit Facility was fully drawn subsequent to December 31, 2015, any reduction in the borrowing base will result in a deficiency in the amount that our borrowings exceed the borrowing base, which must be repaid within 30 days or in six equal monthly installments thereafter, at our election. The Company may not have the financial resources to make any mandatory deficiency principal repayments, which could result in an event of default under the Credit Facility. Cross Default Provisions The debt facilities contain significant cross default and/or cross acceleration provisions where a default under the Credit Facility or one of the indentures could enable the lenders of the other debt to also declare events of default and accelerate repayment of the obligations under those debt instruments. In general, these cross default/cross acceleration provisions are as follows: · The Credit Facility allows the lenders to declare an event of default if there is an event of default on other indebtedness and that default: (i) is the result of the failure to make any payment when due in respect of other indebtedness having an aggregate principal amount of at least 5% of the then effective borrowing base and such failure continues after the applicable grace or notice period; or (ii) is the result of a failure to perform any condition, covenant or other event and such failure permits the holders of such other indebtedness to cause the acceleration of such other indebtedness. · The indentures governing the Senior Notes allow the lenders to declare an event of default if there is an event of default on other indebtedness and that default: (i) is caused by a failure to make any payment of principal prior to the expiration of the grace period following the final maturity date of such indebtedness; or (ii) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of any such indebtedness, together with the principal amount of any other indebtedness with respect to which an event described herein has occurred, aggregates $50.0 million or more.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies	3. 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 Securities and Exchange Commission ("SEC") and have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP"). All intercompany transactions have been eliminated in consolidation. 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 consolidated financial statements for the year ended December 31, 2013 include the results from the Anadarko Basin Acquisition beginning May 31, 2013. 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. Use of Estimates The preparation of financial statements in conformity with 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 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 commodity derivative contracts, the fair value of share-based compensation, 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, 2015 and 2014 that exceeded the balance insured by the FDIC in the amount of $87.2 million and $34.3 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, 2015 and 2014, 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 4. Fair Value Measurements of Financial Instruments". The fair value of the Company's long-term debt is disclosed, see "—Note 9. 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 are recorded 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 earnings 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, 2015 and 2014, other noncurrent assets consisted of the following: At December 31, 2015 2014 (As Adjusted, Note 3) (in thousands) Deferred financing costs associated with the Credit Facility $ $ Field equipment inventory Other ​ ​ ​ ​ ​ ​ ​ ​ Other noncurrent assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the years ended December 31, 2015 and 2014, the Company recorded $2.0 million and $4.1 million, respectively, 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. 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. During 2014, the Company transferred $59.2 million of Mississippian unevaluated property costs to the full cost pool. These costs were attributable to leases that either expired during 2014, were determined to not be prospective, or that were assigned proved reserves as a result of the Company's development drilling activities. The Company also transferred $128.2 million of Anadarko Basin and $16.5 million of Gulf Coast unevaluated property costs based upon our lack of plans for further evaluation or development of those leases in the current commodity price environment. 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 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 years ended December 31, 2015, 2014 and 2013, the Company recorded impairments of oil and gas properties of $1.6 billion, $86.5 million and $453.3 million respectively. A significant 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 year ended December 31, 2015. For the years ended December 31, 2014 and 2013, the primary factors affecting the impairment related to the transfer of unevaluated property costs to the full cost pool and negative reserve revisions in certain areas. 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 from external borrowings is capitalized on unevaluated properties using the weighted-average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at the date of first production from the field. 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, 2015 and 2014, accrued liabilities consisted of the following: At December 31, 2015 2014 (in thousands) 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 8. 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. 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. See "—Note 11. 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, 2015, 2014 or 2013. Acquisition and Transaction Costs Acquisition and transaction related costs are expensed as incurred and as services are received. Such costs include finders' fees, advisory, legal, accounting, valuation and other professional and consulting fees, and acquisition related general and administrative costs. Costs incurred in 2015 relate to the Dequincy Divestiture and costs incurred in 2014 relate to the Pine Prairie Disposition. Costs incurred in 2013 relate to the Anadarko Basis Acquisition. See "—Note 7. 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 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 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 and outstanding stock options (if any) using the treasury method, as well as the Company's Series A Preferred Stock using the if-converted method (in periods prior to the Preferred Stock's mandatory conversion date). In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that such excess tax benefits are more likely than not to be realized. 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 13. 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 (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance obligation. ASU 2014-09 will be effective for the Company beginning on January 1, 2018, including interim periods within that reporting period, considering the one year deferral provided by ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date." The standard permits the use of either the retrospective or cumulative effect transition method and early adoption is permitted. The Company has not selected a transition method and is evaluating the impact this standard will have on its consolidated financial statements and related disclosures. In April 2015, the FASB issued Accounting Standards Update 2015-03, "Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03") and in August 2015 issued Accounting Standards Update 2015-15, "Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements—Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update)" ("ASU 2015-15"). The ASUs provide that the debt issuance costs are similar to debt discounts and in effect reduce the proceeds of borrowings. ASU 2015-03 amends the FASB ASC to require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the related liability. Prior to the amendment, debt issuance costs were reported in the balance sheet as an asset. ASU 2015-15 further clarified that given ASU 2015-03's silence on debt issuance costs related to revolving credit facilities, the SEC would not object to debt issuance costs for revolving credit facilities being deferred and presented as an asset. The amended guidance is effective for financial statements issued for fiscal years beginning after December 15, 2015; however the Company elected to early adopt effective December 31, 2015. The election requires retrospective application and represents a change in accounting principle. As a result of the adoption, the December 31, 2014 consolidated balance sheet has been adjusted as follows: December 31, 2014 Previously Reported Effect of Accounting Principle Adoption As Adjusted (in thousands) Assets: Other noncurrent assets $ $ ) $ Total other assets ) Total assets ) Liabilities: Long-term debt less unamortized debt issuance costs $ $ ) $ Total long-term liabilities ) Total liabilities and shareholders' equity ) Debt costs associated with the Company's revolving credit facility, under which no borrowings were outstanding at December 31, 2015, remain classified as an asset in accordance with the Company's accounting policy that debt costs related to revolving credit arrangements are deferred and amortized over the term of the arrangement. In September 2015, the FASB issued Accounting Standards Update 2015-16, "Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments" ("ASU 2015-16"). ASU 2015-16 simplifies measurement period adjustments associated with business combinations accounted for under FASB ASC 805, Business Combinations . ASU 2015-16 changes the accounting for measurement period adjustments by eliminating the requirement that such adjustments are made retrospectively. As a result, such measurement period adjustments will be recognized in the reporting period in which the adjustment was determined. ASU 2015-16 is applied prospectively to adjustments to provisional amounts that occur after the effective date. ASU 2015-16 is effective for the Company beginning on January 1, 2016. The Company does not believe the adoption of ASU 2015-16 will have a material impact on its financial position, results of operations or cash flows. In November 2015, the FASB issued Accounting Standards Update 2015-17, "Balance Sheet Classification of Deferred Taxes," ("ASU 2015-17") which requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent in the balance sheet. As a result, the Company now only presents its deferred income taxes on a net noncurrent basis. However, the new guidance does not change the existing requirement that only permits offsetting within a jurisdiction. Companies are still prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. The amendments in this accounting standard are effective for public companies for interim and annual reporting periods beginning after December 15, 2016, with early application permitted. The Company has early adopted this standard and has applied the change in accounting as of December 31, 2015 on a prospective basis. Adoption of this amendment did not have an effect on the Company's financial position or results of operations, and prior periods were not retrospectively adjusted. 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. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new standard is effective for 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 currently evaluating the impact this standard will have on its consolidated financial statements and related disclosures.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	12 Months Ended
	Dec. 31, 2015
Fair Value Measurements of Financial Instruments
Fair Value Measurements of Financial Instruments	4. 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. Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative Instruments —Commodity derivative contracts reflected in the consolidated balance sheets are recorded at estimated fair value. The Company's derivative contracts all expired as of December 31, 2015. As of December 31, 2014, the Company's commodity derivative contracts were with seven counterparties and were classified as Level 2. Fair Value Measurements at December 31, 2014 Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total (in thousands) Assets: Commodity derivative oil swaps $ — $ $ — $ Commodity derivative gas swaps — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total assets $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total liabilities $ — $ — $ — $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Derivative instruments listed above are presented gross and include swaps that are carried at fair value. The Company records the net change in the fair value of these positions in "Gains (losses) on commodity derivative contracts—net" in the Company's consolidated statements of operations. See "—Note 5. Risk Management and Derivative Instruments" for additional information on the Company's derivative instruments and balance sheet presentation.

Risk Management and Derivative

Risk Management and Derivative Instruments	12 Months Ended
	Dec. 31, 2015
Risk Management and Derivative Instruments
Risk Management and Derivative Instruments	5. 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 on an ongoing basis, the Company currently has no derivatives in place as of and for any period subsequent to December 31, 2015. Inherent in the Company's portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company's counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Commodity Derivative Contracts As of December 31, 2015, the Company did not have any open commodity derivative contract positions. Balance Sheet Presentation The following table summarizes the gross fair value of derivative instruments by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company's consolidated balance sheets at December 31, 2015 and 2014, respectively (in thousands): Type Balance Sheet Location(1) December 31, 2015 December 31, 2014 Oil Swaps Derivative financial instruments—Current Assets $ — $ Gas Swaps Derivative financial instruments—Current Assets — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total derivative fair value at period end $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) The fair values of commodity derivative instruments reported in the Company's consolidated balance sheets are subject to netting arrangements and qualify for net presentation. As of December 31, 2015, the Company did not have any open commodity derivative contract positions. The following table summarizes the location and fair value amounts of all derivative instruments in the consolidated balance sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheet at December 31, 2014 (in thousands): December 31, 2014 Not Designated as ASC 815 Hedges: Balance Sheet Classification Gross Recognized Assets/ Liabilities Gross Amounts Offset Net Recognized Fair Value Assets/ Liabilities Derivative assets: Commodity contracts Derivative financial instruments—current $ $ — $ Commodity contracts Derivative financial instruments—noncurrent — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Derivative liabilities: Commodity contracts Derivative financial instruments—current $ — $ — $ — Commodity contracts Derivative financial instruments—noncurrent — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ — $ — $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gains/Losses on Commodity Derivative Contracts The Company does not designate its commodity derivative contracts as hedging instruments for financial reporting purposes. Accordingly, commodity derivative contracts are marked-to-market each quarter with the change in fair value during the periodic reporting period recognized currently as a gain or loss in "Gains (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: For the Years Ended 2015 2014 2013 (in thousands) Net cash received (paid) for commodity derivative contracts $ $ ) $ ) Unrealized net gains (losses) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gains (losses) 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, 2015
Property and Equipment
Property and Equipment	6. Property and Equipment The Company's property and equipment as of December 31, 2015 and 2014 was as follows: December 31, 2015 December 31, 2014 (in thousands) Oil and gas properties, on the basis of full-cost accounting: Proved properties $ $ Unevaluated properties — Other property and equipment Less accumulated depreciation, depletion, amortization and impairment ) ) ​ ​ ​ ​ ​ ​ ​ ​ Net property and equipment $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the years ended December 31, 2015, 2014 and 2013, depletion expense related to oil and gas properties was $195.2 million, $266.8 million, and $248.2 million, respectively and $16.26, $22.75 and $28.42 per barrel of oil equivalent ("Boe"), respectively. For the years ended December 31, 2015, 2014 and 2013, depreciation expense related to other property and equipment was $3.5 million, $3.1 million and $2.2 million, respectively. For the years ended December 31, 2015, 2014 and 2013, interest capitalized to unevaluated properties was $4.9 million, $12.4 million and $32.2 million, respectively. For the years ended December 31, 2015, 2014 and 2013, the Company capitalized $7.3 million, $12.4 million and $8.4 million, respectively, of internal costs to oil and gas properties, including $1.3 million, $2.2 million and $1.4 million, respectively, of qualifying share based compensation expense, see "—Note 11. Equity and Share Based Compensation".

