Amplify Energy (AMPY) 10-K 16 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Mar. 09, 2015	Jun. 30, 2014
Document and Entity Information
Entity Registrant Name	Midstates Petroleum Company, Inc.
Entity Central Index Key	1533924
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$272
Entity Common Stock, Shares Outstanding		72,196,132
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
CURRENT ASSETS:
Cash and cash equivalents	$11,557	$33,163
Accounts receivable:
Oil and gas sales	69,161	102,483
Joint interest billing	42,407	42,631
Other	22,193	1,090
Commodity derivative contracts	126,709	700
Deferred income taxes		11,837
Other current assets	1,098	693
Total current assets	273,125	192,597
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full cost accounting	3,442,681	3,060,661
Other property and equipment	13,454	11,113
Less accumulated depreciation, depletion, amortization and impairment	-1,333,019	-976,880
Net property and equipment	2,123,116	2,094,894
OTHER ASSETS:
Commodity derivative contracts		19
Deferred income taxes	35,821
Other noncurrent assets	43,731	54,597
Total other assets	79,552	54,616
TOTAL	2,475,793	2,342,107
CURRENT LIABILITIES:
Accounts payable	22,783	21,493
Accrued liabilities	183,831	204,381
Commodity derivative contracts		27,880
Deferred income taxes	44,862
Total current liabilities	251,476	253,754
LONG-TERM LIABILITIES:
Asset retirement obligations	21,599	26,308
Commodity derivative contracts		3,651
Long-term debt	1,735,150	1,701,150
Deferred income taxes		15,291
Other long-term liabilities	1,706	1,954
Total long-term liabilities	1,758,455	1,748,354
COMMITMENTS AND CONTINGENCIES (Note 15)
STOCKHOLDERS' EQUITY
Preferred stock
Common stock, $0.01 par value, 300,000,000 shares authorized; 70,491,732 shares issued and 69,957,055 shares outstanding at December 31, 2014 and 68,925,745 shares issued and 68,807,043 shares outstanding at December 31, 2013	704	689
Treasury stock	-2,592	-664
Additional paid-in-capital	881,894	871,047
Retained deficit	-414,147	-531,076
Total stockholders' equity	465,862	339,999
TOTAL	2,475,793	2,342,107
Series A Preferred Stock
STOCKHOLDERS' EQUITY
Preferred stock	3	3
Total stockholders' equity	$3	$3

CONDENSED_CONSOLIDATED_BALANCE1

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Common stock, par value (in dollars per share)	$0.01	$0.01
Common stock, shares authorized	300,000,000	300,000,000
Common stock, shares issued	70,491,732	68,925,745
Common stock, shares outstanding	69,957,055	68,807,043
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	$0.01
Preferred stock, shares issued	325,000	325,000
Preferred stock, shares outstanding	325,000	325,000
Preferred stock, liquidation value (in dollars per share)	$387,808	$358,550
Preferred stock, cumulative dividends (as a percent)	8.00%	8.00%

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES :
Oil sales	$466,655	$387,226	$218,430
Natural gas liquid sales	87,771	62,340	23,617
Natural gas sales	99,204	63,187	16,030
Gains (losses) on commodity derivative contracts - net	139,189	-44,284	-11,158
Other	1,364	1,037	754
Total revenues	794,183	469,506	247,673
EXPENSES :
Lease operating and workover	79,598	73,414	30,500
Gathering and transportation	13,404	5,455
Severance and other taxes	24,266	27,237	24,921
Asset retirement accretion	1,706	1,435	723
Depreciation, depletion, and amortization	269,935	250,396	125,561
Impairment in carrying value of oil and gas properties	86,471	453,310
General and administrative	48,733	53,250	30,541
Acquisition and transaction costs	4,129	11,803	14,884
Other	5,108	615
Total expenses	533,350	876,915	227,130
OPERATING INCOME (LOSS)	260,833	-407,409	20,543
OTHER INCOME (EXPENSE)
Interest income	39	33	245
Interest expense - net of amounts capitalized	-137,548	-83,138	-12,999
Total other income (expense)	-137,509	-83,105	-12,754
INCOME (LOSS) BEFORE TAXES	123,324	-490,514	7,789
Income tax benefit (expense)	-6,395	146,529	-157,886
NET INCOME ( LOSS)	116,929	-343,985	-150,097
Preferred stock dividend	-10,378	-15,589	-6,500
Participating securities - Series A Preferred Stock	35,696
Participating securities - Non-vested Restricted Stock	3,584
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$67,271	($359,574)	($156,597)
Basic and diluted net income (loss) per share attributable to common shareholders	$1.01	($5.47)	($2.61)
Basic and diluted weighted average number of common shares outstanding	66,440	65,766	59,979

CONDENSED_CONSOLIDATED_STATEME1

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (USD $)	Eagle Property Acquisition	Series A Preferred Stock	Common Stock	Treasury Stock	Capital Contributions	Additional Paid-in-Capital	Retained Deficit/Accumulated Loss	Total
In Thousands, unless otherwise specified
Balance at Dec. 31, 2011					$322,496		($36,994)	$285,502
Increase (Decrease) in Stockholders' Equity
Issuance of common stock			476		-476
Reclassification of members' contributions					-322,020	322,020
Proceeds from the sale of common stock			180			213,389		213,569
Tax attributes contributed at IPO reorganization date by shareholding entities IPO reorganization date by shareholding entities						33,888		33,888
Issuance of preferred stock as consideration in the Eagle Property Acquisition	291,956	3				291,953		291,956
Share-based compensation			10			2,641		2,651
Net income (loss)							-150,097	-150,097
Balance at Dec. 31, 2012		3	666			863,891	-187,091	677,469
Increase (Decrease) in Stockholders' Equity
Share-based compensation			23			7,156		7,179
Acquisition of treasury stock				-664				-664
Net income (loss)							-343,985	-343,985
Balance at Dec. 31, 2013		3	689	-664		871,047	-531,076	339,999
Increase (Decrease) in Stockholders' Equity
Share-based compensation			15			10,847		10,862
Acquisition of treasury stock				-1,928				-1,928
Net income (loss)							116,929	116,929
Balance at Dec. 31, 2014		$3	$704	($2,592)		$881,894	($414,147)	$465,862

CONDENSED_CONSOLIDATED_STATEME2

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$116,929	($343,985)	($150,097)
Adjustments to reconcile net loss to net cash provided by operating activities:
(Gains) losses on commodity derivative contracts-net	-139,189	44,284	11,158
Net cash paid for commodity derivative contracts not designated as hedging instruments	-18,332	-17,585	-15,825
Asset retirement accretion	1,706	1,435	723
Depreciation, depletion, and amortization	269,935	250,396	125,561
Impairment in carrying value of oil and gas properties	86,471	453,310
Share-based compensation, net of amounts capitalized to oil and gas properties	8,618	5,713	2,459
Deferred income taxes	5,586	-146,529	157,886
Amortization of deferred financing costs	7,857	5,955	1,530
Change in operating assets and liabilities:
Accounts receivable - oil and gas sales	33,322	-66,865	-11,826
Accounts receivable - JIB and other	-13,603	-28,488	-11,019
Other current and noncurrent assets	3,191	-1,802	-218
Accounts payable	2,327	-4,350	-646
Accrued liabilities	-7,733	75,903	27,931
Other	-247	-290	-368
Net cash provided by operating activities	356,838	227,102	137,249
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	-561,691	-573,734	-422,332
Investment in acquired property		-620,112	-351,276
Proceeds from the sale of oil and gas properties	152,133
Net cash used in investing activities	-409,558	-1,193,846	-773,608
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings	165,000	1,041,450	744,667
Repayment of long-term borrowings	-131,000	-34,300	-285,467
Proceeds from issuance of mandatorily redeemable convertible preferred units			65,000
Repayment of mandatorily redeemable convertible preferred units			-65,000
Proceeds from sale of common stock, net of initial public offering expenses of $6.4 million			213,569
Deferred financing costs	-958	-25,457	-24,876
Acquisition of treasury stock	-1,928	-664
Net cash provided by financing activities	31,114	981,029	647,893
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	-21,606	14,285	11,534
Cash and cash equivalents, beginning of period	33,163	18,878	7,344
Cash and cash equivalents, end of period	11,557	33,163	18,878
SUPPLEMENTAL INFORMATION:
Non-cash transactions - investments in property and equipment accrued - not paid	95,000	106,500	87,812
Non-cash components of Business Acquisition Purchase Price:
Preferred stock issued for property			291,956
Non- cash components of Pine Prairie Disposition:
Cash paid for interest, net of capitalized interest of $12.4 million, $32.2 million and $11.2 million, respectively	129,511	72,085
Cash paid for taxes	209
Tax attributes contributed at IPO reorganization date by shareholding entities			33,888
Eagle Property Acquisition
Non-cash components of Business Acquisition Purchase Price:
Preferred stock issued for property			291,956
Deferred tax liability assumed		-727	26,712
Asset retirement obligation assumed			2,662
Accrual for additional consideration		-941	1,500
Anadarko Basin Acquisition
Non-cash components of Business Acquisition Purchase Price:
Asset retirement obligation assumed		6,296
Accrual for miscellaneous liabilities assumed	-344	3,030
Pine Prairie Disposition
Non- cash components of Pine Prairie Disposition:
Asset retirement obligation disposed	-7,652
Accrual for miscellaneous liabilities released	-2,185
Other non currents sold	$371

CONDENSED_CONSOLIDATED_STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Initial public offering expenses			$6.40
Capitalized interest	$12.40	$32.20	$11.20

Organization_and_Business

Organization and Business	12 Months Ended
	Dec. 31, 2014
Organization and Business
Organization and Business	1. Organization and Business
	Midstates Petroleum Company, Inc., through its wholly-owned subsidiary Midstates Petroleum Company LLC, engages in the business of drilling for, and production of, oil, natural gas liquids ("NGL") 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 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 27,600,000 shares of $0.01 par value common stock, which included 6,000,000 shares of stock sold by the selling shareholders and 3,600,000 shares of common stock sold by the selling shareholders pursuant to an option granted to the underwriters to cover over-allotments. The Company's sale of the shares in its initial public offering closed on April 25, 2012 and its initial public offering terminated upon completion of the closing.
	The proceeds of the Company's initial public offering, based on the public offering price of $13.00 per share, were approximately $358.8 million. After subtracting underwriting discounts and commissions of $21.5 million and the net proceeds to the selling stockholders of $117.3 million, the Company received net proceeds of approximately $220.0 million from the registration and sale of 18,000,000 common shares (or $213.6 million net of offering expenses paid directly by the Company). The Company used $67.1 million of the net proceeds to redeem convertible preferred units in Holdings LLC, including interest and other charges, and $99.0 million to pay down a portion of the borrowings under its revolving credit facility. The Company used the remaining $47.5 million to fund the execution of its growth strategy through its drilling program. The Company did not receive any of the proceeds from the sale of the 9,600,000 shares by the selling stockholders. Immediately after the initial public offering and exercise of the over-allotment option granted to the underwriters, First Reserve Midstates Interholding LP and its affiliates owned approximately 41.4% of the Company's outstanding common stock.
	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 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 $600 million in aggregate principal amount of 10.75% senior unsecured notes due 2020, which also closed on October 1, 2012 ("2020 Senior Notes").
	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 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 $700 million in aggregate principal amount of 9.25% senior unsecured notes due 2021, which also closed on May 31, 2013 ("2021 Senior Notes").
	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.
	At December 31, 2014, the Company has oil and gas operations and properties in Oklahoma, Texas and Louisiana and operated the oil and natural gas properties as one reportable segment engaged in the exploration, development and production of oil, natural gas liquids and natural gas. The Company's management evaluated performance based on one reportable segment as there were not significantly different economic or operational environments within its oil and natural gas properties.
	All pro forma and per share information presented in the accompanying consolidated financial statements have been adjusted to reflect the effects of the Company's initial public offering.