Acquisition and Divestitures of

Acquisition and Divestitures of Oil and Gas Properties	12 Months Ended
	Dec. 31, 2015
Acquisition and Divestitures of Oil and Gas Properties
Acquisition and Divestitures of Oil and Gas Properties	7. 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 March 5, 2014, the Company executed an agreement 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 a purchase price of $170.0 million in cash, subject to 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. On May 1, 2014, the Company closed on the sale for net proceeds of $147.7 million, of which $131.0 million was used to reduce amounts outstanding under its Credit Facility, with the remainder retained for transaction expenses and working capital purposes. The Company reduced the full cost pool subject to amortization by the amount of the net proceeds received and 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 requested the unutilized portion of the non-interest bearing amount of approximately $4.4 million be refunded. The refund was received in February 2016 and has been included in "accounts receivable—other" on the Company's consolidated balance sheet as of December 31, 2015. Anadarko Basin Acquisition On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas and Oklahoma from Panther Energy Company, LLC and its partners for approximately $618.0 million in cash (before customary post-closing adjustments). The Company funded the purchase price of the Anadarko Basin Acquisition with a portion of the net proceeds from the private placement of the 2021 Senior Notes, which also closed on May 31, 2013. The transaction was accounted for using the acquisition method of accounting which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The fair value of, and the allocation to, the assets acquired and liabilities assumed in the Anadarko Basin Acquisition has been finalized and is shown in the following table (in thousands): Anadarko Basin Acquisition Oil and gas properties Proved $ Unevaluated ​ ​ ​ ​ ​ Total assets acquired $ Asset retirement obligations ​ ​ ​ ​ ​ Total liabilities assumed $ ​ ​ ​ ​ ​ Net assets acquired $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The finalized balances in the table above include immaterial changes to the amounts originally allocated to oil and gas properties. These changes were required to reflect the final consideration paid after adjustment for certain post-closing purchase price amounts. Actual and Pro Forma Impact of Acquisition—unaudited Revenues attributable to the Anadarko Basin Acquisition included in the Company's consolidated statements of operations for the year ended December 31, 2014 and 2013 were $178.9 million and $104.7 million, respectively. The following table presents unaudited pro forma information for the Company as if the Anadarko Basin Acquisition had been completed on January 1, 2013 (in thousands, other than per share amounts): For the Year Ended December 31, 2013 Revenues and other $ Net loss ) Preferred stock dividends ) Loss attributable to common shareholders $ ) Net loss per common share—basic and diluted $ ) The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Anadarko Basin Acquisition and are factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Company's consolidated results of operations actually would have been had the Anadarko Basin Acquisition been completed on January 1, 2013. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations for the combined Company. 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. For the year ended December 31, 2013, acquisition and transaction costs of $11.8 million were incurred as a result of the Anadarko Basin Acquisition and include advisory, legal, accounting, valuation and other professional and consulting fees related to the acquisition.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligations
Asset Retirement Obligations	8. 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 $18.7 million and $21.6 million as of December 31, 2015 and 2014, respectively. The liability has been accreted to its present value as of December 31, 2015 and 2014. At December 31, 2015 and 2014, 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 years ended December 31, 2015, 2014 and 2013, respectively (in thousands): Year ended December 31, 2015 2014 2013 Asset retirement obligations at beginning of year $ $ $ Liabilities incurred Liabilities assumed in Anadarko Basin Acquisition — — 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 years ended December 31, 2014 and 2013 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 areas. (2) Liabilities eliminated through asset sales for the year ended December 31, 2015 is primary 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 7. Acquisition and Divestitures of Oil and Gas Properties".

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Debt
Debt	9. Debt The Company's total debt, including debt classified as current, as of December 31, 2015 and 2014 is as follows: Principal Unamortized Deferred Gain on Debt Forgiven Unamortized Debt Issuance Costs Total 2015 2014 2015 2014 2015 2014 2015 2014 (in thousands) Credit Facility $ — $ $ — $ — $ — $ — $ — $ 2020 Senior Notes — — ) ) 2021 Senior Notes — — ) ) Second Lien Notes — — — — — Third Lien Notes — — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total debt $ $ $ $ — $ ) $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The Company is required to receive an unqualified auditors' opinion in relation to the 2015 consolidated financial statements. The failure to receive an unqualified opinion is an event of default under the Credit Facility that must be cured within 30 days of such event or waived by the lenders under the Credit Facility. As discussed above, the report of the Company's independent registered public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31, 2015 in this Annual Report on Form 10-K contains an explanatory paragraph regarding an event of default under the Credit Facility, a projected additional debt covenant violation, and resulting lack of liquidity, which raises substantial doubt about the Company's ability to continue as a going concern. The Company has not received a waiver from the lenders under its Credit Facility for the explanatory paragraph to its 2015 independent registered public accounting firm report. As a result, the Company is in default under its Credit Facility and all of its debt is classified as current in the accompanying consolidated balance sheet as of December 31, 2015. A failure to cure this default within 30 days may result in the acceleration of all of the Company's indebtedness under the Credit Facility and, due to cross default and cross acceleration provisions, its other outstanding debt obligations. 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 Credit Facility 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. Additionally, the Company and Midstates Sub entered into the Seventh Amendment to the Credit Facility (the "Seventh Amendment') which provided that upon completion of the offering of the Second Lien Notes and exchange of Third Lien Notes, the borrowing base of the Credit Facility would be reduced to $252.0 million. The Seventh Amendment also provided additional covenant flexibility. Further discussion regarding the Second Lien Notes, Third Lien Notes and Seventh Amendment can be found below. 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 will 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. As a result, the Company's reported interest expense will be significantly less than the contractual interest payments throughout the term of the Second Lien Notes and Third Lien Notes. 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. The table below summarizes the changes in total debt, including debt classified as current, during the year as a result of the debt restructuring, not considering unamortized debt issuance costs related to the 2020 Senior Notes and the 2021 Senior Notes: December 31, 2014 Carrying Value Borrowings/ (Repayments) Exchanges Deferred Gain on Forgiven Debt Amortization of Forgiven Debt Paid-in Kind Interest December 31, 2015 Carrying Value (excluding unamortized debt issuance costs) Credit Facility $ $ ) $ — $ — $ — $ — $ — 2020 Senior Notes — ) ) — — 2021 Senior Notes — ) ) — — Second Lien Notes — — ) — Third Lien Notes — — ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total debt $ $ $ — $ — $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2015 Carrying Value Unamortized Deferred Gain on Debt Forgiven December 31, 2015 Principle Balance Outstanding Credit Facility $ — $ — $ — 2020 Senior Notes — 2021 Senior Notes — Second Lien Notes ) Third Lien Notes ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total debt $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Reserve-based Credit Facility The Company maintains a $750.0 million Credit Facility with a current borrowing base of $252.0. At December 31, 2015, the Company had no amounts drawn on the Credit Facility and had outstanding letters of credit obligations totaling $2.8 million. In February 2016, the Company borrowed approximately $249.2 million under the Credit Facility, which represented the remaining undrawn availability under the Credit Facility. The Credit Facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of the Company's oil and natural gas properties and bear 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 Credit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of either 0.375% or 0.500% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter. The borrowing base under the Credit Facility is subject to semiannual redeterminations in April and October and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by the Company or the administrative agent acting on behalf of lenders holding at least two-thirds of the outstanding loans and other obligations. On October 14, 2015, the Company and Midstates Sub entered into the Ninth Amendment, which, among other items, reaffirmed the borrowing base at $252.0 million. The next borrowing base redetermination is scheduled for April 2016. Under the terms of the Credit Facility, the Company is required to repay any amount by which the principal balance of its outstanding loans and its letter of credit obligations exceeds its redetermined borrowing base or grant liens on additional property having sufficient value to eliminate such excess. The Company is permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent's notice regarding such borrowing base reduction. If commodity prices remain depressed or deteriorate further, the borrowing base under the Credit Facility will likely be reduced. Since the Credit Facility was fully drawn subsequent to December 31, 2015, any reduction in the borrowing base will result in a deficiency in the amount that the Company's borrowings exceed the borrowing base, which must be repaid within 30 days or in six equal monthly installments thereafter, at the Company's election. The Company may not have the financial resources to make any mandatory deficiency principal repayments, which could result in an event of default under the Credit Facility. On March 24, 2015, the Company and Midstates Sub entered into a Sixth Amendment (the "Sixth Amendment") to the Credit Facility. The Sixth Amendment amended the required ratio of net consolidated indebtedness to EBITDA under the Credit Agreement for each of the fiscal quarters in 2015 from 4.0:1.0 to 4.5:1.0. Additionally, the Sixth Amendment amended the mortgage requirements under the Credit Facility to provide for an increase from 80.0% to 90.0% in the percentage of properties included in the borrowing base that are required to be subject to mortgages for the benefit of the lenders. On May 21, 2015, the Company and Midstates Sub entered into a Seventh Amendment to the Credit Facility. The Seventh Amendment provided that, with the completion of the offering of the Second Lien Notes and exchange of the Third Lien Notes (both discussed below), the Company's borrowing base would be reduced to approximately $252.0 million. The Seventh Amendment also eliminated the required ratio of net consolidated indebtedness to EBITDA covenant and added a ratio of Total Senior Indebtedness (as defined therein) to EBITDA of not more than 1.0 to 1.0, which is further discussed below under "—Debt Covenants." On August 5, 2015, the Company and Midstates Sub entered into an Eighth Amendment (the "Eighth Amendment") to the Credit Facility. The Eighth Amendment increased the limitation on certain leases and lease agreements into which Midstates and Midstates Sub may enter into during any period of twelve consecutive calendar months of the life of such leases from $2.0 million to $3.5 million. On October 14, 2015, the Company and Midstates Sub entered into the Ninth Amendment to the Credit Facility (the "Ninth Amendment") which, among other items, reaffirmed the borrowing base at $252.0 million and provided flexibility for certain specified asset sales by confirming the amount of the borrowing base reduction if any such sale occurs. 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. The 2020 Senior Notes rank pari passu in right of payment with the 2021 Senior Notes, the Second Lien Notes and Third Lien Notes; however, the 2021 Senior Notes and 2020 Senior Notes are effectively junior to the extent of the value of the collateral securing the Company's Credit Facility, the Second Lien Notes and the Third Lien Notes. The 2020 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. The Company does not have any operations or independent assets other than its 100% ownership interest in Midstates Sub and there are no other subsidiaries of the Company. The indenture governing the 2020 Senior Notes (the "2020 Senior Notes Indenture") does not impose any significant restrictions on the ability of Midstates Sub to transfer assets to, pay dividends to, make investments in or make loans to the Company or limit the ability of the Company to transfer assets to, pay dividends to, make investments in or make loans to Midstates Sub. Upon the occurrence of certain change of control events, as defined in the 2020 Senior Notes Indenture, each holder of the 2020 Senior Notes will have the right to require that the Company repurchase all or a portion of such holder's 2020 Senior Notes in cash at a purchase price equal to 101.0% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase. As part of the debt restructuring, 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 estimated fair value of the 2020 Senior Notes as of December 31, 2015 was $35.2 million (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective interest rate was 11.2% and 11.1%, respectively, for the years ended December 31, 2015 and 2014. 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. The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes, Second Lien Notes and Third Lien Notes; however, the 2021 Senior Notes and 2020 Senior Notes are effectively junior to the extent of the value of the collateral securing the Company's secured indebtedness, including the Second Lien Notes and the Third Lien Notes. The 2021 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. The Company does not have any operations or independent assets other than its 100% ownership interest in Midstates Sub and there are no other subsidiaries of the Company. The indenture governing the 2021 Senior Notes (the "2021 Senior Notes Indenture") does not impose any significant restrictions on the ability of Midstates Sub to transfer assets to, pay dividends to, make investments in or make loans to the Company or limit the ability of the Company to transfer assets to, pay dividends to, make investments in or make loans to Midstates Sub. Upon the occurrence of certain change of control events, as defined in the 2021 Senior Notes Indenture, each holder of the 2021 Senior Notes will have the right to require that the Company repurchase all or a portion of such holder's 2021 Senior Notes in cash at a purchase price equal to 101.0% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase. As part of the debt restructuring, 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 estimated fair value as of December 31, 2015 of the 2021 Senior Notes was $41.7 million (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective interest rate was 9.6% for the years ended December 31, 2015 and 2014. 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 mature on the earlier of June 1, 2020 or 12 months after the maturity date of the Company's Credit Facility (including any extension or refinancing of such facility). The Second Lien Notes have an interest rate of 10.0% and interest is payable semi-annually on June 1 and December 1 of each fiscal year. The Second Lien Notes are unconditionally guaranteed, jointly and severally, on a senior secured basis by each of the Company's future restricted subsidiaries (the "Guarantors") and will be initially secured by second-priority liens on substantially all of the Company's and Guarantors' assets that secure the Company's Credit Facility. The indenture governing the Second Lien Notes (the "Second Lien Notes Indenture") does not impose any significant restrictions on the ability of Midstates Sub to transfer assets to, pay dividends to, make investments in or make loans to the Company or limit the ability of the Company to transfer assets to, pay dividends to, make investments in or make loans to Midstates Sub. The Second Lien Notes are senior secured obligations of the Company and rank effectively junior to its obligations under the Credit Facility, effectively senior to its existing and future unsecured indebtedness, effectively senior to the Company's Third Lien Notes and all future junior lien obligations, effectively junior to all existing and future secured indebtedness secured by assets not constituting collateral under the Second Lien Notes, pari passu with all of the Company's existing and future senior debt, structurally subordinated to all existing and future indebtedness of any non-Guarantor subsidiaries and senior to any existing or future subordinated debt. Upon the occurrence of certain change of control events, as defined in the indenture governing the Second Lien Notes, each holder of the Second Lien Notes will have the right to require that the Company repurchase all or a portion of such holder's 2020 Second Lien Notes in cash at a purchase price equal to 101.0% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase. The estimated fair value of the Second Lien Notes was $262.5 million as of December 31, 2015 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective interest rate was 10.5% for the year ended December 31, 2015. 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 are unconditionally guaranteed, jointly and severally, on a senior secured basis by each of the Guarantors. The Third Lien Notes are secured by third-priority liens on substantially all of the Company's assets that secure the Credit Facility. The Third Lien Notes have an interest rate of 12.0%, consisting of cash interest of 10.0% and paid-in-kind interest of 2.0%, per annum and mature on the earlier of June 1, 2020 or 12 months after the maturity date of the Company's Credit Facility (including any extension or refinancing of such facility). Cash interest is payable semi-annually on June 1 and December 1 of each fiscal year. Paid-in-kind interest, which is included in other long-term liabilities in our consolidated balance sheet, increases the outstanding principal balance of the Third Lien Notes on June 1 and December 1 of each fiscal year. The indenture governing the Third Lien Notes (the "Third Lien Notes Indenture") does not impose any significant restrictions on the ability of Midstates Sub to transfer assets to, pay dividends to, make investments in or make loans to the Company or limit the ability of the Company to transfer assets to, pay dividends to, make investments in or make loans to Midstates Sub. The Third Lien Notes are senior secured obligations of the Company and rank effectively junior to its obligations under the Credit Facility and Second Lien Notes to the extent of the value of the collateral securing such indebtedness, effectively senior to its existing and future unsecured indebtedness to the extent of the value of the collateral securing the Third Lien Notes, effectively senior to all future junior lien obligations that rank below a third-priority basis to the extent of the value of the collateral securing the Third Lien Notes, effectively junior to all existing and future secured indebtedness secured by assets not constituting collateral under the Third Lien Notes, pari passu to all of the Company's existing and future senior debt, structurally subordinated to all existing and future indebtedness of any non-Guarantor subsidiaries and senior in right of payment to any existing or future subordinated debt. Upon the occurrence of certain change of control events, as defined in the indenture governing the Third Lien Notes, each holder of the Third Lien Notes will have the right to require that the Company repurchase all or a portion of such holder's Third Lien Notes in cash at a purchase price equal to 101.0% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase. The estimated fair value of the Third Lien Notes was $94.3 million as of December 31, 2015 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective interest rate was 12.6% for the year ended December 31, 2015. Debt Covenants The Credit Facility, as amended, contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of Total Senior Indebtedness to EBITDA (as defined therein) of not more than 1.0 to 1.0 and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. The Credit Facility also limits the Company's ability to make any dividends, distributions or redemptions. The indentures governing the 2020 Senior Notes, 2021 Senior Notes, Second Lien Notes and Third Lien Notes contain covenants that, among other things, restrict the Company's ability to: (i) incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with the Company's affiliates; (vii) consolidate, merge or sell substantially all of the Company's assets; (viii) prepay, redeem or repurchase certain debt; (ix) alter the business the Company conducts; and (x) enter into agreements restricting the ability of the Company's current and any future subsidiaries to pay dividends.

Preferred Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2015
Preferred Stock.
Preferred Stock	10. 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. The Series A Preferred Shares were mandatorily convertible at September 30, 2015 into shares of the Company's common stock at a conversion price of $110.00 per share, which was automatically adjusted to reflect the reverse stock split. Based on the liquidation preference at September 30, 2015, each Series A Preferred Share converted into approximately 11.5 shares of the Company's common stock pursuant to the Certificate of Designation, which governed the Series A Preferred Stock. As a result, the Company issued 3,738,424 additional shares of common stock upon conversion of the Series A Preferred Stock. For the year ended December 31, 2014, the $10.4 million Series A Preferred Stock dividend was based upon the estimated fair value of 265,979 common shares that would have been issued had the notional dividend amounts for the year of $29.3 million been converted into common shares at a conversion price of $110.00 per share For the year ended December 31, 2013, the $15.6 million Series A Preferred Stock dividend was based upon the estimated fair value of 245,912 common shares that would have been issued had the notional dividend amounts for the year of $27.1 million been converted into common shares at a conversion price of $110.00 per share. Share Activity The following table summarizes changes in the number of Series A Preferred Stock shares since January 1, 2012: Series A Preferred Stock Share count as of January 1, 2012 — Issuance of preferred stock as consideration in Eagle Property Acquisition ​ ​ ​ ​ ​ Share count as of December 31, 2012 Share count as of December 31, 2013 Share count as of December 31, 2014 Conversion of preferred stock into common stock ) ​ ​ ​ ​ ​ Share count as of December 31, 2015 — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Equity and Share-Based Compensa