Liquidity_and_Capital_Resource

Liquidity and Capital Resources	12 Months Ended
	Dec. 31, 2014
Liquidity and Capital Resources
Liquidity and Capital Resources	2. Liquidity and Capital Resources
	As of December 31, 2014, the Company had available cash of approximately $11 million and availability under the reserve based revolving credit facility (the "Credit Facility") of approximately $90 million. If there is a downward revision in estimates of proved reserves, the borrowing base for the revolving credit facility may be reduced, and as a result, available liquidity will be reduced. As of December 31, 2014, payments due on contractual obligations during the next twelve months are approximately $150 million. This includes approximately $130 million of interest payments on the senior notes and other operating expenses such as fixed drilling commitments and operating leases. The Company expects it will need to complete certain transactions, including management of debt capital structure and potential asset sales, to have sufficient liquidity to satisfy these obligations in the long-term.
	Liquidity Sufficiency
	The liquidity outlook has changed since December 31, 2014 primarily as a result of the substantial decrease in oil and gas prices. This has resulted in lower operating cash flows than expected and if commodity prices remain low compared to recent historical prices, will result in future significantly lower levels of operating cash flows as current hedging contracts expire.
	As a result of the commodity price decline and the Company's substantial debt burden, the Company believes that forecasted cash and available credit capacity are not expected to be sufficient to meet commitments as they come due over the next twelve months and that the Company will not be able to remain in compliance with current debt covenants unless able to successfully increase liquidity. Additionally, the terms of the Credit Facility and the indentures governing the senior notes require that some or all of the proceeds from certain asset sales be used to permanently reduce outstanding debt which could substantially reduce the amount of proceeds retained, and the covenants in these debt instruments impose limitations on the amount and type of additional indebtedness the Company can incur, which may significantly reduce the ability to obtain liquidity through the incurrence of additional indebtedness. Furthermore, the ability to refinance any of the existing indebtedness on commercially reasonably terms may be materially and adversely impacted by the current conditions in the energy industry and the Company's financial condition.
	The Company is currently pursuing a number of actions including (i) actively managing the debt capital structure, (ii) selling additional assets, (iii) minimizing capital expenditures, (iv) obtaining waivers or amendments from lenders, (v) effectively managing working capital and (vi) improving cash flows from operations. There can be no assurance that sufficient liquidity can be raised from one or more of these actions or that these actions can be consummated within the period needed to meet certain obligations. The interest payment obligations are substantial, and the Company will be required to pay approximately $32 million in interest on the 2020 Senior Notes on each of April 1 and October 1 and approximately $32 million in interest on the 2021 Senior Notes on each of June 1 and December 1. The Company has obtained a waiver to the Credit Facility waiving any default as a result of delivering an auditors' opinion in connection with the 2014 financial statements that includes a going concern qualification. As the Company pursues the actions mentioned above to increase liquidity, it may need to negotiate additional waivers or amendments to the Credit Facility or indentures to facilitate those actions. There can be no assurance that the lenders or the holders of the senior notes will agree to any amendment or waiver on acceptable terms and if a default occurs, a failure to do so may provide the lenders the opportunity to accelerate the outstanding debt under these facilities and it would be classified as a current liability on the balance sheet.
	The uncertainty associated with the ability to meet commitments as they come due or to repay outstanding debt raises substantial doubt about the ability to continue as a going concern. The accompanying financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities that might result from the uncertainty associated with the ability to meet obligations as they come due.
	Financial Ratio Covenants
	As of December 31, 2014, the ratio of net consolidated indebtedness to EBITDA was 3.7:1.0 and the ratio of current assets to current liabilities was 1.1:1.0. If liquidity concerns are not addressed in the near-term, the Company may breach the leverage covenant of our Credit Facility, in the third quarter of 2015 which currently requires a maximum ratio of net consolidated indebtedness to EBITDA of 4.0:1.0 beginning with the quarter ended March 31, 2015. As of December 31, 2014, the Company was in compliance with the financial ratio covenants included in the Credit Facility.
	Borrowing Base Redetermination
	If oil, NGL, natural gas prices remain weak or deteriorate, the borrowing base under the Credit Facility may be reduced. Any reduction in the borrowing base will reduce our available liquidity, and, if the reduction results in the outstanding amount under the facility exceeding the borrowing base, the Company will be required to repay the deficiency within 30 days or in six 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.
	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.
	Recent Amendments and Waivers
	In March 2015, the Company received a waiver related to the requirement that an unqualified auditors' opinion without an explanatory paragraph in relation to going concern accompany the 2014 financial statements.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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, 2014 include the results of the Pine Prairie field from January 1, 2014 through May 1, 2014, the date of disposition. The consolidated financial statements as of and for the year ended December 31, 2013 include the results from the Anadarko Basin Acquisition beginning May 31, 2013. The consolidated financial statements as of and for the year ended December 31, 2012 include the results from the Eagle Property Acquisition beginning October 1, 2012.
	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. Actual results could differ from those estimates.
	Significant estimates include, but are not limited to, the amount of recoverable oil and natural gas reserves; future cash flows from oil and natural gas properties; 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.
	Accounts Receivable and Allowance for Doubtful Accounts
	Accounts receivable are stated at the historical carrying amount net of 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. 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, 2014 and 2013, 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). Based upon recent amendments to the Company's Credit Facility, the Company believes the carrying amount of the related floating-rate debt approximates fair value due to the variable nature of the interest rate and the current secured financing terms available to the Company. See fair value discussion of Senior Notes and Series A Preferred Shares issued in October 2012 in Notes 9 and 10, respectively. 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 currently 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, 2014 and 2013, other noncurrent assets consisted of the following:
		At December 31,
		2014		2013
		(in thousands)
	Deferred financing costs	$	37,807	$	44,706
	Field equipment inventory		5,713		9,682
	Other		211		209
	Other noncurrent assets	$	43,731	$	54,597
	During the year ended December 31, 2014, the Company has recorded approximately $5.9 million in adjustments to field equipment inventory, either as a result of physical inventory counts, disposals or market adjustments; this is offset by additional inventory added during the period of approximately $1.8 million. For the years ended December 31, 2014 and 2013, the Company recorded $4.1 million and $0.6 million, respectively, of losses on 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, the cost 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 that 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. Based on current pricing and current drilling plans, we impaired the remaining Anadarko Basin unevaluated property to the full cost pool during the fourth quarter of 2014.
	Oil and Gas Reserves
	Proved oil, NGLs and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (FASB), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements.
	Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company depletes its oil and gas properties using the units-of-production method. Capitalized costs of oil and natural gas properties subject to amortization are depleted over proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
	Impairment of Oil and Gas Properties/Ceiling Test
	The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit (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 price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations. For the year ended December 31, 2014, an impairment of oil and gas properties of $83.5 million, after tax, was recorded. For the year ended December 31, 2013, capitalized costs exceeded the ceiling and an impairment of oil and gas properties of $319.6 million, after tax, was recorded.
	The most significant factors affecting the impairment related to the transfer of unevaluated property costs to the full cost pool and negative reserve revisions in certain areas.
	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 to previously unproved acreage 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 up on our lack of plans for further evaluation or development of those leases in the current commodity price environment.
	During 2013, the Company transferred $61.2 million of Gulf Coast unevaluated property costs to the full cost pool based upon our lack of future plans for further evaluation or development of those leases and $168.4 million of Mississippian unevaluated property costs attributable to leases that expired during 2013 or that were assigned to proved reserves as a result of the Company's drilling activities. The Company also transferred $89.6 million of Anadarko Basin unevaluated costs due primarily to lease expirations and development drilling. The negative reserve revisions in our Gulf Coast area were mainly attributable to variability in well performance, our decision during the second quarter of 2013 to halt further development in our West Gordon field and unfavorable cost revisions. See Note 6.
	Depreciation, Depletion, and Amortization (DD&A)
	DD&A 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 DD&A, 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 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. The Company paid cash interest of $141.9 million, $104.3 million, and $7.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	Other Property and Equipment
	Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are 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, 2014 and 2013, accrued liabilities consisted of the following:
		At December 31,
		2014		2013
		(in thousands)
	Accrued oil and gas capital expenditures	$	76,398	$	87,202
	Accrued revenue and royalty distributions		51,292		64,370
	Accrued lease operating and workover expense		10,113		8,279
	Accrued interest		21,521		21,341
	Accrued taxes		4,226		4,386
	Other		20,281		18,803
	Accrued liabilities	$	183,831	$	204,381
	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 acquiring or drilling 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 depreciated 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 in the full cost pool. See Note 8.
	Share-Based Compensation
	We measure share-based compensation cost at fair value and generally recognize the corresponding compensation expense on a straight-line basis over the service period during which awards are expected to vest. We include share-based compensation expense, net of amounts capitalized to oil and gas properties, in "General and administrative expense" in our consolidated statements of operations. See Note 11.
	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 and gas revenues, whereby revenue is recognized for all oil 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, 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 2014 relate to the Pine Prairie Disposition, costs incurred in 2013 relate to the Anadarko Basis Acquisition, and costs incurred in 2012 relate to the Eagle Property Acquisition. See Note 7.
Income Taxes
Income taxes are provided 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.
Prior to its corporate reorganization (See Note 1), the Company was a limited liability company and not subject to federal income tax or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company's equity holders were responsible for income tax on the Company's profits. In connection with the closing of the Company's initial public offering, the Company merged into a corporation and became subject to federal and state income taxes. The Company's book and tax basis in assets and liabilities differed at the time of the corporate reorganization due primarily to different cost recovery periods utilized for book and tax purposes for the Company's oil and natural gas properties. See Note 12.
Earnings (Loss) Per Share
Basic earnings (loss) per common share is calculated by dividing net income 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 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 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.
Recent Accounting Pronouncements
The Company reviewed recently issued accounting pronouncements that became effective during the twelve months ended December 31, 2014, and determined that none would have a material impact on the Company's consolidated financial statements with the exception of ASU 2014-09, "Revenue from Contracts with Customers "and ASU 2014-15, "Presentation of Financial Statements—Going Concern," (both effective for annual reporting periods beginning after December 15, 2016), which the Company is still evaluating.