Equity and Share-Based Compensation	12 Months Ended
	Dec. 31, 2015
Equity and Share-Based Compensation
Equity and Share-Based Compensation	11. Equity and Share-Based Compensation Common Shares At December 31, 2015, the Company had 10,962,105 and 10,865,814 shares of its common stock issued and outstanding, respectively. On April 25, 2012, the Company completed its initial public offering of common stock pursuant to a registration statement on Form S-1 (File 333-177966), as amended and declared effective by the SEC on April 19, 2012. Pursuant to the registration statement, the Company registered the offer and sale of 2,760,000 shares of $0.01 par value common stock, which included 600,000 shares of stock sold by the selling shareholders and 360,000 shares of common stock sold by the selling stockholders pursuant to an option granted to the underwriters to cover over-allotments. 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. The Company is also authorized to issue up to a total of 50,000,000 shares of its preferred stock with a par value of $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. With respect to preferred shares, the Company is authorized, without further stockholder approval, to establish and issue from time to time one or more classes or series of preferred stock with such powers, preferences, rights, qualifications, limitations and restrictions as determined by its board of directors. See discussion of Series A Preferred Shares in "—Note 10. Preferred Stock". Share Activity The following table summarizes changes in the number of shares of common stock and treasury stock outstanding since January 1, 2013: Common Stock Treasury Stock(1) Share count as of January 1, 2013 — Grants of restricted stock — Forfeitures of restricted stock ) — Acquisition of treasury stock — ) ​ ​ ​ ​ ​ ​ ​ ​ Share count as of December 31, 2013 ) Grants of restricted stock — Forfeitures of restricted stock ) — Acquisition of treasury stock — ) ​ ​ ​ ​ ​ ​ ​ ​ Share count as of December 31, 2014 ) 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 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Treasury stock represents the net settlement on vesting of restricted stock necessary to satisify the minimum statutory withholding requirements. Incentive Units. In connection with the corporate reorganization that occurred immediately prior to our initial public offering, incentive units held in the Company were contributed to FR Midstates Interholding, LP ("FRMI") in exchange for incentive units in FRMI. Holders of FRMI incentive units will receive, out of proceeds otherwise distributable to FRMI, a percentage interest in the amounts distributed to FRMI in excess of certain multiples of FRMI's aggregate capital contributions and investment expenses ("FRMI Profits"). Although any future payments to the incentive unit holders will be made out of the proceeds otherwise distributable to FRMI and not by the Company, the Company will be required to record a non-cash compensation charge in the period any payment is made related to the FRMI incentive units. To date, no compensation expense related to the incentive units has been recognized by the Company, as any payout under the incentive units is not considered probable, and thus, the amount of FRMI Profits, if any, cannot be determined. Share-based Compensation 2012 Long Term Incentive Plan. On April 20, 2012, the Company established the 2012 Long Term Incentive Plan (the "2012 LTIP") and filed a Form S-8 with the SEC, registering 656,343 shares of common stock for future issuance under the terms of the 2012 LTIP. On May 27, 2014, the Company filed a Form S-8 with the SEC, increasing the number of shares available for future issuance under the terms of the 2012 LTIP to 863,843 shares of common stock. The 2012 LTIP provides a means for the Company to attract and retain employees, directors and consultants, and a method whereby employees, directors and consultants of the Company who contribute to its success can acquire and maintain stock ownership or awards, the value of which is tied to the performance of the Company. The 2012 LTIP provides 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 (the "Awards"). Subject to certain limitations as defined in the 2012 LTIP, the terms of each Award are as determined by the Compensation Committee of the Board of Directors. As of December 31, 2015, a total of 863,843 common share Awards are authorized for issuance under the 2012 LTIP and shares of stock subject to an Award that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future Awards under the 2012 LTIP. Non-vested Stock Awards. At December 31, 2015 the Company had 318,031 shares of restricted common stock outstanding pursuant to the 2012 LTIP. Shares granted under the LTIP generally vest ratably over a period of three years (one-third on each anniversary of the grant), however, beginning in 2013, shares granted under the 2012 LTIP to directors are subject to one-year cliff vesting. The fair value of restricted stock grants is based on the value of the Company's common stock on the date of grant. Compensation expense is recognized ratably over the requisite three year service period. The following table summarizes the Company's non-vested share award activity for the years ended December 31, 2015, 2014 and 2013: Shares Weighted Average Grant Date Fair Value Non-vested shares outstanding at December 31, 2012 $ Granted $ Vested ) $ Forfeited ) $ ​ ​ ​ ​ ​ ​ ​ ​ Non-vested shares outstanding at December 31, 2013 $ Granted $ Vested ) $ Forfeited ) $ ​ ​ ​ ​ ​ ​ ​ ​ Non-vested shares outstanding at December 31, 2014 $ Granted $ Vested ) $ Forfeited ) $ ​ ​ ​ ​ ​ ​ ​ ​ Non-vested shares outstanding at December 31, 2015 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Unrecognized expense as of December 31, 2015 for all outstanding restricted stock awards, adjusted for estimated forfeitures, was $3.8 million and will be recognized over a weighted average period of 1.53 years. At December 31, 2015, 203,589 shares remain available for issuance under the terms of the 2012 LTIP. The share-based compensation costs (net of amounts capitalized to oil and gas properties) recognized as general and administrative expense by the Company for the years ended December 31, 2015, 2014, and 2013 of $4.4 million, $8.6 million, and $5.7 million, respectively, all related to the 2012 LTIP. During the quarter 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 the twelve months ended December 31, 2015, approximately $1.5 million was related to the accelerated vesting for employees impacted by the corporate relocation. For the twelve months ended December 31, 2014, approximately $2.9 million of the $8.6 million in share-based compensation was related to the accelerated vesting. For the years ended December 31, 2015 and 2014, the Company capitalized $1.3 million and $2.2 million, respectively, of qualifying share-based compensation costs to oil and gas properties.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Taxes
Income Taxes	12. Income Taxes The Company incurred a tax net operating loss ("NOL") in the current year. There is no tax refund available to the Company, nor is there any current income tax payable. In light of the impairment of oil and gas properties recorded in the current year, management recorded a $689.4 million valuation allowance against the Company's federal and state NOLs this year. Management believes that the balance of the Company's NOLs are realizable only to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. No other sources of future taxable income are considered in this judgment. The Company reported unrealized losses from hedging activities in the amount of $126.7 million and impairments of oil and gas properties in the amount of $1.6 billion, which resulted in pre-tax book loss of $1.8 billion for the year ended December 31, 2015. The Company's NOLs were incurred in the tax years 2012 through 2015, and U.S. federal and State of Oklahoma NOLs will generally be available for use through the tax years 2033 and 2035, respectively, and its State of Louisiana NOLs are generally available through 2028 and 2030, respectively. The State of Texas currently has no NOL carryover provision. Section 382 of the Internal Revenue Code of 1986, as amended, relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three year look back period. The Company believes there has not been such a change as of December 31, 2015. As of December 31, 2015, 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. For the Years Ended December 31, 2015 2014 2013 (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: Years Ended December, 31 2015 2014 2013 (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 ) ) ) 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: Years Ended December 31, 2015 2014 (in thousands) 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 — 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, 2015
Earnings (Loss) Per Share
Earning (Loss) Per Share	13. Earnings (Loss) Per Share The Company's Series A Preferred Stock issued in connection with the Eagle Property Acquisition, which converted into common stock on September 30, 2015, had the nonforfeitable right to participate on an as converted basis at the conversion rate then in effect in any common stock dividends declared and as such, was considered a participating security. The Company's nonvested stock awards, which are granted as part of the 2012 LTIP, contain nonforfeitable rights to dividends and as such, are considered to be participating securities and, together with the Series A Preferred Stock, are included in the computation of basic and diluted earnings (loss) per share, pursuant to the two-class method. In the calculation of basic earnings (loss) per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company's participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. The computation of diluted earnings (loss) per share attributable to common shareholders reflects the potential dilution that could occur if securities or other contracts to issue common shares that are dilutive were exercised or converted into common shares (or resulted in the issuance of common shares) and would then share in the earnings of the Company. During the periods in which the Company records a loss from continuing operations attributable to common shareholders, securities would not be dilutive to net loss per share and conversion into common shares is assumed to not occur. Diluted net income per share attributable to common shareholders is calculated under both the two-class method and the treasury stock method; the more dilutive of the two calculations is presented below. 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: Years Ended December 31, 2015 2014 2013 (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 10. 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, 2015
Concentrations of Credit Risk
Concentrations of Credit Risk	14. 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 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. For the year ended December 31, 2013, five purchasers accounted for 28%, 16%, 13%, 12% and 11% 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, 2015, three purchasers accounted for approximately 33%, 29%, and 14%, respectively, of the accounts receivable balance. At December 31, 2014, four purchasers accounted for approximately 25%, 23%, 15% and 13% 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 has no derivative instruments in place at December 31, 2015.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies
Commitments and Contingencies	15. Commitments and Contingencies Contractual Obligations At December 31, 2015, contractual obligations for drilling contracts, long-term operating leases, seismic contracts and other contracts are as follows (in thousands): Total 2016 2017 2018 2019 2020 and beyond Drilling contracts $ $ $ — $ — $ — $ — Non-cancellable office lease commitments(1) Seismic contracts — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net minimum commitments $ $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) During 2014, the Company announced plans to relocate the headquarters from Houston, Texas to Tulsa, Oklahoma. However, at December 31, 2015, the Company still leased space in Houston (with a contractual obligation through 2018) and of the $7.5 million total in office lease commitments, approximately $2.5 million relates to the Houston leases. For the years ended December 31, 2015, 2014, and 2013, the Company expensed $2.3 million, $2.3 million, and $1.7 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 (as amended and effective June 1, 2013) in the Mississippian Lime region, which includes certain minimum natural gas and 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 of roughly $0.08 to $0.125 per gallon (subject to annual escalation). 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 8. Asset Retirement Obligations" for discussion of those commitments. 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, 2015 and 2014, the Company's total accrual for all loss contingencies was $1.0 million and $0.2 million, respectively.

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
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 Securities and Exchange Commission ("SEC") and have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP"). All intercompany transactions have been eliminated in consolidation. 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 consolidated financial statements for the year ended December 31, 2013 include the results from the Anadarko Basin Acquisition beginning May 31, 2013. 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.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with 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 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 commodity derivative contracts, the fair value of share-based compensation, 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, 2015 and 2014 that exceeded the balance insured by the FDIC in the amount of $87.2 million and $34.3 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, 2015 and 2014, 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 4. Fair Value Measurements of Financial Instruments". The fair value of the Company's long-term debt is disclosed, see "—Note 9. 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 are recorded 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 earnings 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, 2015 and 2014, other noncurrent assets consisted of the following: At December 31, 2015 2014 (As Adjusted, Note 3) (in thousands) Deferred financing costs associated with the Credit Facility $ $ Field equipment inventory Other ​ ​ ​ ​ ​ ​ ​ ​ Other noncurrent assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the years ended December 31, 2015 and 2014, the Company recorded $2.0 million and $4.1 million, respectively, 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. 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. During 2014, the Company transferred $59.2 million of Mississippian unevaluated property costs to the full cost pool. These costs were attributable to leases that either expired during 2014, were determined to not be prospective, or that were assigned proved reserves as a result of the Company's development drilling activities. The Company also transferred $128.2 million of Anadarko Basin and $16.5 million of Gulf Coast unevaluated property costs based upon our lack of plans for further evaluation or development of those leases in the current commodity price environment. 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 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 years ended December 31, 2015, 2014 and 2013, the Company recorded impairments of oil and gas properties of $1.6 billion, $86.5 million and $453.3 million respectively. A significant 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 year ended December 31, 2015. For the years ended December 31, 2014 and 2013, the primary factors affecting the impairment related to the transfer of unevaluated property costs to the full cost pool and negative reserve revisions in certain areas. 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 from external borrowings is capitalized on unevaluated properties using the weighted-average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at the date of first production from the field. 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, 2015 and 2014, accrued liabilities consisted of the following: At December 31, 2015 2014 (in thousands) 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 8. 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. 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. See "—Note 11. 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, 2015, 2014 or 2013.
Acquisition and Transaction Costs	Acquisition and Transaction Costs Acquisition and transaction related costs are expensed as incurred and as services are received. Such costs include finders' fees, advisory, legal, accounting, valuation and other professional and consulting fees, and acquisition related general and administrative costs. Costs incurred in 2015 relate to the Dequincy Divestiture and costs incurred in 2014 relate to the Pine Prairie Disposition. Costs incurred in 2013 relate to the Anadarko Basis Acquisition. See "—Note 7. 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 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 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 and outstanding stock options (if any) using the treasury method, as well as the Company's Series A Preferred Stock using the if-converted method (in periods prior to the Preferred Stock's mandatory conversion date). In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that such excess tax benefits are more likely than not to be realized. 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 13. 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 (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance obligation. ASU 2014-09 will be effective for the Company beginning on January 1, 2018, including interim periods within that reporting period, considering the one year deferral provided by ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date." The standard permits the use of either the retrospective or cumulative effect transition method and early adoption is permitted. The Company has not selected a transition method and is evaluating the impact this standard will have on its consolidated financial statements and related disclosures. In April 2015, the FASB issued Accounting Standards Update 2015-03, "Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03") and in August 2015 issued Accounting Standards Update 2015-15, "Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements—Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update)" ("ASU 2015-15"). The ASUs provide that the debt issuance costs are similar to debt discounts and in effect reduce the proceeds of borrowings. ASU 2015-03 amends the FASB ASC to require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the related liability. Prior to the amendment, debt issuance costs were reported in the balance sheet as an asset. ASU 2015-15 further clarified that given ASU 2015-03's silence on debt issuance costs related to revolving credit facilities, the SEC would not object to debt issuance costs for revolving credit facilities being deferred and presented as an asset. The amended guidance is effective for financial statements issued for fiscal years beginning after December 15, 2015; however the Company elected to early adopt effective December 31, 2015. The election requires retrospective application and represents a change in accounting principle. As a result of the adoption, the December 31, 2014 consolidated balance sheet has been adjusted as follows: December 31, 2014 Previously Reported Effect of Accounting Principle Adoption As Adjusted (in thousands) Assets: Other noncurrent assets $ $ ) $ Total other assets ) Total assets ) Liabilities: Long-term debt less unamortized debt issuance costs $ $ ) $ Total long-term liabilities ) Total liabilities and shareholders' equity ) Debt costs associated with the Company's revolving credit facility, under which no borrowings were outstanding at December 31, 2015, remain classified as an asset in accordance with the Company's accounting policy that debt costs related to revolving credit arrangements are deferred and amortized over the term of the arrangement. In September 2015, the FASB issued Accounting Standards Update 2015-16, "Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments" ("ASU 2015-16"). ASU 2015-16 simplifies measurement period adjustments associated with business combinations accounted for under FASB ASC 805, Business Combinations . ASU 2015-16 changes the accounting for measurement period adjustments by eliminating the requirement that such adjustments are made retrospectively. As a result, such measurement period adjustments will be recognized in the reporting period in which the adjustment was determined. ASU 2015-16 is applied prospectively to adjustments to provisional amounts that occur after the effective date. ASU 2015-16 is effective for the Company beginning on January 1, 2016. The Company does not believe the adoption of ASU 2015-16 will have a material impact on its financial position, results of operations or cash flows. In November 2015, the FASB issued Accounting Standards Update 2015-17, "Balance Sheet Classification of Deferred Taxes," ("ASU 2015-17") which requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent in the balance sheet. As a result, the Company now only presents its deferred income taxes on a net noncurrent basis. However, the new guidance does not change the existing requirement that only permits offsetting within a jurisdiction. Companies are still prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. The amendments in this accounting standard are effective for public companies for interim and annual reporting periods beginning after December 15, 2016, with early application permitted. The Company has early adopted this standard and has applied the change in accounting as of December 31, 2015 on a prospective basis. Adoption of this amendment did not have an effect on the Company's financial position or results of operations, and prior periods were not retrospectively adjusted. 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. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new standard is effective for 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 currently evaluating the impact this standard will have on its consolidated financial statements and related disclosures.

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Summary of Significant Accounting Policies
Schedule of other noncurrent assets	At December 31, 2015 2014 (As Adjusted, Note 3) (in thousands) Deferred financing costs associated with the Credit Facility $ $ Field equipment inventory Other ​ ​ ​ ​ ​ ​ ​ ​ Other noncurrent assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of accrued liabilities	At December 31, 2015 2014 (in thousands) 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 $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of restated consolidated balance sheet	December 31, 2014 Previously Reported Effect of Accounting Principle Adoption As Adjusted (in thousands) Assets: Other noncurrent assets $ $ ) $ Total other assets ) Total assets ) Liabilities: Long-term debt less unamortized debt issuance costs $ $ ) $ Total long-term liabilities ) Total liabilities and shareholders' equity )

Fair Value Measurements of Fi25

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Measurements of Financial Instruments
Schedule of commodity derivative contracts in the condensed consolidated balance sheets are recorded at estimated fair value	Fair Value Measurements at December 31, 2014 Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total (in thousands) Assets: Commodity derivative oil swaps $ — $ $ — $ Commodity derivative gas swaps — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total assets $ — $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total liabilities $ — $ — $ — $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Risk Management and Derivativ26

Risk Management and Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Risk Management and Derivative Instruments
Summary of location and fair values amounts of all derivative instruments as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited condensed consolidated balance sheet	The following table summarizes the gross fair value of derivative instruments by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company's consolidated balance sheets at December 31, 2015 and 2014, respectively (in thousands): Type Balance Sheet Location(1) December 31, 2015 December 31, 2014 Oil Swaps Derivative financial instruments—Current Assets $ — $ Gas Swaps Derivative financial instruments—Current Assets — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total derivative fair value at period end $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) The fair values of commodity derivative instruments reported in the Company's consolidated balance sheets are subject to netting arrangements and qualify for net presentation. As of December 31, 2015, the Company did not have any open commodity derivative contract positions. The following table summarizes the location and fair value amounts of all derivative instruments in the consolidated balance sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheet at December 31, 2014 (in thousands): December 31, 2014 Not Designated as ASC 815 Hedges: Balance Sheet Classification Gross Recognized Assets/ Liabilities Gross Amounts Offset Net Recognized Fair Value Assets/ Liabilities Derivative assets: Commodity contracts Derivative financial instruments—current $ $ — $ Commodity contracts Derivative financial instruments—noncurrent — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ $ — $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Derivative liabilities: Commodity contracts Derivative financial instruments—current $ — $ — $ — Commodity contracts Derivative financial instruments—noncurrent — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ — $ — $ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of "Gains (losses) on commodity derivative contracts - net" for the periods	For the Years Ended 2015 2014 2013 (in thousands) Net cash received (paid) for commodity derivative contracts $ $ ) $ ) Unrealized net gains (losses) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gains (losses) on commodity derivative contracts—net $ $ $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property and Equipment
Schedule of property and equipment	December 31, 2015 December 31, 2014 (in thousands) Oil and gas properties, on the basis of full-cost accounting: Proved properties $ $ Unevaluated properties — Other property and equipment Less accumulated depreciation, depletion, amortization and impairment ) ) ​ ​ ​ ​ ​ ​ ​ ​ Net property and equipment $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Acquisition and Divestitures 28

Acquisition and Divestitures of Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2015
Acquisition of Oil and Gas Properties
Schedule of unaudited pro forma information as of the acquisition date	The following table presents unaudited pro forma information for the Company as if the Anadarko Basin Acquisition had been completed on January 1, 2013 (in thousands, other than per share amounts): For the Year Ended December 31, 2013 Revenues and other $ Net loss ) Preferred stock dividends ) Loss attributable to common shareholders $ ) Net loss per common share—basic and diluted $ )
Anadarko Basin Acquisition
Acquisition of Oil and Gas Properties
Schedule of fair value of the assets acquired and liabilities assumed in acquisition	The fair value of, and the allocation to, the assets acquired and liabilities assumed in the Anadarko Basin Acquisition has been finalized and is shown in the following table (in thousands): Anadarko Basin Acquisition Oil and gas properties Proved $ Unevaluated ​ ​ ​ ​ ​ Total assets acquired $ Asset retirement obligations ​ ​ ​ ​ ​ Total liabilities assumed $ ​ ​ ​ ​ ​ Net assets acquired $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligations
Schedule of changes in the Company's ARO's	The following table details the change in the asset retirement obligations for the years ended December 31, 2015, 2014 and 2013, respectively (in thousands): Year ended December 31, 2015 2014 2013 Asset retirement obligations at beginning of year $ $ $ Liabilities incurred Liabilities assumed in Anadarko Basin Acquisition — — 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 years ended December 31, 2014 and 2013 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 areas. (2) Liabilities eliminated through asset sales for the year ended December 31, 2015 is primary 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 7. Acquisition and Divestitures of Oil and Gas Properties".

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt
Schedule of the company's total debt	Principal Unamortized Deferred Gain on Debt Forgiven Unamortized Debt Issuance Costs Total 2015 2014 2015 2014 2015 2014 2015 2014 (in thousands) Credit Facility $ — $ $ — $ — $ — $ — $ — $ 2020 Senior Notes — — ) ) 2021 Senior Notes — — ) ) Second Lien Notes — — — — — Third Lien Notes — — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total debt $ $ $ $ — $ ) $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of the company's long-term debt	December 31, 2014 Carrying Value Borrowings/ (Repayments) Exchanges Deferred Gain on Forgiven Debt Amortization of Forgiven Debt Paid-in Kind Interest December 31, 2015 Carrying Value (excluding unamortized debt issuance costs) Credit Facility $ $ $ — $ — $ — $ — $ — 2020 Senior Notes — — — 2021 Senior Notes — — — Second Lien Notes — — — Third Lien Notes — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total debt $ $ $ — $ — $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2015 Carrying Value Unamortized Deferred Gain on Debt Forgiven December 31, 2015 Principle Balance Outstanding Credit Facility $ — $ — $ — 2020 Senior Notes — 2021 Senior Notes — Second Lien Notes ) Third Lien Notes ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total debt $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Preferred Stock (Tables)

Preferred Stock (Tables)	12 Months Ended
	Dec. 31, 2015
Preferred Stock.
Summary of changes in the number of outstanding shares	Series A Preferred Stock Share count as of January 1, 2012 — Issuance of preferred stock as consideration in Eagle Property Acquisition ​ ​ ​ ​ ​ Share count as of December 31, 2012 Share count as of December 31, 2013 Share count as of December 31, 2014 Conversion of preferred stock into common stock ) ​ ​ ​ ​ ​ Share count as of December 31, 2015 — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Equity and Share-Based Compen32

Equity and Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Equity and Share-Based Compensation
Summary of changes in the number of outstanding shares	Common Stock Treasury Stock(1) Share count as of January 1, 2013 — Grants of restricted stock — Forfeitures of restricted stock ) — Acquisition of treasury stock — ) ​ ​ ​ ​ ​ ​ ​ ​ Share count as of December 31, 2013 ) Grants of restricted stock — Forfeitures of restricted stock ) — Acquisition of treasury stock — ) ​ ​ ​ ​ ​ ​ ​ ​ Share count as of December 31, 2014 ) 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 ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Treasury stock represents the net settlement on vesting of restricted stock necessary to satisify the minimum statutory withholding requirements.
Summary of Company's non-vested share award activity	Shares Weighted Average Grant Date Fair Value Non-vested shares outstanding at December 31, 2012 $ Granted $ Vested ) $ Forfeited ) $ ​ ​ ​ ​ ​ ​ ​ ​ Non-vested shares outstanding at December 31, 2013 $ Granted $ Vested ) $ Forfeited ) $ ​ ​ ​ ​ ​ ​ ​ ​ Non-vested shares outstanding at December 31, 2014 $ Granted $ Vested ) $ Forfeited ) $ ​ ​ ​ ​ ​ ​ ​ ​ Non-vested shares outstanding at December 31, 2015 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Taxes
Schedule of income tax provision (benefit)	For the Years Ended December 31, 2015 2014 2013 (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	Years Ended December, 31 2015 2014 2013 (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 ) ) ) Other, net ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total income tax provision (benefit) $ ) $ $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of components of the entity's deferred taxes	Years Ended December 31, 2015 2014 (in thousands) 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 — 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, 2015
Earnings (Loss) Per Share
Schedule of reconciliation of net income (loss) to preferred shareholders, common shareholders, and participating securities for purposes of computing net income (loss) per share:	Years Ended December 31, 2015 2014 2013 (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 10. 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, 2015
Commitments and Contingencies
Schedule of contractual obligations for drilling contracts, long-term operating leases and seismic contracts	At December 31, 2015, contractual obligations for drilling contracts, long-term operating leases, seismic contracts and other contracts are as follows (in thousands): Total 2016 2017 2018 2019 2020 and beyond Drilling contracts $ $ $ — $ — $ — $ — Non-cancellable office lease commitments(1) Seismic contracts — — — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net minimum commitments $ $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) During 2014, the Company announced plans to relocate the headquarters from Houston, Texas to Tulsa, Oklahoma. However, at December 31, 2015, the Company still leased space in Houston (with a contractual obligation through 2018) and of the $7.5 million total in office lease commitments, approximately $2.5 million relates to the Houston leases.