Fair_Value_Measurements_of_Fin

Fair Value Measurements of Financial Instruments	12 Months Ended
	Dec. 31, 2014
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. At December 31, 2014 and 2013, all of the Company's commodity derivative contracts were with seven counterparties, respectively, and are classified as Level 2.
			Fair Value Measurements at December 31, 2014
			Quoted Prices in		Significant Other		Significant		Total
			Active Markets		Observable Inputs		Unobservable
			(Level 1)		(Level 2)		Inputs
							(Level 3)
			(in thousands)
	Assets:
	Commodity derivative oil swaps		$	—	$	106,450	$	—	$	106,450
	Commodity derivative gas swaps			—		20,259		—		20,259
	Total assets		$	—	$	126,709	$	—	$	126,709
	Liabilities:
	Commodity derivative oil swaps		$	—	$	—	$	—	$	—
	Commodity derivative NGL swaps			—		—		—		—
	Commodity derivative gas swaps			—		—		—		—
	Commodity derivative oil collars			—		—		—		—
	Commodity derivative gas collars			—		—		—		—
	Total liabilities		$	—	$	—	$	—	$	—
			Fair Value Measurements at December 31, 2013
			Quoted Prices in		Significant Other		Significant		Total
			Active Markets		Observable Inputs		Unobservable
			(Level 1)		(Level 2)		Inputs
							(Level 3)
			(in thousands)
	Assets:
	Commodity derivative NGL swaps		$	—	$	469	$	—	$	469
	Commodity derivative gas swaps			—		488		—		488
	Commodity derivative oil collars			—		64		—		64
	Commodity derivative gas collars			—		751		—		751
	Commodity derivative differential swaps			—		806		—		806
	Total assets		$	—	$	2,578	$	—	$	2,578
	Liabilities:
	Commodity derivative oil swaps		$	—	$	32,209	$	—	$	32,209
	Commodity derivative NGL swaps			—		74		—		74
	Commodity derivative gas swaps			—		809		—		809
	Commodity derivative oil collars			—		272		—		272
	Commodity derivative gas collars			—		26		—		26
	Total liabilities		$	—	$	33,390	$	—	$	33,390
	Derivative instruments listed above are presented gross and include collars and 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 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, 2014
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 entering into derivative financial instruments to economically hedge a portion of its crude oil, NGLs and natural gas production. The Company utilizes 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.
	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. Due to the netting arrangements, had the Company's counterparties failed to perform under existing commodity derivative contracts, the maximum loss at December 31, 2014 would have been approximately $126.7 million.
	Commodity Derivative Contracts
	As of December 31, 2014, the Company had the following open commodity positions:
			Hedged			Weighted-Average
			Volume			Fixed Price
	Oil (Bbls):
	WTI Swaps—2015			3,276,000		$	88.72
	Natural Gas (MMBtu):
	Swaps—2015(1)			20,050,000		$	4.15
	-1	Includes 2,170,000 MMBtu in natural gas swaps that priced during the period, but had not cash settled as of December 31, 2014.
	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, 2014 and 2013, respectively (in thousands):
		Type		Balance Sheet Location(1)		December 31,			December 31,
						2014			2013
		Oil Swaps		Derivative financial instruments—Current Assets		$	106,450		$	—
		Oil Swaps		Derivative financial instruments—Current Liabilities			—			(28,871	)
		Oil Swaps		Derivative financial instruments—Non-Current Liabilities			—			(3,338	)
		NGL Swaps		Derivative financial instruments—Current Assets			—			469
		NGL Swaps		Derivative financial instruments—Current Liabilities			—			(74	)
		Gas Swaps		Derivative financial instruments—Current Assets			20,259			469
		Gas Swaps		Derivative financial instruments—Non-Current Assets			—			19
		Gas Swaps		Derivative financial instruments—Current Liabilities			—			(496	)
		Gas Swaps		Derivative financial instruments—Non-Current Liabilities			—			(313	)
		Oil Collars		Derivative financial instruments—Current Assets			—			64
		Oil Collars		Derivative financial instruments—Current Liabilities			—			(272	)
		Gas Collars		Derivative financial instruments—Current Assets			—			751
		Gas Collars		Derivative financial instruments—Current Liabilities			—			(26	)
		Basis Differential Swaps		Derivative financial instruments—Current Assets			—			806
		Total derivative fair value at period end				$	126,709		$	(30,812	)
	-1	The fair values of commodity derivative instruments reported in the Company's consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table summarizes the location and fair value amounts of all derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets at December 31, 2014 and 2013, respectively (in thousands):
					December 31, 2014
	Not Designated as ASC 815 Hedges:		Balance Sheet Classification		Gross Recognized			Gross Amounts			Net Recognized
					Assets/			Offset			Fair Value Assets/
					Liabilities						Liabilities
	Derivative assets:
	Commodity contracts		Derivative financial instruments—current		$	126,709		$	—		$	126,709
	Commodity contracts		Derivative financial instruments—noncurrent			—			—			—
					$	126,709		$	—		$	126,709
	Derivative liabilities:
	Commodity contracts		Derivative financial instruments—current		$	—		$	—		$	—
	Commodity contracts		Derivative financial instruments—noncurrent			—			—			—
					$	—		$	—		$	—
					December 31, 2013
	Not Designated as ASC 815 Hedges:		Balance Sheet		Gross Recognized			Gross Amounts			Net Recognized
			Classification		Assets/			Offset			Fair Value Assets/
					Liabilities						Liabilities
	Derivative assets:
	Commodity contracts		Derivative financial instruments—current		$	2,559		$	1,859		$	700
	Commodity contracts		Derivative financial instruments—noncurrent			19			—			19
					$	2,578		$	1,859		$	719
	Derivative liabilities:
	Commodity contracts		Derivative financial instruments—current		$	29,739		$	1,859		$	27,880
	Commodity contracts		Derivative financial instruments—noncurrent			3,651			—			3,651
					$	33,390		$	1,859		$	31,531
	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. Realized gains and losses represent the actual settlements under commodity derivative contracts that require making a payment to or receiving a payment from the counterparty, as well as any deferred premiums payable to the counterparty upon contract settlement. During the year ended December 31, 2012, the Company paid deferred premiums of $3.3 million related to put options covering a total of 549,000 barrels of crude oil, respectively. No such payments for deferred premiums were made during 2014 or 2013.
	The following table presents realized net losses and unrealized net gains (losses) recorded by the Company in "Gains (losses) on commodity derivative contracts—net" related to the change in fair value of the commodity derivative instruments for the periods presented:
			Years Ended December 31,
			2014			2013			2012
			(in thousands)
	Realized net losses		$	(18,332	)	$	(17,585	)	$	(15,825	)
	Unrealized net gains (losses)			157,521			(26,699	)		4,667
Gains (losses) on commodity derivative contracts—net		$	139,189		$	(44,284	)	$	(11,158	)

Property_and_Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2014
Property and Equipment
Property and Equipment	6. Property and Equipment
	The Company's property and equipment as of December 31, 2014 and 2013 was as follows (in thousands):
		December 31,			December 31,
		2014			2013
		(in thousands)
	Oil and gas properties, on the basis of full-cost accounting:
	Proved properties	$	3,398,146		$	2,817,062
	Unevaluated properties		44,535			243,599
	Other property and equipment		13,454			11,113
	Less accumulated depreciation, depletion, amortization and impairment		(1,333,019	)		(976,880	)
	Net property and equipment	$	2,123,116		$	2,094,894
	For the years ended December 31, 2014, 2013 and 2012, depletion expense related to oil and gas properties was $266.8 million, $248.2 million and $125.1 million, respectively and $22.75, $28.42 and $34.17 per barrel of oil equivalent ("Boe"), respectively. For the years ended December 31, 2014, 2013 and 2012, depreciation expense related to other property and equipment was $3.1 million, $2.2 million and $0.5 million, respectively.
	For the years ended December 31, 2014, 2013 and 2012, interest capitalized to unevaluated properties was $12.4 million, $32.2 million and $11.2 million, respectively. For the years ended December 31, 2014, 2013 and 2012, the Company capitalized $12.4 million, $8.4 million and $1.5 million, respectively, of internal costs to oil and gas properties, including $2.2 million, $1.4 million and $0.2 million, respectively, of qualifying share based compensation expense (see Note 11).