Organization and Business (Deta

Organization and Business (Details) $ / shares in Units, $ in Millions	Apr. 21, 2015USD ($)a	May. 31, 2013USD ($)	Oct. 01, 2012USD ($)$ / sharesshares	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	11,757
Eagle Property Acquisition
Acquisition information
Purchase price, cash			$ 325
Eagle Property Acquisition | Series A Preferred Stock
Acquisition information
Purchase price, preferred shares | shares			325,000
Preferred stock, liquidation value (in dollars per share) | $ / shares			$ 1,000
Anadarko Basin Acquisition | 2021 Senior Notes | Panther Energy LLC
Acquisition information
Purchase price, cash		$ 618

Liquidity and Ability to Cont37

Liquidity and Ability to Continue as a Going Concern (Details) $ in Thousands	Jun. 02, 2015USD ($)	Jun. 02, 2015USD ($)	May. 21, 2015USD ($)	Feb. 29, 2016USD ($)	Dec. 31, 2015USD ($)item	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Feb. 09, 2016USD ($)	Apr. 21, 2015USD ($)	May. 31, 2013USD ($)	Dec. 31, 2012USD ($)	Oct. 01, 2012USD ($)
Net cash received for commodity derivative contracts					$ (167,669)	$ 18,332	$ 17,585
Operating cash flow (as a percent)					78.60%
Aggregate principal amount borrowed					$ 1,795,930	1,735,150
Repayment of outstanding facility balance					468,150	131,000	34,300
Available cash					81,093	11,557	33,163	$ 335,700			$ 18,878
Proceeds from revolving credit facility					33,000	165,000	$ 341,450
Contractual obligations during the next twelve months					188,000
Interest payments on the senior notes due on April 1, 2016					$ 15,800
Maximum period available to pay default payment					30 days
Liquidity Sufficiency
Periodic interest payment amount on due dates of long-term debt					$ 179,500
Cross Default Provisions
Minimum effective borrowing base under credit facility					5.00%
Minimum indebtedness of senior notes including principal amount					$ 50,000
Minimum
Financial Ratio Covenants
Current Ratio					1
Maximum
Financial Ratio Covenants
Total Senior Indebtedness (as defined) to EBITDA					1
Dequincy Divestiture
Consideration for divestiture									$ 44,000
Second Lien Notes
Aggregate principal amount borrowed			$ 625,000		$ 625,000
Interest rate (as a percent)			10.00%
Third Lien Notes
Aggregate principal amount borrowed	$ 20,000	$ 20,000	$ 504,100		529,653
Interest rate (as a percent)			12.00%
Par value of debt exchanged for					524,121
Credit Facility
Aggregate principal amount borrowed						435,150
2020 Senior Notes
Aggregate principal amount borrowed					293,625	600,000						$ 600,000
Interest rate (as a percent)			10.75%
Par value of debt exchanged for	306,400	26,600	$ 279,800		(242,445)
2021 Senior Notes
Aggregate principal amount borrowed					347,652	$ 700,000				$ 700,000
Interest rate (as a percent)			9.25%
Par value of debt exchanged for	$ 352,300	$ 2,000	$ 350,300		(281,676)
Unsecured Notes
Percentage of exchanged debt's par value		70.00%	80.00%
Senior Revolving Credit Facility, due 2018
Proceeds from revolving credit facility				$ 249,200	$ 0
Borrowing Base Redetermination
Period during which Company may request additional redetermination of borrowing base					6 months
Period for commencement of repayment of equal successive monthly payments following the administrative agent's notice regarding borrowing base reduction					30 days
Number of equal successive monthly payments to make repayment on reduction of borrowing base | item					6
Senior Revolving Credit Facility, due 2018 | Minimum
Borrowing Base Redetermination
Percentage of outstanding loans and other obligations held by lenders, on whose behalf the administrative agent may request for redetermination of borrowing base					67.00%
Senior Revolving Credit Facility, due 2018 | Maximum
Borrowing Base Redetermination
Additional borrowing base redeterminations at company request per 6 month period following each scheduled borrowing base redetermination | item					1

Summary of Significant Accoun38

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2015USD ($)segment	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Number of reportable segments | segment	1
Cash and Cash Equivalents
Cash balance of FDIC insured amount	$ 250,000
Cash balance of FDIC uninsured amount	87,200,000	$ 34,300,000
Accounts Receivable and Allowance for Doubtful Accounts
Allowance for doubtful accounts	0	0
Other Noncurrent Assets
Deferred financing costs associated with the Credit Facility	6,105,000	9,189,000
Field equipment inventory	3,225,000	5,713,000
Other	166,000	211,000
Other noncurrent assets	9,496,000	15,113,000
Losses on the sale of field equipment inventory	2,000,000	4,100,000
Oil and Gas Reserves
Provision for price and cost escalations	0
Impairments of oil and gas properties	1,625,776,000	86,471,000	$ 453,310,000
Accrued Liabilities
Accrued oil and gas capital expenditures	19,984,000	76,398,000
Accrued revenue and royalty distributions	27,939,000	51,292,000
Accrued lease operating and workover expense	9,281,000	10,113,000
Accrued interest	20,193,000	21,521,000
Accrued taxes	1,272,000	4,226,000
Compensation and benefit related accruals	8,414,000	10,766,000
Other	4,629,000	9,515,000
Accrued liabilities	91,712,000	183,831,000
Assets:
Other noncurrent assets	9,496,000	15,113,000
Total other assets	9,496,000	50,934,000
TOTAL	679,167,000	2,447,175,000
Liabilities:
Long-term debt less unamortized debt issuance costs		1,706,532,000
Total long-term liabilities	20,673,000	1,729,837,000
TOTAL	679,167,000	2,447,175,000
Credit Facility
Liabilities:
Amount borrowing of outstanding	0
Accounting Standards Update 2015-03 And 2015-15 | Effect of Accounting Principle Early Adoption | Previously Reported
Other Noncurrent Assets
Other noncurrent assets		43,731,000
Assets:
Other noncurrent assets		43,731,000
Total other assets		79,552,000
TOTAL		2,475,793,000
Liabilities:
Long-term debt less unamortized debt issuance costs		1,735,150,000
Total long-term liabilities		1,758,455,000
TOTAL		2,475,793,000
Accounting Standards Update 2015-03 And 2015-15 | Effect of Accounting Principle Early Adoption | Effect of Accounting Principle Adoption
Other Noncurrent Assets
Other noncurrent assets		(28,618,000)
Assets:
Other noncurrent assets		(28,618,000)
Total other assets		(28,618,000)
TOTAL		(28,618,000)
Liabilities:
Long-term debt less unamortized debt issuance costs		(28,618,000)
Total long-term liabilities		(28,618,000)
TOTAL		(28,618,000)
Mississippian
Other Noncurrent Assets
Unevaluated property costs transferred to the full cost pool	56,300,000	59,200,000
Andarko Basin
Other Noncurrent Assets
Unevaluated property costs transferred to the full cost pool	200,000	128,200,000
Gulf Coast
Other Noncurrent Assets
Unevaluated property costs transferred to the full cost pool	$ 100,000	$ 16,500,000
Other Property and Equipment | Minimum
Estimated useful lives	3 years
Other Property and Equipment | Maximum
Estimated useful lives	7 years

Fair Value Measurements of Fi39

Fair Value Measurements of Financial Instruments (Details) - Recurring - Commodity Derivatives $ in Thousands	Dec. 31, 2014USD ($)item
Total
Assets:
Total assets	$ 126,709
Total | Swaps | Oil
Assets:
Total assets	106,450
Total | Swaps | Natural Gas
Assets:
Total assets	$ 20,259
Significant Other Observable Inputs (Level 2)
Fair Value Measurements of Financial Instruments
Number of bank counterparties for company's commodity derivative contracts | item	7
Assets:
Total assets	$ 126,709
Significant Other Observable Inputs (Level 2) | Swaps | Oil
Assets:
Total assets	106,450
Significant Other Observable Inputs (Level 2) | Swaps | Natural Gas
Assets:
Total assets	$ 20,259

Risk Management and Derivativ40

Risk Management and Derivative Instruments - By Nature (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Risk Management and Derivative Instruments
Derivative, Notional Amount	$ 0
Not designated as Hedging Instrument | Commodity Derivatives
Derivative assets:
Gross Recognized Assets		$ 126,709
Net Recognized Fair Value Assets		126,709
Not designated as Hedging Instrument | Commodity Derivatives | Current Assets
Derivative assets:
Gross Recognized Assets		126,709
Net Recognized Fair Value Assets		126,709
Not designated as Hedging Instrument | Commodity Derivatives | Swaps | Current Assets | Oil
Derivative assets:
Gross Recognized Assets		106,450
Not designated as Hedging Instrument | Commodity Derivatives | Swaps | Current Assets | Natural Gas
Derivative assets:
Gross Recognized Assets		$ 20,259

Risk Management and Derivativ41

Risk Management and Derivative Instruments - Gain Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Gains (losses) on Commodity Derivative Contracts
Net cash received (paid) for commodity derivative contracts	$ (167,669)	$ 18,332	$ 17,585
Unrealized net gains (losses)	(126,700)
Gains (losses) on commodity derivative contracts - net	40,960	139,189	(44,284)
Not designated as Hedging Instrument
Gains (losses) on Commodity Derivative Contracts
Net cash received (paid) for commodity derivative contracts	167,669	(18,332)	(17,585)
Unrealized net gains (losses)	(126,709)	157,521	(26,699)
Gains (losses) on commodity derivative contracts - net	$ 40,960	$ 139,189	$ (44,284)

Property and Equipment (Details

Property and Equipment (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / Boe	Dec. 31, 2014USD ($)$ / Boe	Dec. 31, 2013USD ($)$ / Boe
Property and Equipment
Proved properties	$ 3,666,403	$ 3,398,146
Unevaluated properties		44,535
Other property and equipment	14,798	13,454
Less accumulated depreciation, depletion, amortization and impairment	(3,157,332)	(1,333,019)
Net property and equipment	523,869	2,123,116
Other information
Capitalized qualifying share-based compensation expense	1,300	2,200
Other Property and Equipment
Other information
Depreciation	3,500	3,100	$ 2,200
Oil and Gas Properties
Other information
Depletion expense related to oil and gas properties	$ 195,200	$ 266,800	$ 248,200
Depletion expense (per Boe) | $ / Boe	16.26	22.75	28.42
Costs capitalized to unevaluated properties	$ 4,900	$ 12,400	$ 32,200
Internal costs capitalized to oil and gas properties	7,300	12,400	8,400
Capitalized qualifying share-based compensation expense	$ 1,300	$ 2,200	$ 1,400

Acquisition and Divestitures 43

Acquisition and Divestitures of Oil and Gas Properties (Details) - USD ($) $ / shares in Units, $ in Thousands	Apr. 21, 2015	Jun. 25, 2014	May. 01, 2014	Mar. 05, 2014	May. 31, 2013	Jan. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and gas properties
Proved							$ 3,666,403	$ 3,398,146
Additional disclosures
Proceeds from the sale of oil and gas properties							42,366	152,133
Unaudited Pro forma information
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS							(1,798,143)	67,271	$ (359,574)
Acquisition and transaction costs							330	4,129	11,803
Pro Forma
Unaudited Pro forma information
Revenues and other									539,562
Net loss									(340,400)
Preferred stock dividends									(15,589)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS									$ (355,989)
Net loss per common share - basic and diluted									$ (54.13)
Anadarko Basin Acquisition
Oil and gas properties
Proved					$ 417,750
Unevaluated					207,606
Total assets acquired					625,356
Asset retirement obligations					6,296
Total liabilities assumed					6,296
Net assets acquired					619,060
Additional disclosures
Revenue included in the statement of consolidated operations								178,900	$ 104,700
Unaudited Pro forma information
Acquisition and transaction costs									$ 11,800
Petro Quest | Exploration agreement
Unaudited Pro forma information
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
Panther Energy LLC | Anadarko Basin Acquisition | 2021 Senior Notes
Acquisition of Oil and Gas Properties
Purchase price, cash					$ 618,000
Dequincy Divestiture
Additional disclosures
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
Unaudited Pro forma information
Acquisition and transaction costs							$ 300
Pine Prairie Disposition
Additional disclosures
Proceeds from the sale of oil and gas properties				$ 170,000
Net proceeds from disposition			$ 147,700
Gain (loss) on divestiture of business recognized			0
Unaudited Pro forma information
Acquisition and transaction costs								$ 4,100
Pine Prairie Disposition | Credit Facility
Unaudited Pro forma information
Repayment of debt			$ 131,000

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations
Asset retirement obligations	$ 21,599	$ 26,308	$ 15,245
Changes in Company's asset retirement obligations
Asset retirement obligations at beginning of year	21,599	26,308	15,245
Liabilities incurred	127	996	2,535
Liabilities assumed in Anadarko Basin Acquisition			6,296
Revisions	570	288	858
Liabilities settled	(279)	(47)	(61)
Liabilities eliminated through asset sales	(4,919)	(7,652)
Current period accretion expense	1,610	1,706	1,435
Asset retirement obligations at end of year	$ 18,708	$ 21,599	$ 26,308

Debt (Details)

Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Jun. 02, 2015	May. 21, 2015	Dec. 31, 2014	May. 31, 2013	Oct. 01, 2012
Debt
Principal	$ 1,795,930			$ 1,735,150
Unamortized Deferred Gain on Debt Forgiven	119,654
Unamortized Debt Issuance Costs	(24,640)			(28,618)
Total	1,890,944			1,706,532
Credit Facility
Debt
Principal				435,150
Total				435,150
2020 Senior Notes
Debt
Principal	293,625			600,000		$ 600,000
Unamortized Debt Issuance Costs	(11,344)			(13,475)
Total	282,281			586,525
2021 Senior Notes
Debt
Principal	347,652			700,000	$ 700,000
Unamortized Debt Issuance Costs	(13,296)			(15,143)
Total	334,356			$ 684,857
Second Lien Notes
Debt
Principal	625,000		$ 625,000
Unamortized Deferred Gain on Debt Forgiven	42,293
Total	667,293
Third Lien Notes
Debt
Principal	529,653	$ 20,000	$ 504,100
Unamortized Deferred Gain on Debt Forgiven	77,361
Total	$ 607,014

Debt - Debt Restructuring (Deta

Debt - Debt Restructuring (Details) - USD ($) $ in Thousands	Jun. 02, 2015	Jun. 02, 2015	May. 21, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	May. 31, 2013	Oct. 01, 2012
Debt Restructuring
Borrowings				$ 625,000		$ 700,000
Gain (loss) on restructuring of debt				0
Carrying Value, beginning balance				1,735,150
Borrowings/(Repayments)				189,850
Repayment of revolving credit facility				(468,150)	$ (131,000)	$ (34,300)
Amortization of Forgiven Debt				(14,948)
Paid-in kind interest added to principal				5,532
Carrying Value, ending balance				1,915,584	1,735,150
Unamortized Deferred Gain on Debt Forgiven				(119,654)
Principle Balance Outstanding				1,795,930	1,735,150
Second Lien Notes
Debt Restructuring
Borrowings			$ 625,000
Borrowings/(Repayments)				625,000
Deferred Gain on Forgiven Debt				47,082
Amortization of Forgiven Debt				(4,789)
Carrying Value, ending balance				667,293
Unamortized Deferred Gain on Debt Forgiven				(42,293)
Principle Balance Outstanding			625,000	625,000
Credit Facility
Debt Restructuring
Carrying Value, beginning balance				435,150
Borrowings/(Repayments)				(435,150)
Carrying Value, ending balance					435,150
Principle Balance Outstanding					435,150
Third Lien Notes
Debt Restructuring
Exchanges				524,121
Deferred Gain on Forgiven Debt				87,520
Amortization of Forgiven Debt				(10,159)
Paid-in kind interest added to principal				5,532
Carrying Value, ending balance				607,014
Unamortized Deferred Gain on Debt Forgiven				(77,361)
Principle Balance Outstanding	$ 20,000	$ 20,000	504,100	529,653
2020 Senior Notes
Debt Restructuring
Principal amount extinguished		63,900
Carrying Value, beginning balance				600,000
Exchanges	306,400	26,600	279,800	(242,445)
Deferred Gain on Forgiven Debt				(63,930)
Carrying Value, ending balance				293,625	600,000
Principle Balance Outstanding				293,625	600,000			$ 600,000
2021 Senior Notes
Debt Restructuring
Principal amount extinguished		70,700
Carrying Value, beginning balance				700,000
Exchanges	$ 352,300	$ 2,000	$ 350,300	(281,676)
Deferred Gain on Forgiven Debt				(70,672)
Carrying Value, ending balance				347,652	700,000
Principle Balance Outstanding				$ 347,652	$ 700,000		$ 700,000
Unsecured Notes
Debt Restructuring
Percentage of exchanged debt's par value		70.00%	80.00%

Debt - Credit Facilities, Debt

Debt - Credit Facilities, Debt Covenants and Cross Default provisions (Details) $ in Thousands	Jun. 02, 2015USD ($)	Jun. 02, 2015USD ($)	May. 21, 2015USD ($)	Mar. 24, 2015	Feb. 29, 2016USD ($)	Dec. 31, 2015USD ($)item	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Oct. 14, 2015USD ($)	Aug. 05, 2015USD ($)	Aug. 04, 2015USD ($)	May. 31, 2013USD ($)	Oct. 01, 2012USD ($)
Debt
Proceeds from revolving credit facility						$ 33,000	$ 165,000	$ 341,450
Aggregate principal amount borrowed						$ 1,795,930	1,735,150
Midstates Sub
Debt
Ownership interest (as a percent)						100.00%
Eighth Amendment | Midstates Sub
Debt
Operating lease basket										$ 3,500	$ 2,000
Minimum
Debt
Current ratio						1
Maximum
Debt
Total Senior Indebtedness (as defined) to EBITDA						1
Senior Revolving Credit Facility, due 2018
Debt
Maximum borrowing capacity						$ 750,000
Borrowing base						252,000			$ 252,000
Proceeds from revolving credit facility					$ 249,200	0
Outstanding letters of credit amount						$ 2,800
Commitment fee, option one (as a percent)						0.375%
Commitment fee, option two (as a percent)						0.50%
Period during which Company may request additional redetermination of borrowing base						6 months
Number of equal successive monthly payments to make repayment on reduction of borrowing base | item						6
Period for commencement of repayment of equal successive monthly payments following the administrative agent's notice regarding borrowing base reduction						30 days
Leverage ratio				4
Mortgage requirement- percentage of properties included in the borrowing base that are required to be subject to mortgages for the benefit of the lenders				80.00%
Senior Revolving Credit Facility, due 2018 | LIBOR Loans
Debt
Interest rate, description						LIBOR
Senior Revolving Credit Facility, due 2018 | Sixth Amendment
Debt
Leverage ratio				4.5
Mortgage requirement- percentage of properties included in the borrowing base that are required to be subject to mortgages for the benefit of the lenders				90.00%
Senior Revolving Credit Facility, due 2018 | Seventh Amendment
Debt
Borrowing base			$ 252,000
Total Senior Indebtedness (as defined) to EBITDA			1
Senior Revolving Credit Facility, due 2018 | Minimum
Debt
Percentage of outstanding loans and other obligations held by lenders, on whose behalf the administrative agent may request for redetermination of borrowing base						67.00%
Senior Revolving Credit Facility, due 2018 | Minimum | LIBOR Loans
Debt
Interest rate added to base rate (as a percent)						2.00%
Senior Revolving Credit Facility, due 2018 | Maximum
Debt
Additional borrowing base redeterminations at company request per 6 month period following each scheduled borrowing base redetermination | item						1
Senior Revolving Credit Facility, due 2018 | Maximum | LIBOR Loans
Debt
Interest rate added to base rate (as a percent)						3.00%
2020 Senior Notes
Debt
Aggregate principal amount borrowed						$ 293,625	$ 600,000						$ 600,000
Redemption price, expressed as percentage of principal amount						101.00%
Exchanges	$ 306,400	$ 26,600	$ 279,800			$ (242,445)
Estimated fair value of the Notes						$ 35,200
Effective annual interest rate (as a percent)						11.20%	11.10%
Interest rate (as a percent)			10.75%
2021 Senior Notes
Debt
Aggregate principal amount borrowed						$ 347,652	$ 700,000					$ 700,000
Exchanges	352,300	2,000	$ 350,300			(281,676)
Estimated fair value of the Notes						$ 41,700
Effective annual interest rate (as a percent)						9.60%	9.60%
Redemption price, upon the occurrence of certain change of control events (as a percentage)						101.00%
Interest rate (as a percent)			9.25%
Second Lien Notes
Debt
Aggregate principal amount borrowed			$ 625,000			$ 625,000
Estimated fair value of the Notes						$ 262,500
Effective annual interest rate (as a percent)						10.50%
Redemption price, upon the occurrence of certain change of control events (as a percentage)						101.00%
Interest rate (as a percent)			10.00%
Third Lien Notes
Debt
Aggregate principal amount borrowed	$ 20,000	$ 20,000	$ 504,100			$ 529,653
Exchanges						524,121
Estimated fair value of the Notes						$ 94,300
Effective annual interest rate (as a percent)						12.60%
Redemption price, upon the occurrence of certain change of control events (as a percentage)						101.00%
Interest rate (as a percent)			12.00%
Cash interest rate			10.00%
PIK Interest			2.00%