Acquisition_and_Divestitures_o

Acquisition and Divestitures of Oil and Gas Properties	12 Months Ended
	Dec. 31, 2014
Acquisition of Oil and Gas Properties
Acquisition of Oil and Gas Properties	7. Acquisition and Divestitures of Oil and Gas Properties
	Pine Prairie Disposition
	On March 5, 2014, the Company executed a 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 a purchase price of $170 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 revolving 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 other standard post-closing adjustments. Accordingly, 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 paid on or before December 31, 2015, the Company can elect to take the remaining portion in cash.
	At December 31, 2014, the Company had a receivable of $7.0 million included in "Other accounts receivable," which represented the additional cash the Company subsequently received in January 2015 under the exploration agreement with PetroQuest.
	Other Property Divestitures
	During the twelve months ended December 31, 2014, the Company received $1.4 million in cash for the sale of other properties.
	Anadarko Basin Acquisition—May 2013
	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 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 $700 million in aggregate principal amount of 9.25% senior unsecured notes due 2021, 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		$	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
	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.
	Eagle Property Acquisition—October 2012
	On October 1, 2012, the Company closed on the Eagle Property Acquisition. The assets acquired include certain interests in producing oil and natural gas assets and unevaluated leasehold acreage in Oklahoma and Kansas and related hedging instruments. The aggregate purchase price, before adjustments for expenses incurred and revenue received by Eagle from June 1, 2012 through the closing date and other customary post-closing purchase price adjustments, consisted of (a) $325 million in cash and (b) 325,000 shares of Series A Preferred Stock with an initial liquidation preference of $1,000/share. The Company funded the cash portion of the Eagle Property Acquisition purchase price with a portion of the net proceeds from the private placement (which also closed on October 1, 2012) of $600 million in aggregate principal amount of 10.75% senior unsecured notes due October 1, 2020.
	The transaction was accounted for using the acquisition method of accounting. The fair value of, and the allocation to, the assets acquired and liabilities assumed in the Eagle Property Acquisition has been finalized and is shown in the following table (in thousands):
			Eagle Property
			Acquisition
	Oil and gas properties
	Proved		$	419,549
	Unevaluated			244,236
	Commodity derivative contracts			8,453
	Total assets acquired		$	672,238
	Asset retirement obligations			2,662
	Deferred income tax liabilities			25,985
	Commodity derivative contracts			—
	Total liabilities assumed		$	28,647
	Net assets acquired		$	643,591
	Other Property Acquisitions
	On April 1, 2013, the Company exercised preference rights and acquired additional acreage and producing wells in its Gulf Coast region for $3.4 million.
	Actual and Pro Forma Impact of Acquisitions—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. Revenues attributable to the Eagle Property Acquisition, included in the Company's consolidated statements of operations for the year ended December 31, 2012 were $28.4 million.
	The following table presents unaudited pro forma information for the Company as if the Eagle Property Acquisition occurred on January 1, 2011 and the Anadarko Basin Acquisition had been completed on January 1, 2012 (in thousands, other than per share amounts):
			For the Year Ended
			December 31,
			2013(1)			2012(2)
	Revenues and other		$	539,562		$	490,241
	Net income (loss)			(340,400	)		(129,885	)
	Preferred stock dividends			(15,589	)		(26,000	)
	Loss attributable to common shareholders		$	(355,989	)	$	(155,885	)
	Net loss per common share—basic and diluted		$	(5.41	)	$	(2.60	)
	-1	Includes the effect of the Anadarko Basin Acquisition, as the Eagle Property Acquisition was included in the historical results for this period.
	-2	Includes the effect of the Eagle Property Acquisition and the Anadarko Basin Acquisition.
	The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Eagle Property Acquisition and 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 Eagle Property Acquisition been completed on January 1, 2011 and if the Anadarko Basin Acquisition had been completed on January 1, 2012. 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, 2014, acquisition and transaction costs are costs the Company has incurred primarily as a result of the Pine Prairie Disposition and include advisory, legal, accounting, valuation and other professional and consulting fees; and other general and administrative costs. For the year ended December 31, 2014, the Company recorded $4.1 million of such expenses.
	For the year ended December 31, 2013, acquisition and transaction costs are costs the Company has incurred as a result of the Anadarko Basin Acquisition and include advisory, legal, accounting, valuation and other professional and consulting fees; and general and administrative costs. For the year ended December 31, 2013, the Company recorded $11.8 million of such expenses.
	For the year ended December 31, 2012, acquisition and transaction costs are costs the Company has incurred as a result of the Eagle Property Acquisition and include finders' fees; advisory, legal, accounting, valuation and other professional and consulting fees; and acquisition related general and administrative costs. For the year ended December 31, 2012, the Company recorded $14.9 million of such expenses.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligations
Asset Retirement Obligations	8. Asset Retirement Obligations
	For the Company, asset retirement obligations 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 assets. Asset retirement obligations approximated $21.6 million and $26.3 million as of December 31, 2014 and 2013, respectively. The liability has been accreted to its present value as of December 31, 2014 and 2013. The Company evaluated its wells and determined a range of abandonment dates through 2079. At December 31, 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, 2014, 2013 and 2012, respectively (in thousands):
			Year ended December 31,
			2014			2013			2012
	Asset retirement obligations at beginning of year		$	26,308		$	15,245		$	7,627
	Liabilities incurred			996			2,535			3,044
	Liabilities assumed in Anadarko Basin Acquisition			—			6,296			—
	Liablities assumed in Eagle Property Acquisition			—			—			2,662
	Revisions			288			858			1,189
	Liabilities settled			(47	)		(61	)		—
	Liabilities eliminated through asset sale(1)			(7,652	)		—			—
	Current period accretion expense			1,706			1,435			723
	Asset retirement obligations at end of year		$	21,599		$	26,308		$	15,245
	-1	As a result of the Pine Prairie Disposition, AROs were reduced by approximately $7.7 million during the year ended December 31, 2014. See discussion of the Pine Prairie Disposition in Note 7.
	Revisions during the year ended December 31, 2014 were due primarily to an increase in estimated future abandonment costs based upon higher costs for oilfield services and materials in the Mississippian Lime and Anadarko areas. Revisions during the year ended December 31, 2013 were due to an increase in estimated future abandonment costs based upon higher oilfield service pricing. Revisions during the year ended December 31, 2012 were due to an increase in estimated future abandonment costs for our Gulf Coast wells based upon higher oilfield service pricing and a change in the Company's approach to site remediation based upon expected environmental and regulatory requirements.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Long-Term Debt
Long-Term Debt	9. Long-Term Debt
	The Company's long-term debt as of December 31, 2014 and 2013 is as follows:
		At December 31,
		2014		2013
		(in thousands)
	Revolving credit facility, due 2018	$	435,150	$	401,150
	Senior notes, due 2020		600,000		600,000
	Senior notes, due 2021		700,000		700,000
	Long-term debt	$	1,735,150	$	1,701,150
	Reserve-based Credit Facility
	As of December 31, 2014, the Company's credit facility consisted of a $750 million Credit Facility with a borrowing base supported by the Company's Mississippian Lime and Anadarko Basin oil and gas assets. On September 30, 2014, the Company entered into an Assignment and Borrowing Base Increase Agreement that increased the borrowing base from $475 million to $525 million. At December 31, 2014, the Company had drawn $435.2 million on the Credit Facility and had outstanding letters of credit obligations totaling $1.4 million.
	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. At December 31, 2014 and December 31, 2013, the weighted average interest rate was 2.8% and 2.5%, respectively.
	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 0.50% 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.
	Under the terms of the Credit Facility, the Company is required to repay the amount by which the principal balance of its outstanding loans and its letter of credit obligations exceed its redetermined borrowing base. 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.
	The Credit Facility, as amended, contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of net debt to EBITDA (i.e. leverage ratio) and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. The Company is required to maintain a leverage ratio of not more than 4.75 to 1.00 for the quarter ended December 31, 2014, and currently 4.00 to 1.00 for each quarter thereafter. The Credit Facility also limits the Company's ability to make any dividends, distributions or redemptions.
	As of December 31, 2014, the Company was in compliance with the current ratio and the ratio of debt to EBITDA covenants as set forth in the Credit Facility. The Company's current ratio at December 31, 2014 was 1.1 to 1.0. At December 31, 2014, the Company's leverage ratio was 3.7 to 1.0.
	In March 2015, the Company received a waiver related to the requirement that an unqualified auditors' opinion without an explanatory paragraph in relation to going concern accompany the 2014 financial statements.
	Based upon the recent amendments to the Credit Facility, the Company believes its carrying amount at December 31, 2014 approximates its fair value (Level 2) due to the variable nature of the applicable interest rate and current financing terms available to the Company.
	2020 Senior Notes
	On October 1, 2012, the Company issued $600 million in aggregate principal amount of 10.75% senior notes due 2020 (the "2020 Outstanding Notes") in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the "Securities Act"). On October 29, 2013, substantially all of the 2020 Outstanding Notes were exchanged for an equal principal amount of registered 10.75% senior subordinated notes due 2020 pursuant to an effective registration statement on Form S-4 filed on August 30, 2013 under the Securities Act (the "2020 Exchange Notes"). The 2020 Exchange Notes are identical to the 2020 Outstanding Notes except that the 2020 Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. As used in this Annual Report on Form 10-K, the term "2020 Senior Notes" refers to both the 2020 Outstanding Notes and the 2020 Exchange 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 2020 Senior Notes Indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advance loans to Midstates Sub.
	At any time prior to October 1, 2015, the Company may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes with the net proceeds of a public or private equity offering at a redemption price of 110.75% of the principal amount of the 2020 Senior Notes, plus any accrued and unpaid interest up to the redemption date. In addition, at any time before October 1, 2016, the Company may redeem all or a part of the 2020 Senior Notes at a redemption price equal to 100% of the principal amount of 2020 Senior Notes redeemed plus the Applicable Premium (as defined in the Indenture) at the redemption date, plus any accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any, up to, the redemption date. On or after October 1, 2016, the Company may redeem all or a part of the 2020 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the Indenture plus accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any, on the 2020 Senior Notes redeemed, up to, the redemption date.
	The Indenture contains 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.
	Upon the occurrence of certain change of control events, as defined in the 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% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.
	The estimated fair value of the 2020 Senior Notes was $327.0 million as of December 31, 2014 (Level 2 in the fair value measurement hierarchy due to the limited trading volume on the secondary market), based on quoted market prices for these same debt securities. The effective annual interest rate for the 2020 Senior Notes was approximately 11.1% for the years ended December 31, 2014 and 2013.
	2021 Senior Notes
	On May 31, 2013, the Company issued $700 million in aggregate principal amount of 9.25% senior notes due 2021 (the "2021 Outstanding Notes") in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act. On October 29, 2013, all of the 2021 Outstanding Notes were exchanged for an equal principal amount of registered 9.25% senior subordinated notes due 2021 pursuant to an effective registration statement on Form S-4 filed on August 30, 2013 under the Securities Act (the "2021 Exchange Notes"). The 2021 Exchange Notes are identical to the 2021 Outstanding Notes except that the 2021 Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. As used in this Annual Report on Form 10-K, the term "2021 Senior Notes" refers to both the 2021 Outstanding Notes and the 2021 Exchange Notes. The proceeds from the offering of $700 million (net of the initial purchasers' discount and related offering expenses) were used to fund the Anadarko Basin Acquisition and the related expenses, to pay the expenses related to an amendment to the Company's revolving credit facility, to repay $34.3 million in outstanding borrowings under the Company's Credit Facility, and for general corporate purposes.
	The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior 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 2021 Senior Notes indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advance loans to Midstates Sub.
	Prior to June 1, 2016, the Company may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes (less the amount of 2021 Senior Notes redeemed pursuant to the preceding paragraph) with the net proceeds of any Equity Offerings at a redemption price of 109.25% of the principal amount of the 2021 Senior Notes redeemed, plus any accrued and unpaid interest, if any, up to the redemption date. In addition, at any time before June 1, 2016, the Company may redeem all or a part of the 2021 Senior Notes at a redemption price equal to 100% of the principal amount of the 2021 Senior Notes redeemed plus the Applicable Premium (as defined in the Indenture) at the redemption date, plus any accrued and unpaid interest and Additional Interest (as defined in the 2021 Senior Notes Indenture), if any, up to, the redemption date. On or after October 1, 2016, the Company may redeem all or a part of the 2021 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2021 Senior Notes Indenture plus accrued and unpaid interest and Additional Interest (as defined in the 2021 Senior Notes Indenture), if any, on the 2021 Senior Notes redeemed, up to, the redemption date.
	The terms of the covenants and change in control provisions in the 2021 Senior Notes Indenture are substantially identical to those of the 2020 Senior Notes discussed above.
	The estimated fair value of the 2021 Senior Notes was $357.0 million as of December 31, 2014 (Level 2 in the fair value measurement hierarchy due to the limited trading volume on the secondary market), based on quoted market prices for these same debt securities. The effective annual interest rate for the 2021 Senior Notes was approximately 9.6% and 9.5% for the years ended December 31, 2014 and 2013, respectively.

Preferred_StockUnits

Preferred Stock/Units	12 Months Ended
	Dec. 31, 2014
Preferred Stock/Units
Preferred Stock/Units	10. Preferred Stock/Units
	Series A Preferred Stock
	At December 31, 2014, the Company had 325,000 shares of Series A Mandatorily Convertible Preferred Stock (the "Series A Preferred Stock") issued and outstanding. In connection with the Eagle Property Acquisition, on September 28, 2012, the Company designated 325,000 shares of Series A Preferred Stock with an initial liquidation preference of $1,000 per share and an 8% 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 are convertible after October 1, 2013, in whole but not in part and at the option of the holders of a majority of the outstanding shares of Series A Preferred Stock, into a number shares of the Company's common stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share and, if not previously converted, are mandatorily convertible at September 30, 2015 into shares of the Company's common stock at a conversion price no greater than $13.50 per share and no less than $11.00 per share, with the ultimate conversion price dependent upon the volume weighted average price of the Company's common stock during the 15 trading days immediately prior to September 30, 2015. The Series A Preferred Stock was issued on October 1, 2012.
	2014
	For the twelve months ended December 31, 2014, the $10.4 million Series A Preferred Stock dividend was based upon the estimated fair value of 2,659,792 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 $11.00 per share.
	The following table demonstrates the number of shares to be issued upon conversion through December 31, 2014 at the respective conversion rates based upon the current liquidation preference:
		Conversion at $13.50/share		Conversion at $11.00/share
	Number of Common Shares Issuable Upon Conversion		28,726,527		35,255,283
	2013
	For the twelve months ended December 31, 2013, the $15.6 million Series A Preferred Stock dividend was based upon the estimated fair value of 2,459,127 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 $11.00 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		325,000
	Share count as of December 31, 2012		325,000
	Share count as of December 31, 2013		325,000
	Share count as of December 31, 2014		325,000
	Mandatorily Redeemable Convertible Preferred Units
	In December 2011, Holdings LLC, FR Midstates Holdings LLC ("FR Midstates") and Midstates Petroleum Holdings, Inc. ("Petroleum Inc.") entered into an amended and restated limited liability company agreement, which was later amended in March 2012, to provide for the issuance of up to 65,000, or $65 million in aggregate value, of certain mandatorily redeemable convertible preferred units (the "Preferred Units") between December 15, 2011 and June 10, 2015. During the year ended December 31, 2012 , Holdings LLC issued 65,000 Preferred Units to FR Midstates for aggregate cash proceeds of $65.0 million. On April 26, 2012, the Company used $67.1 million of the proceeds from its initial public offering to redeem the Preferred Units in full, including interest and other charges. As such, at December 31, 2012, the Preferred Units are no longer outstanding. The Company recorded $2.1 million related to interest expense associated with these Preferred Units for the year ended December 31, 2012. There was no related interest expense for the years ended December 31, 2014 or 2013.

Equity_and_ShareBased_Compensa

Equity and Share-Based Compensation	12 Months Ended
	Dec. 31, 2014
Equity and Share-Based Compensation
Equity and Share-Based Compensation	11. Equity and Share-Based Compensation
	Common Shares
	At December 31, 2014, the Company had 70,491,732 and 69,957,055 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 27,600,000 shares of $0.01 par value common stock, which included 6,000,000 shares of stock sold by the selling shareholders and 3,600,000 shares of common stock sold by the selling stockholders pursuant to an option granted to the underwriters to cover over-allotments.
	After the corporate reorganization and the completion of its initial public offering discussed above, the Company is authorized to issue up to a total of 300,000,000 shares of its common stock with a par value of $0.01 per share, and 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.
	Share Activity
	The following table summarizes changes in the number of shares of common stock and treasury stock outstanding shares since January 1, 2012:
		Common			Treasury
		Stock			Stock
	Share count as of January 1, 2012		—			—
	Issuance of common stock in pre IPO reorganization		47,634,353			—
	Proceeds from the sale of common stock to public		18,000,000			—
	Issuance of preferred stock as consideration in Eagle Property Acquisition		—			—
	Share based compensation grants of restricted stock		1,029,509			—
	Forfeitures of restricted stock		(44,151	)		—
	Share count as of December 31, 2012		66,619,711			—
	Grants of restricted stock		2,840,241			—
	Forfeitures of restricted stock		(534,207	)		—
	Acquisition of treasury stock		—			(118,702	)
	Share count as of December 31, 2013		68,925,745			(118,702	)
	Grants of restricted stock		3,447,485			—
	Forfeitures of restricted stock		(1,881,498	)		—
	Acquisition of treasury stock		—			(415,975	)
	Share count as of December 31, 2014		70,491,732			(534,677	)
	Incentive Units.
	At December 31, 2014, 1,099 incentive units were issued and outstanding. In connection with the corporate reorganization that occurred immediately prior to our initial public offering, these 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 6,563,435 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 8,638,435 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, thereby strengthening their concern for the welfare of the Company and their desire to remain employed.
	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, 2014, a total of 8,638,435 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, 2014 the Company had 3,062,015 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, 2014 and 2013:
		Shares			Weighted
					Average
					Grant Date
					Fair Value
	Non-vested shares outstanding at December 31, 2012		985,358		$	12.61
	Granted		2,840,241			6.82
	Vested		(327,720	)		12.62
	Forfeited		(534,207	)		8.65
	Non-vested shares outstanding at December 31, 2013		2,963,672		$	7.78
	Granted		3,447,485		$	4.66
	Vested		(1,467,644	)		7.21
	Forfeited		(1,881,498	)		6.58
	Non-vested shares outstanding at December 31, 2014		3,062,015		$	5.28
	Unrecognized expense as of December 31, 2014 for all outstanding restricted stock awards, adjusted for estimated forfeitures, was $10.9 million and will be recognized over a weighted average period of 1.97 years.
	At December 31, 2014, 3,781,056 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, 2014, 2013 and 2012 of $8.6 million, $5.7 million and $2.5 million, respectively, all relate to the 2012 LTIP.
	During the quarter ended December 31, 2014, the Company announced that its Houston office would be closing, resulting in accelerated vesting of restricted stock awards in the period for those employees subject to a severance agreement. Of the $8.6 million in share-based compensation for the twelve months ended December 31, 2014, approximately $2.9 million was related to the accelerated vesting for employees impacted by the office closure.
	For the years ended December 31, 2014 and 2013, the Company capitalized $2.2 million and $1.4 million, respectively, of qualifying share-based compensation costs to oil and gas properties.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Taxes
Income Taxes	12. Income Taxes
	Prior to its corporate reorganization (See Note 1), the Company was a limited liability company and not subject to federal income tax or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company's equity holders were responsible for income tax on the Company's profits. In connection with the closing of the Company's initial public offering, the Company merged into a corporation and became subject to federal and state income taxes. The Company's book and tax basis in assets and liabilities differed at the time of the corporate reorganization due primarily to different cost recovery methodology utilized for book and tax purposes for the Company's oil and natural gas properties. In the quarter ended June 30, 2012, the Company recorded a one-time charge to income tax expense of $149.5 million to recognize this deferred tax liability related to the Company's change in tax status caused by the initial public offering.
	The Company incurred a tax net operating loss ("NOL") in the current year due principally to the ability to expense certain intangible drilling and development costs under current law. There is no tax refund available to the Company, nor is there any current federal income tax payable. In light of the impairment of oil and gas properties recorded in the year ended December 31, 2013, Management recorded a $45.7 million valuation allowance against the Company's federal and State of Louisiana NOLs for 2013. Management believed that the balance of the Company's NOLs were 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. During the year ended December 31, 2014, the Company recorded unrealized gains on commodity derivative contracts in the amount of $157.5 million, which resulted in pre-tax book income $123.3 million. This activity resulted in the full release of the federal valuation allowance of $39.9 million. The Company continues to report a net valuation allowance of $3.8 million for Louisiana state losses.
	The Company's NOLs were incurred in the tax years 2012 through 2014. U.S. federal and State of Oklahoma NOLs will generally be available for use through the tax years 2033 and 2034, respectively, and its State of Louisiana NOLs are generally available through 2023 and 2029, respectively. The State of Texas currently has no NOL carryover provision. The Company believes that Section 382 of the Internal Revenue Code of 1986, as amended, which relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three-year look back period, will not have an adverse effect on future NOL usage.
	On September 13, 2013, the US Treasury and IRS issued final Tangible Property Regulations ("TPR") under IRC Section 162 and IRC Section 263(a). The regulations are effective for tax years beginning on or after January 1, 2014. Due to these changes, certain portions may require an accounting method change on a retroactive basis, thus requiring a IRC Section 481(a) adjustment related to fixed and real asset deferred taxes. The accounting rules under ASC 740 treat the release of the regulations as a change in tax law as of the date of issuance and require the Company to determine whether there will be an impact on its financial statements for the period ended December 31, 2014. Any such impact of the final tangible property regulations would affect temporary deferred taxes only and result in a balance sheet reclassification within non-current deferred taxes. The Company has analyzed the expected impact of the TPR on the Company and concluded that the expected impact is minimal. The Company will continue to monitor the impact of any future changes to the TPR on the Company prospectively.
	As of December 31, 2014, the Company has not recorded a reserve for any uncertain tax positions. No federal income tax payments are expected in the upcoming four quarterly reporting periods. The Company expects $0.6 million in Texas Margins Tax payments in 2015.
			Years Ended December, 31
			2014			2013			2012
			(in thousands)
	Current
	United States		$	—		$	—		$	—
	State			809			—			—
	Total current			809			—			—
	Deferred
	United States			3,863			(130,906	)		137,496
	State			1,723			(15,623	)		20,390
	Total deferred			5,586			(146,529	)		157,886
	Total income tax provision (benefit)		$	6,395		$	(146,529	)	$	157,886
	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 (in thousands):
			Years Ended December, 31
			2014			2013			2012
			(in thousands)
	Income before taxes		$	123,324		$	(490,514	)	$	7,789
	Statutory rate			35	%		35	%		35	%
	Income tax expense computed at statutory rate			43,164			(171,680	)		2,726
	Reconciling items:
	Non-deductible pre-IPO loss			—			—			4,561
	State income taxes, net of federal benefit			4,398			(10,886	)		1,053
	Change in valuation allowance			(42,134	)		45,688			—
	Change in state rate			(414	)		(10,500	)		—
	Other, net			1,381			849			57
	Change in tax status(1)			—			—			149,489
	Total income tax provision (benefit)		$	6,395		$	(146,529	)	$	157,886
	-1	The change in tax status for the year ended December 31, 2012 is split between federal of $130.2 million and state of $19.3 million.
	Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of our deferred taxes are detailed in the table below (in thousands):
			Years Ended
			December, 31
			2014			2013
	Deferred tax assets—current
	Derivative instruments and other		$	—		$	15,581
	Less valuation allowance			—			(3,744	)
	Total deferred tax assets, current		$	—		$	11,837
	Deferred tax assets—noncurrent
	US tax loss carryforwards			75,604			151,872
	State tax loss carryforwards			7,122			14,154
	Employee benefit plans			2,193			1,539
	Less valuation allowance			(3,826	)		(41,944	)
	Total deferred tax assets, noncurrent		$	81,093		$	125,621
	Deferred tax liabilities—current
	Derivative instruments and other			44,862			—
	Total deferred tax liabilities—current		$	44,862		$	—
	Deferred tax liabilities—noncurrent
	Oil and gas properties and equipment			45,272			140,912
	Total deferred tax liabilities, noncurrent		$	45,272		$	140,912
	Reflected in the accompanying balance sheet as:
	Net deferred tax asset, current		$	—		$	11,837
	Net deferred tax liability, current		$	44,862		$	—
	Net deferred tax asset, noncurrent		$	35,821		$	—
	Net deferred tax liability, noncurrent		$	—		$	15,291