Preferred Stock (Details)

Preferred Stock (Details) - Series A Preferred Stock - USD ($) $ / shares in Units, $ in Millions	Sep. 30, 2015	Oct. 01, 2012	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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%
Conversion rate for preferred stock (in dollars per share)	$ 110				$ 110	$ 110
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
Preferred stock dividends					$ 10.4	$ 15.6
Issuance of common stock for Series A Preferred Stock conversion					265,979	245,912
Notional dividend amount of convertible preferred stock					$ 29.3	$ 27.1
Changes in number of outstanding shares
Share count at the beginning of the period (in shares)				325,000	325,000	325,000
Issuance of preferred stock as consideration in Eagle Property Acquisition (in shares)							325,000
Conversion of preferred stock into common stock				(325,000)
Share count at the end of the period (in shares)					325,000	325,000	325,000

Equity and Share-Based Compen49

Equity and Share-Based Compensation - By Stock Type (Details)	Aug. 03, 2015$ / sharesshares	Apr. 25, 2012$ / sharesshares	Dec. 31, 2015itemshares	Dec. 31, 2014shares	Dec. 31, 2013shares	Dec. 31, 2015$ / sharesshares	Dec. 31, 2014$ / sharesshares
Common shares
Common stock, par value (in dollars per share) | $ / shares						$ 0.01	$ 0.01
Common stock, shares authorized						100,000,000	100,000,000
Common Stock
Common shares
Shares issued			7,049,173	6,892,574	6,661,971	10,962,105	7,049,173
Shares outstanding						10,865,814
Issuance of common stock		2,760,000
Common stock, par value (in dollars per share) | $ / shares	$ 0.01	$ 0.01
Number of shares of stock sold by the selling shareholders		600,000
Number of shares of sold by the selling shareholders pursuant to an option granted to the underwriters to cover over-allotments		360,000
Stock split ratio	0.1
Common stock, shares authorized	100,000,000
Number of votes per share entitled to holders | item			1
Number of preferences or rights of conversion, exchange, pre-exemption or other subscription rights for common stock | item			0
Changes in number of outstanding shares
Share count at the beginning of the period (in shares)			7,049,173	6,892,574	6,661,971
Grants of restricted stock (in shares)			268,677	344,748	284,024
Forfeitures of restricted stock (in shares)			(94,159)	(188,149)	(53,421)
Fractional Share Adjustment						(10)
Issuance of common stock for Series A Preferred Stock conversion			3,738,424
Share count at the end of the period (in shares)			10,962,105	7,049,173	6,892,574
Treasury Stock
Common shares
Shares issued			(53,467)	(11,870)	(11,870)	(96,291)	(53,467)
Changes in number of outstanding shares
Share count at the beginning of the period (in shares)			(53,467)	(11,870)
Acquisition of treasury stock (in shares)			(42,824)	(41,597)	(11,870)
Share count at the end of the period (in shares)			(96,291)	(53,467)	(11,870)
Preferred Stock
Common shares
Preferred stock, shares authorized		50,000,000
Preferred stock, par value (in dollars per share) | $ / shares		$ 0.01

Equity and Share-Based Compen50

Equity and Share-Based Compensation - Incentive Awards (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2014USD ($)
Incentive units
Restricted Stock Awards
Stock-based compensation expense (in dollars)	$ 0

Equity and Share-Based Compen51

Equity and Share-Based Compensation - Restricted Stock Awards (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	May. 27, 2014	Apr. 20, 2012
Restricted stock awards
Restricted Stock Awards
Restricted common stock outstanding	306,202	296,367	98,535	318,031	306,202
Requisite service period for recognition of compensation expense	3 years
Shares
Non-vested shares outstanding at the beginning of the period	306,202	296,367	98,535
Granted (in shares)	268,677	344,748	284,024
Vested (in shares)	(162,689)	(146,764)	(32,772)
Forfeited (in shares)	(94,159)	(188,149)	(53,420)
Non-vested shares outstanding at the end of the period	318,031	306,202	296,367
Weighted Average Grant Date Fair Value
Non-vested shares outstanding at the beginning of the period (in dollars per share)	$ 52.76	$ 77.78	$ 126.13
Granted (in dollars per share)	12.29	46.60	68.23
Vested (in dollars per share)	54.39	72.08	126.18
Forfeited (in dollars per share)	38.69	65.83	86.46
Non-vested shares outstanding at the end of the period (in dollars per share)	$ 21.46	$ 52.76	$ 77.78
Additional information
Unrecognized expense, adjusted for estimated forfeitures (in dollars)				$ 3.8
Weighted-average period for over which unrecognized expense will be recognized	1 year 6 months 11 days
2012 LTIP
Restricted Stock Awards
Number of shares authorized					863,843	863,843	656,343
Additional information
Shares available for issuance				203,589
2012 LTIP | Restricted stock awards
Restricted Stock Awards
Restricted common stock outstanding	318,031			318,031
Vesting period	3 years
Percentage of awards vesting on each anniversary of the grant	33.00%
Shares
Non-vested shares outstanding at the end of the period	318,031
2012 LTIP | Restricted stock awards | Directors
Restricted Stock Awards
Vesting period	1 year

Equity and Share-Based Compen52

Equity and Share-Based Compensation - By Share Based Payment Award (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation, Post-Initial Public Offering
Total share-based compensation expense	$ 4,408	$ 8,618	$ 5,713
Capitalized qualifying share-based compensation costs to oil and gas properties	1,300	2,200
Severance
Share-based Compensation, Post-Initial Public Offering
Total share-based compensation expense	1,500	2,900
2012 LTIP | General and administrative expense.
Share-based Compensation, Post-Initial Public Offering
Share-based compensation costs recognized	$ 4,400	$ 8,600	$ 5,700

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes
Tax refund	$ 0
Valuation allowance against net operating loss carryforwards	689,400
Unrealized loss from hedging activity	126,700
Impairment of Oil and Gas Properties	1,625,776	$ 86,471	$ 453,310
Income (loss) before taxes	(1,806,836)	123,324	(490,514)
Income tax payments expected in the upcoming four quarterly reporting periods	0
Current
State		809
Total current		809
Deferred
United States	(3,864)	3,863	(130,906)
State	(5,777)	1,723	(15,623)
Total deferred	(9,641)	5,586	(146,529)
Total income tax provision (benefit)	9,641	(6,395)	146,529
Reconciliation of income tax expense
Income (loss) before taxes	$ (1,806,836)	$ 123,324	$ (490,514)
Statutory rate	35.00%	35.00%	35.00%
Income tax provision (benefit) computed at statutory rate	$ (632,393)	$ 43,164	$ (171,680)
Reconciling items:
State income taxes, net of federal benefit	(65,904)	4,398	(10,886)
Change in valuation allowance	689,419	(42,134)	45,688
Change in state rate	(612)	(414)	(10,500)
Other, net	(151)	1,381	849
Total income tax provision (benefit)	(9,641)	6,395	$ (146,529)
Deferred tax assets - noncurrent
Federal tax loss carryforwards	146,641	75,604
State tax loss carryforwards	13,848	7,122
Employee benefit plans	1,160	2,193
Oil and gas properties and equipment	465,028
Debt restructuring	66,693
Less valuation allowance	$ (693,370)	(3,826)
Total deferred tax assets, noncurrent		81,093
Deferred tax liabilities-current
Derivative instruments and other		44,862
Total deferred tax liabilities - current		44,862
Oil and gas properties and equipment		45,272
Total deferred tax liabilities, noncurrent		45,272
Reflected in the accompanying balance sheet as:
Net deferred tax liability, current		44,862
Net deferred tax asset, noncurrent		$ 35,821

Earnings (Loss) Per Share (Deta

Earnings (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings (Loss) Per Share
Net income (loss)	$ (1,797,195)	$ 116,929	$ (343,985)
Preferred Dividend	(948)	(10,378)	(15,589)
Net income (loss) attributable to shareholders	(1,798,143)	106,551	(359,574)
Participating securities - Series A Preferred Stock		(35,696)
Participating securities - Non-vested Restricted Stock		(3,584)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (1,798,143)	$ 67,271	$ (359,574)
Weighted average shares outstanding	7,726	6,644	6,576
Basic and diluted net income (loss) per share	$ (232.74)	$ 10.13	$ (54.68)

Concentrations of Credit Risk (

Concentrations of Credit Risk (Details)	12 Months Ended
	Dec. 31, 2015derivativeitem	Dec. 31, 2014item	Dec. 31, 2013item
Concentrations of Credit Risk
Short-term contracts usual term	1 month
Number of derivatives held | derivative	0
Revenue | Customer concentration
Concentrations of Credit Risk
Number of purchasers	2	4	5
Revenue | Customer concentration | Purchaser one
Concentrations of Credit Risk
Concentration risk (as a percent)	43.00%	28.00%	28.00%
Revenue | Customer concentration | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)	25.00%	18.00%	16.00%
Revenue | Customer concentration | Purchaser three
Concentrations of Credit Risk
Concentration risk (as a percent)		15.00%	13.00%
Revenue | Customer concentration | Purchaser four
Concentrations of Credit Risk
Concentration risk (as a percent)		12.00%	12.00%
Revenue | Customer concentration | Purchaser five
Concentrations of Credit Risk
Concentration risk (as a percent)			11.00%
Accounts receivable | Customer concentration
Concentrations of Credit Risk
Number of purchasers	3	4
Accounts receivable | Customer concentration | Purchaser one
Concentrations of Credit Risk
Concentration risk (as a percent)	33.00%	25.00%
Accounts receivable | Customer concentration | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)	29.00%	23.00%
Accounts receivable | Customer concentration | Purchaser three
Concentrations of Credit Risk
Concentration risk (as a percent)	14.00%	15.00%
Accounts receivable | Customer concentration | Purchaser four
Concentrations of Credit Risk
Concentration risk (as a percent)		13.00%

Commitments and Contingencies56

Commitments and Contingencies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / gal	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Net minimum commitments
2,016	$ 8,537
2,017	1,941
2,018	1,471
2,019	966
2020 and beyond	1,208
Total	14,123
Office rent	2,300	$ 2,300	$ 1,700
Loss Contingency Accrual	1,000	$ 200
Drilling contracts
Net minimum commitments
2,016	3,468
Total	3,468
Non-cancellable office lease commitments
Net minimum commitments
2,016	1,877
2,017	1,941
2,018	1,471
2,019	966
2020 and beyond	1,208
Total	7,463
Non-cancellable office lease commitments | Houston
Net minimum commitments
Total	2,500
Seismic contracts
Net minimum commitments
2,016	3,192
Total	$ 3,192
Gas transportation gathering and processing contract | Minimum
Net minimum commitments
Fee used as multiple for payment to the counterparty equal to the shortfall amount (in dollars per gallon/MMBTU) | $ / gal	0.08
Gas transportation gathering and processing contract | Maximum
Net minimum commitments
Fee used as multiple for payment to the counterparty equal to the shortfall amount (in dollars per gallon/MMBTU) | $ / gal	0.125