Earnings_Loss_Per_Share

Earnings (Loss) Per Share	12 Months Ended
	Dec. 31, 2014
Earnings (Loss) Per Share
Earnings (Loss) Per Share	13. Earnings (Loss) Per Share
	The Company's Series A Preferred Stock issued in connection with the Eagle Property Acquisition has 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, is 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 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 (in thousands, except per share amounts) 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
			2014			2013			2012
	Net income (loss)		$	116,929		$	(343,985	)	$	(150,097	)
	Preferred Dividend(1)			(10,378	)		(15,589	)		(6,500	)
	Net income (loss) attributable to shareholders		$	106,551		$	(359,574	)	$	(156,597	)
	Participating securities—Series A Preferred Stock			(35,696	)		—			—
	Participating securities—Non-vested Restricted Stock			(3,584	)		—			—
	Net income (loss) attributable to common shareholders		$	67,271		$	(359,574	)	$	(156,597	)
	Weighted average shares outstanding			66,440			65,766			59,979
	Basic and diluted net income (loss) per share		$	1.01		$	(5.47	)	$	(2.61	)
	-1	Calculation of the preferred stock dividend is discussed in Note 10.
	-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, 2014
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 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 attempts to limit the amount of credit exposure to any one financial institution or company.
	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, 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. For the year ended December 31, 2012, three purchasers accounted for 41%, 32% and 10%, 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, 2014, four purchasers accounted for approximately 25%, 23%, 15% and 13% respectively, of the accounts receivable balance. At December 31, 2013, three purchasers accounted for approximately 31%, 16%, 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.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies
Commitments and Contingencies	15. Commitments and Contingencies
	Contractual Obligations
	At December 31, 2014, contractual obligations for drilling contracts, long-term operating leases, seismic contracts and other contracts are as follows (in thousands):
			Total		2015(1)		2016		2017		2018		2019 and
													beyond
	Drilling contracts		$	16,698	$	15,819	$	879	$	—	$	—	$	—
	Non-cancellable office lease commitments(2)			9,320		1,857		1,877		1,941		1,471		2,174
	Seismic contracts			3,192		3,192		—		—		—		—
	Net minimum commitments		$	29,210	$	20,868	$	2,756	$	1,941	$	1,471	$	2,174
	-1	In addition to the $20.9 million of minimum commitments noted above, the Company also has approximately $130 million of interest payments due on the senior notes during the year ended December 31, 2015, for estimated total obligations of approximately $150 million.
	-2	During the quarter ended December 31, 2014, the Company announced plans to relocate the headquarters from Houston, Texas to Tulsa, Oklahoma. At December 31, 2014, the Company still leased space in Houston (contractually through 2018) and of the $9.3 million total in office lease commitments, approximately $3.4 million related to the Houston leases.
	For the years ended December 31, 2014, 2013 and 2012, the Company expensed $2.3 million, $1.7 million and $1.1 million, respectively, for office rent.
	In addition to the commitments noted in the above table, the Company is party to a gas transportation, 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 the Company does not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLs, the Company 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). The NGL volume commitments range from 2,800 Bbls to 5,780 Bbls per day for each monthly accounting period over the remaining term of the contract. Additionally, the Company is obligated to deliver a total of 38,100,000 MMBtu and 76,200,000 MMBtu during the first 30 months and 60 months of the contract, respectively. During the first 30 months, any shortfall in delivered volumes would result in a payment to the counterparty equal to the shortfall amount multiplied by a fee of approximately $0.36 per MMBtu. During the first 60 months, any shortfall in delivered volumes would result in a payment to the counterparty equal to the shortfall amount multiplied by a fee of approximately $0.36 per MMBtu, provided that the Company would receive volumetric credit for any deficiency payment made after the initial 30 months. The Company is currently delivering at least the minimum volumes required under these contractual provisions and does not expect to incur any future volumetric shortfall payments during the term of this contract.
	Commitments related to ARO's are not included in the table above; see Note 8 for discussion of those commitments.
	Litigation
	The Company is involved in disputes or legal actions arising in the ordinary course of its business. The Company may not be able to predict the timing or outcome of these or future claims and proceedings with certainty, and an unfavorable resolution of one or more of such matters could have a material adverse effect on our financial condition, results of operations or cash flows. Currently, it is not party to any legal proceedings that the Company believes, individually or in the aggregate, are reasonably expected to have a material adverse effect on its financial position, results of operations, or cash flows.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2014
Subsequent Events
Subsequent Events	16. Subsequent Events
	Sale of Dequincy Assets
	The Company executed a PSA in March 2015 for the sale of its Dequincy assets, its only remaining producing properties in Louisiana, for total consideration of $44 million (subject to customary purchase price adjustments). The PSA includes the ownership interests in developed and undeveloped acreage in the Dequincy area.; the transaction does not include our acreage and interests in the Fleetwood area of Louisiana. The net proceeds from the sale will be used to pay down a portion of the outstanding borrowings under the Company revolving credit facility and for general corporate purposes. The transaction has an effective date of March 1, 2015 and is expected to close on or before April 30, 2015, subject to customary closing conditions.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
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, 2014 include the results of the Pine Prairie field from January 1, 2014 through May 1, 2014, the date of disposition. The consolidated financial statements as of and for the year ended December 31, 2013 include the results from the Anadarko Basin Acquisition beginning May 31, 2013. The consolidated financial statements as of and for the year ended December 31, 2012 include the results from the Eagle Property Acquisition beginning October 1, 2012.
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. Actual results could differ from those estimates.
	Significant estimates include, but are not limited to, the amount of recoverable oil and natural gas reserves; future cash flows from oil and natural gas properties; 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.
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 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. 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, 2014 and 2013, 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). Based upon recent amendments to the Company's Credit Facility, the Company believes the carrying amount of the related floating-rate debt approximates fair value due to the variable nature of the interest rate and the current secured financing terms available to the Company. See fair value discussion of Senior Notes and Series A Preferred Shares issued in October 2012 in Notes 9 and 10, respectively. 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 currently 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, 2014 and 2013, other noncurrent assets consisted of the following:
		At December 31,
		2014		2013
		(in thousands)
	Deferred financing costs	$	37,807	$	44,706
	Field equipment inventory		5,713		9,682
	Other		211		209
	Other noncurrent assets	$	43,731	$	54,597
	During the year ended December 31, 2014, the Company has recorded approximately $5.9 million in adjustments to field equipment inventory, either as a result of physical inventory counts, disposals or market adjustments; this is offset by additional inventory added during the period of approximately $1.8 million. For the years ended December 31, 2014 and 2013, the Company recorded $4.1 million and $0.6 million, respectively, of losses on 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, the cost 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 that 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. Based on current pricing and current drilling plans, we impaired the remaining Anadarko Basin unevaluated property to the full cost pool during the fourth quarter of 2014.
	Oil and Gas Reserves
	Proved oil, NGLs and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (FASB), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements.
	Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company depletes its oil and gas properties using the units-of-production method. Capitalized costs of oil and natural gas properties subject to amortization are depleted over proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
	Impairment of Oil and Gas Properties/Ceiling Test
	The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit (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 price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations. For the year ended December 31, 2014, an impairment of oil and gas properties of $83.5 million, after tax, was recorded. For the year ended December 31, 2013, capitalized costs exceeded the ceiling and an impairment of oil and gas properties of $319.6 million, after tax, was recorded.
	The most significant factors affecting the impairment related to the transfer of unevaluated property costs to the full cost pool and negative reserve revisions in certain areas.
	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 to previously unproved acreage 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 up on our lack of plans for further evaluation or development of those leases in the current commodity price environment.
	During 2013, the Company transferred $61.2 million of Gulf Coast unevaluated property costs to the full cost pool based upon our lack of future plans for further evaluation or development of those leases and $168.4 million of Mississippian unevaluated property costs attributable to leases that expired during 2013 or that were assigned to proved reserves as a result of the Company's drilling activities. The Company also transferred $89.6 million of Anadarko Basin unevaluated costs due primarily to lease expirations and development drilling. The negative reserve revisions in our Gulf Coast area were mainly attributable to variability in well performance, our decision during the second quarter of 2013 to halt further development in our West Gordon field and unfavorable cost revisions. See Note 6.
	Depreciation, Depletion, and Amortization (DD&A)
	DD&A 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 DD&A, 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 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. The Company paid cash interest of $141.9 million, $104.3 million, and $7.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	Other Property and Equipment
	Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are 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, 2014 and 2013, accrued liabilities consisted of the following:
		At December 31,
		2014		2013
		(in thousands)
	Accrued oil and gas capital expenditures	$	76,398	$	87,202
	Accrued revenue and royalty distributions		51,292		64,370
	Accrued lease operating and workover expense		10,113		8,279
	Accrued interest		21,521		21,341
	Accrued taxes		4,226		4,386
	Other		20,281		18,803
	Accrued liabilities	$	183,831	$	204,381
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 acquiring or drilling 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 depreciated 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 in the full cost pool. See Note 8.
Share-Based Compensation	Share-Based Compensation
	We measure share-based compensation cost at fair value and generally recognize the corresponding compensation expense on a straight-line basis over the service period during which awards are expected to vest. We include share-based compensation expense, net of amounts capitalized to oil and gas properties, in "General and administrative expense" in our consolidated statements of operations. See Note 11.
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 and gas revenues, whereby revenue is recognized for all oil 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, 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 2014 relate to the Pine Prairie Disposition, costs incurred in 2013 relate to the Anadarko Basis Acquisition, and costs incurred in 2012 relate to the Eagle Property Acquisition. See Note 7.
Income Taxes	Income Taxes
	Income taxes are provided 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.
	Prior to its corporate reorganization (See Note 1), the Company was a limited liability company and not subject to federal income tax or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company's equity holders were responsible for income tax on the Company's profits. In connection with the closing of the Company's initial public offering, the Company merged into a corporation and became subject to federal and state income taxes. The Company's book and tax basis in assets and liabilities differed at the time of the corporate reorganization due primarily to different cost recovery periods utilized for book and tax purposes for the Company's oil and natural gas properties. See Note 12.
Earnings (Loss) Per Share	Earnings (Loss) Per Share
	Basic earnings (loss) per common share is calculated by dividing net income 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 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 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.
Recent Accounting Pronouncements	Recent Accounting Pronouncements
	The Company reviewed recently issued accounting pronouncements that became effective during the twelve months ended December 31, 2014, and determined that none would have a material impact on the Company's consolidated financial statements with the exception of ASU 2014-09, "Revenue from Contracts with Customers "and ASU 2014-15, "Presentation of Financial Statements—Going Concern," (both effective for annual reporting periods beginning after December 15, 2016), which the Company is still evaluating.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Summary of Significant Accounting Policies
Schedule of other noncurrent assets
		At December 31,
		2014		2013
		(in thousands)
	Deferred financing costs	$	37,807	$	44,706
	Field equipment inventory		5,713		9,682
	Other		211		209
	Other noncurrent assets	$	43,731	$	54,597
Schedule of Accrued Liabilities
		At December 31,
		2014		2013
		(in thousands)
	Accrued oil and gas capital expenditures	$	76,398	$	87,202
	Accrued revenue and royalty distributions		51,292		64,370
	Accrued lease operating and workover expense		10,113		8,279
	Accrued interest		21,521		21,341
	Accrued taxes		4,226		4,386
	Other		20,281		18,803
	Accrued liabilities	$	183,831	$	204,381

Fair_Value_Measurements_of_Fin1

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
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		Significant Other		Significant		Total
		Active Markets		Observable Inputs		Unobservable
		(Level 1)		(Level 2)		Inputs
						(Level 3)
		(in thousands)
	Assets:
	Commodity derivative oil swaps	$	—	$	106,450	$	—	$	106,450
	Commodity derivative gas swaps		—		20,259		—		20,259
	Total assets	$	—	$	126,709	$	—	$	126,709
	Liabilities:
	Commodity derivative oil swaps	$	—	$	—	$	—	$	—
	Commodity derivative NGL swaps		—		—		—		—
	Commodity derivative gas swaps		—		—		—		—
	Commodity derivative oil collars		—		—		—		—
	Commodity derivative gas collars		—		—		—		—
	Total liabilities	$	—	$	—	$	—	$	—
		Fair Value Measurements at December 31, 2013
		Quoted Prices in		Significant Other		Significant		Total
		Active Markets		Observable Inputs		Unobservable
		(Level 1)		(Level 2)		Inputs
						(Level 3)
		(in thousands)
	Assets:
	Commodity derivative NGL swaps	$	—	$	469	$	—	$	469
	Commodity derivative gas swaps		—		488		—		488
	Commodity derivative oil collars		—		64		—		64
	Commodity derivative gas collars		—		751		—		751
	Commodity derivative differential swaps		—		806		—		806
	Total assets	$	—	$	2,578	$	—	$	2,578
	Liabilities:
	Commodity derivative oil swaps	$	—	$	32,209	$	—	$	32,209
	Commodity derivative NGL swaps		—		74		—		74
	Commodity derivative gas swaps		—		809		—		809
	Commodity derivative oil collars		—		272		—		272
	Commodity derivative gas collars		—		26		—		26
	Total liabilities	$	—	$	33,390	$	—	$	33,390

Risk_Management_and_Derivative1

Risk Management and Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Risk Management and Derivative Instruments
Schedule of the entity's open commodity positions	As of December 31, 2014, the Company had the following open commodity positions:
			Hedged			Weighted-Average
			Volume			Fixed Price
	Oil (Bbls):
	WTI Swaps—2015			3,276,000		$	88.72
	Natural Gas (MMBtu):
	Swaps—2015(1)			20,050,000		$	4.15
	-1	Includes 2,170,000 MMBtu in natural gas swaps that priced during the period, but had not cash settled as of December 31, 2014.
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 sheets	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, 2014 and 2013, respectively (in thousands):
		Type		Balance Sheet Location(1)		December 31,			December 31,
						2014			2013
		Oil Swaps		Derivative financial instruments—Current Assets		$	106,450		$	—
		Oil Swaps		Derivative financial instruments—Current Liabilities			—			(28,871	)
		Oil Swaps		Derivative financial instruments—Non-Current Liabilities			—			(3,338	)
		NGL Swaps		Derivative financial instruments—Current Assets			—			469
		NGL Swaps		Derivative financial instruments—Current Liabilities			—			(74	)
		Gas Swaps		Derivative financial instruments—Current Assets			20,259			469
		Gas Swaps		Derivative financial instruments—Non-Current Assets			—			19
		Gas Swaps		Derivative financial instruments—Current Liabilities			—			(496	)
		Gas Swaps		Derivative financial instruments—Non-Current Liabilities			—			(313	)
		Oil Collars		Derivative financial instruments—Current Assets			—			64
		Oil Collars		Derivative financial instruments—Current Liabilities			—			(272	)
		Gas Collars		Derivative financial instruments—Current Assets			—			751
		Gas Collars		Derivative financial instruments—Current Liabilities			—			(26	)
		Basis Differential Swaps		Derivative financial instruments—Current Assets			—			806
		Total derivative fair value at period end				$	126,709		$	(30,812	)
	-1	The fair values of commodity derivative instruments reported in the Company's consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table summarizes the location and fair value amounts of all derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets at December 31, 2014 and 2013, respectively (in thousands):
					December 31, 2014
	Not Designated as ASC 815 Hedges:		Balance Sheet Classification		Gross Recognized			Gross Amounts			Net Recognized
					Assets/			Offset			Fair Value Assets/
					Liabilities						Liabilities
	Derivative assets:
	Commodity contracts		Derivative financial instruments—current		$	126,709		$	—		$	126,709
	Commodity contracts		Derivative financial instruments—noncurrent			—			—			—
					$	126,709		$	—		$	126,709
	Derivative liabilities:
	Commodity contracts		Derivative financial instruments—current		$	—		$	—		$	—
	Commodity contracts		Derivative financial instruments—noncurrent			—			—			—
					$	—		$	—		$	—
					December 31, 2013
	Not Designated as ASC 815 Hedges:		Balance Sheet		Gross Recognized			Gross Amounts			Net Recognized
			Classification		Assets/			Offset			Fair Value Assets/
					Liabilities						Liabilities
	Derivative assets:
	Commodity contracts		Derivative financial instruments—current		$	2,559		$	1,859		$	700
	Commodity contracts		Derivative financial instruments—noncurrent			19			—			19
					$	2,578		$	1,859		$	719
	Derivative liabilities:
	Commodity contracts		Derivative financial instruments—current		$	29,739		$	1,859		$	27,880
	Commodity contracts		Derivative financial instruments—noncurrent			3,651			—			3,651
					$	33,390		$	1,859		$	31,531
Schedule of net losses and unrealized net (losses) gains recorded by the Company related to the change in fair value of the derivative instruments in losses on commodity derivative contracts - net for the periods
			Years Ended December 31,
			2014			2013			2012
			(in thousands)
	Realized net losses		$	(18,332	)	$	(17,585	)	$	(15,825	)
	Unrealized net gains (losses)			157,521			(26,699	)		4,667
	Gains (losses) on commodity derivative contracts—net		$	139,189		$	(44,284	)	$	(11,158	)

Property_and_Equipment_Tables

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property and Equipment
Schedule of property and equipment	The Company's property and equipment as of December 31, 2014 and 2013 was as follows (in thousands):
		December 31,			December 31,
		2014			2013
		(in thousands)
	Oil and gas properties, on the basis of full-cost accounting:
	Proved properties	$	3,398,146		$	2,817,062
	Unevaluated properties		44,535			243,599
	Other property and equipment		13,454			11,113
	Less accumulated depreciation, depletion, amortization and impairment		(1,333,019	)		(976,880	)
	Net property and equipment	$	2,123,116		$	2,094,894

Acquisition_and_Divestitures_o1

Acquisition and Divestitures of Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2014
Acquisition of Oil and Gas Properties
Schedule of unaudited pro forma information as of the acquisition	The following table presents unaudited pro forma information for the Company as if the Eagle Property Acquisition occurred on January 1, 2011 and the Anadarko Basin Acquisition had been completed on January 1, 2012 (in thousands, other than per share amounts):
			For the Year Ended
			December 31,
			2013(1)			2012(2)
	Revenues and other		$	539,562		$	490,241
	Net income (loss)			(340,400	)		(129,885	)
	Preferred stock dividends			(15,589	)		(26,000	)
	Loss attributable to common shareholders		$	(355,989	)	$	(155,885	)
	Net loss per common share—basic and diluted		$	(5.41	)	$	(2.60	)
	-1	Includes the effect of the Anadarko Basin Acquisition, as the Eagle Property Acquisition was included in the historical results for this period.
	-2	Includes the effect of the Eagle Property Acquisition and the Anadarko Basin Acquisition.
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		$	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
Eagle Property Acquisition
Acquisition of Oil and Gas Properties
Schedule of fair value of the assets acquired and liabilities assumed in acquisition	The transaction was accounted for using the acquisition method of accounting. The fair value of, and the allocation to, the assets acquired and liabilities assumed in the Eagle Property Acquisition has been finalized and is shown in the following table (in thousands):
			Eagle Property
			Acquisition
	Oil and gas properties
	Proved		$	419,549
	Unevaluated			244,236
	Commodity derivative contracts			8,453
	Total assets acquired		$	672,238
	Asset retirement obligations			2,662
	Deferred income tax liabilities			25,985
	Commodity derivative contracts			—
	Total liabilities assumed		$	28,647
	Net assets acquired		$	643,591

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012, respectively (in thousands):
			Year ended December 31,
			2014			2013			2012
	Asset retirement obligations at beginning of year		$	26,308		$	15,245		$	7,627
	Liabilities incurred			996			2,535			3,044
	Liabilities assumed in Anadarko Basin Acquisition			—			6,296			—
	Liablities assumed in Eagle Property Acquisition			—			—			2,662
	Revisions			288			858			1,189
	Liabilities settled			(47	)		(61	)		—
	Liabilities eliminated through asset sale(1)			(7,652	)		—			—
	Current period accretion expense			1,706			1,435			723
	Asset retirement obligations at end of year		$	21,599		$	26,308		$	15,245
	-1	As a result of the Pine Prairie Disposition, AROs were reduced by approximately $7.7 million during the year ended December 31, 2014. See discussion of the Pine Prairie Disposition in Note 7.

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Long-Term Debt
Schedule of the company's long term debt
		At December 31,
		2014		2013
		(in thousands)
	Revolving credit facility, due 2018	$	435,150	$	401,150
	Senior notes, due 2020		600,000		600,000
	Senior notes, due 2021		700,000		700,000
	Long-term debt	$	1,735,150	$	1,701,150

Preferred_StockUnits_Tables

Preferred Stock/Units (Tables)	12 Months Ended
	Dec. 31, 2014
Preferred Stock/Units
Schedule of number of shares to be issued upon conversion at respective conversion rates based upon the current liquidation preference	The following table demonstrates the number of shares to be issued upon conversion through December 31, 2014 at the respective conversion rates based upon the current liquidation preference:
		Conversion at $13.50/share		Conversion at $11.00/share
	Number of Common Shares Issuable Upon Conversion		28,726,527		35,255,283
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		325,000
	Share count as of December 31, 2012		325,000
	Share count as of December 31, 2013		325,000
	Share count as of December 31, 2014		325,000

Equity_and_ShareBased_Compensa1

Equity and Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Equity and Share-Based Compensation
Summary of changes in the number of outstanding shares
		Common			Treasury
		Stock			Stock
	Share count as of January 1, 2012		—			—
	Issuance of common stock in pre IPO reorganization		47,634,353			—
	Proceeds from the sale of common stock to public		18,000,000			—
	Issuance of preferred stock as consideration in Eagle Property Acquisition		—			—
	Share based compensation grants of restricted stock		1,029,509			—
	Forfeitures of restricted stock		(44,151	)		—
	Share count as of December 31, 2012		66,619,711			—
	Grants of restricted stock		2,840,241			—
	Forfeitures of restricted stock		(534,207	)		—
	Acquisition of treasury stock		—			(118,702	)
	Share count as of December 31, 2013		68,925,745			(118,702	)
	Grants of restricted stock		3,447,485			—
	Forfeitures of restricted stock		(1,881,498	)		—
	Acquisition of treasury stock		—			(415,975	)
	Share count as of December 31, 2014		70,491,732			(534,677	)
Summary of Company's non-vested share award activity
		Shares			Weighted
					Average
					Grant Date
					Fair Value
	Non-vested shares outstanding at December 31, 2012		985,358		$	12.61
	Granted		2,840,241			6.82
	Vested		(327,720	)		12.62
	Forfeited		(534,207	)		8.65
	Non-vested shares outstanding at December 31, 2013		2,963,672		$	7.78
	Granted		3,447,485		$	4.66
	Vested		(1,467,644	)		7.21
	Forfeited		(1,881,498	)		6.58
	Non-vested shares outstanding at December 31, 2014		3,062,015		$	5.28

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Taxes
Schedule of income tax provision
			Years Ended December, 31
			2014			2013			2012
			(in thousands)
	Current
	United States		$	—		$	—		$	—
	State			809			—			—
	Total current			809			—			—
	Deferred
	United States			3,863			(130,906	)		137,496
	State			1,723			(15,623	)		20,390
	Total deferred			5,586			(146,529	)		157,886
	Total income tax provision (benefit)		$	6,395		$	(146,529	)	$	157,886
Schedule of difference between the Company's estimated income tax from amount derived by applying statutory federal rate to pretax income	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 (in thousands):
			Years Ended December, 31
			2014			2013			2012
			(in thousands)
	Income before taxes		$	123,324		$	(490,514	)	$	7,789
	Statutory rate			35	%		35	%		35	%
	Income tax expense computed at statutory rate			43,164			(171,680	)		2,726
	Reconciling items:
	Non-deductible pre-IPO loss			—			—			4,561
	State income taxes, net of federal benefit			4,398			(10,886	)		1,053
	Change in valuation allowance			(42,134	)		45,688			—
	Change in state rate			(414	)		(10,500	)		—
	Other, net			1,381			849			57
	Change in tax status(1)			—			—			149,489
	Total income tax provision (benefit)		$	6,395		$	(146,529	)	$	157,886
	-1	The change in tax status for the year ended December 31, 2012 is split between federal of $130.2 million and state of $19.3 million.
Schedule of components of the entity's deferred taxes	The components of our deferred taxes are detailed in the table below (in thousands):
			Years Ended
			December, 31
			2014			2013
	Deferred tax assets—current
	Derivative instruments and other		$	—		$	15,581
	Less valuation allowance			—			(3,744	)
	Total deferred tax assets, current		$	—		$	11,837
	Deferred tax assets—noncurrent
	US tax loss carryforwards			75,604			151,872
	State tax loss carryforwards			7,122			14,154
	Employee benefit plans			2,193			1,539
	Less valuation allowance			(3,826	)		(41,944	)
	Total deferred tax assets, noncurrent		$	81,093		$	125,621
	Deferred tax liabilities—current
	Derivative instruments and other			44,862			—
	Total deferred tax liabilities—current		$	44,862		$	—
	Deferred tax liabilities—noncurrent
	Oil and gas properties and equipment			45,272			140,912
	Total deferred tax liabilities, noncurrent		$	45,272		$	140,912
	Reflected in the accompanying balance sheet as:
	Net deferred tax asset, current		$	—		$	11,837
	Net deferred tax liability, current		$	44,862		$	—
	Net deferred tax asset, noncurrent		$	35,821		$	—
	Net deferred tax liability, noncurrent		$	—		$	15,291

Earnings_Loss_Per_Share_Tables

Earnings (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings (Loss) Per Share
Schedule of reconciliation of net income (loss) to preferred shareholders, common shareholders, and non-vested restricted shareholders for purposes of computing net income (loss) per share	The following table (in thousands, except per share amounts) 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
			2014			2013			2012
	Net income (loss)		$	116,929		$	(343,985	)	$	(150,097	)
	Preferred Dividend(1)			(10,378	)		(15,589	)		(6,500	)
	Net income (loss) attributable to shareholders		$	106,551		$	(359,574	)	$	(156,597	)
	Participating securities—Series A Preferred Stock			(35,696	)		—			—
	Participating securities—Non-vested Restricted Stock			(3,584	)		—			—
	Net income (loss) attributable to common shareholders		$	67,271		$	(359,574	)	$	(156,597	)
	Weighted average shares outstanding			66,440			65,766			59,979
	Basic and diluted net income (loss) per share		$	1.01		$	(5.47	)	$	(2.61	)
	-1	Calculation of the preferred stock dividend is discussed in Note 10.
	-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, 2014
Commitments and Contingencies
Schedule of contractual obligations for drilling contracts, long-term operating leases and seismic contracts	At December 31, 2014, contractual obligations for drilling contracts, long-term operating leases, seismic contracts and other contracts are as follows (in thousands):
			Total		2015(1)		2016		2017		2018		2019 and
													beyond
	Drilling contracts		$	16,698	$	15,819	$	879	$	—	$	—	$	—
	Non-cancellable office lease commitments(2)			9,320		1,857		1,877		1,941		1,471		2,174
	Seismic contracts			3,192		3,192		—		—		—		—
	Net minimum commitments		$	29,210	$	20,868	$	2,756	$	1,941	$	1,471	$	2,174
	-1	In addition to the $20.9 million of minimum commitments noted above, the Company also has approximately $130 million of interest payments due on the senior notes during the year ended December 31, 2015, for estimated total obligations of approximately $150 million.
	-2	During the quarter ended December 31, 2014, the Company announced plans to relocate the headquarters from Houston, Texas to Tulsa, Oklahoma. At December 31, 2014, the Company still leased space in Houston (contractually through 2018) and of the $9.3 million total in office lease commitments, approximately $3.4 million related to the Houston leases.

Organization_and_Business_Deta

Organization and Business (Details) (USD $)	12 Months Ended	0 Months Ended
	Dec. 31, 2012	Apr. 25, 2012	Dec. 31, 2014	Dec. 31, 2013
Stock issuances and other information
Common stock, par value (in dollars per share)			$0.01	$0.01
Underwriting discounts and commissions	$6,400,000
Proceeds from sale of common stock, net of initial public offering expenses of $6.4 million	213,569,000
Initial public offering
Stock issuances and other information
Initial public offering, aggregate number of shares of common stock sold		27,600,000
Common stock, par value (in dollars per share)		$0.01
Number of shares of stock sold by the selling shareholders		6,000,000
Number of shares of sold by the selling shareholders pursuant to an option granted to the underwriters to cover over-allotments		3,600,000
Public offering price (in dollars per share)		$13
Proceeds from initial public offering		358,800,000
Underwriting discounts and commissions		21,500,000
Net proceeds to selling stockholders		117,300,000
Net proceeds from registration and sale		220,000,000
Number of shares of common stock sold		18,000,000
Proceeds from sale of common stock, net of initial public offering expenses of $6.4 million		213,600,000
Amount of net proceeds from initial public offering used to redeem convertible preferred units, including interest and other charges		67,100,000
Amount of borrowings repaid under the facility		99,000,000
Amount of net proceeds from common stock offering used to fund the execution of company's growth strategy through its drilling program		$47,500,000
Number of shares sold by the selling stockholders		9,600,000

Organization_and_Business_Deta1

Organization and Business (Details 2) (First Reserve or its affiliates)	Apr. 25, 2012
First Reserve or its affiliates
Minority ownership interest
Ownership interest percentage	41.40%

Organization_and_Business_Deta2

Organization and Business (Details 3) (USD $)	0 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Oct. 01, 2012	31-May-13	1-May-14	Mar. 05, 2014
	segment
Segment information
Number of reportable segments	1
Pine Prairie Disposition
Acquisition information
Purchase price of subject to standard post-closing adjustments received in cash				$147.70	$170
2020 Senior Notes
Acquisition information
Aggregate principal amount borrowed		600
Interest rate (as a percent)		10.75%
2021 Senior Notes
Acquisition information
Aggregate principal amount borrowed			700
Interest rate (as a percent)			9.25%
Eagle Property Acquisition
Acquisition information
Purchase price, cash		325
Eagle Property Acquisition | 2020 Senior Notes
Acquisition information
Aggregate principal amount borrowed		600
Interest rate (as a percent)		10.75%
Eagle Property Acquisition | Mandatorily redeemable convertible preferred units
Acquisition information
Purchase price, preferred shares		325,000
Preferred stock, liquidation value (in dollars per share)		$1,000
Anadarko Basin Acquisition | 2021 Senior Notes | Panther Energy LLC
Acquisition information
Purchase price, cash			618
Aggregate principal amount borrowed			$700
Interest rate (as a percent)			9.25%

Liquidity_and_Capital_Resource1

Liquidity and Capital Resources (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Available cash	$11,557,000	$33,163,000	$18,878,000	$7,344,000
Contractual obligations during the next twelve months	150,000,000
Interest payments on the senior notes and other operating expenses	130,000,000
Financial Ratio Covenants
Net consolidated indebtedness to EBITDA ratio	3.7
Current Ratio	1.1
Cross Default Provisions
Minimum effective borrowing base under credit facility	5.00%
Minimum indebtedness of senior notes including principal amount	50,000,000
Credit Facility
Availability under the facility	90,000,000
Borrowing Base Redetermination
Period for commencement of repayment of equal successive monthly payments following the administrative agent's notice regarding borrowing base reduction	30 days
Period during which Company may request additional redetermination of borrowing base	6 months
Credit Facility | Maximum
Financial Ratio Covenants
Net consolidated indebtedness to EBITDA ratio	4
2020 Senior Notes
Liquidity Sufficiency
Periodic interest payment amount on due dates	32,000,000
2021 Senior Notes
Liquidity Sufficiency
Periodic interest payment amount on due dates	$32,000,000

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounts Receivable and Allowance for Doubtful Accounts
Allowance for doubtful accounts	$0	$0
Other Noncurrent Assets
Deferred financing costs	37,807,000	44,706,000
Field equipment inventory	5,713,000	9,682,000
Other	211,000	209,000
Other noncurrent assets	43,731,000	54,597,000
Adjustments amount of field inventory	5,900,000
Additional field inventory purchased	1,800,000
Gain (loss) on sale of or market value adjustments to inventory	-4,100,000	-600,000
Oil and Gas Reserves
Provision for price and cost escalations	0
Cash interest paid	141,900,000	104,300,000	7,200,000
Accrued Liabilities
Accrued oil and gas capital expenditures	76,398,000	87,202,000
Accrued revenue and royalty distributions	51,292,000	64,370,000
Accrued lease operating and workover expense	10,113,000	8,279,000
Accrued interest	21,521,000	21,341,000
Accrued taxes	4,226,000	4,386,000
Other	20,281,000	18,803,000
Accrued Liabilities	183,831,000	204,381,000
Income Taxes
Provision for Federal or State Income Tax Prior to Company Reorganization	0
Oil and Gas Properties
Property and equipment
Ceiling limit of capitalized cost for determining impairment to oil and gas properties, after tax	83,500,000	319,600,000
Mississippian unevaluated property costs attributable to leases	59,200,000	168,400,000
Anadarko Basin unevaluated property costs transferred	128,200,000	89,600,000
Gulf Coast unevaluated property costs transferred to the full cost pool	$16,500,000	$61,200,000
Other Property and Equipment | Minimum
Property and equipment
Estimated useful lives	3 years
Other Property and Equipment | Maximum
Property and equipment
Estimated useful lives	7 years

Fair_Value_Measurements_of_Fin2

Fair Value Measurements of Financial Instruments (Details) (Recurring, Commodity Derivatives, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	item	item
Significant Other Observable Inputs (Level 2)
Fair Value Measurements of Financial Instruments
Number of bank counterparties for company's commodity derivative contracts	7	7
Assets:
Total assets	$126,709	$2,578
Liabilities:
Total liabilities		33,390
Significant Other Observable Inputs (Level 2) | Swaps | Oil
Assets:
Total assets		469
Liabilities:
Total liabilities		32,209
Significant Other Observable Inputs (Level 2) | Swaps | NGL
Assets:
Total assets		488
Liabilities:
Total liabilities		74
Significant Other Observable Inputs (Level 2) | Collars | Oil
Assets:
Total assets	106,450	64
Liabilities:
Total liabilities		809
Significant Other Observable Inputs (Level 2) | Collars | Natural Gas
Assets:
Total assets	20,259	751
Liabilities:
Total liabilities		272
Significant Other Observable Inputs (Level 2) | Basis Differential Swaps
Assets:
Total assets		806
Liabilities:
Total liabilities		26
Total
Assets:
Total assets	126,709	2,578
Liabilities:
Total liabilities		33,390
Total | Swaps | Oil
Assets:
Total assets		469
Liabilities:
Total liabilities		32,209
Total | Swaps | NGL
Assets:
Total assets		488
Liabilities:
Total liabilities		74
Total | Collars | Oil
Assets:
Total assets	106,450	64
Liabilities:
Total liabilities		809
Total | Collars | Natural Gas
Assets:
Total assets	20,259	751
Liabilities:
Total liabilities		272
Total | Basis Differential Swaps
Assets:
Total assets		806
Liabilities:
Total liabilities		$26

Risk_Management_and_Derivative2

Risk Management and Derivative Instruments (Details) (Not designated as Hedging Instrument, Commodity Derivatives, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
	item
Risk Management and Derivative Instruments
Maximum loss exposure under commodity derivative contracts on failure of the entity's counterparty's performance	$126.70
Oil | WTI | Swaps | 2015
Risk Management and Derivative Instruments
Hedged Volume	3,276,000
Weighted-Average Fixed Price	88.72
Natural Gas | Swaps | 2014
Risk Management and Derivative Instruments
Hedged Volume, not settled in cash	2,170,000
Natural Gas | Swaps | 2015
Risk Management and Derivative Instruments
Hedged Volume	20,050,000
Weighted-Average Fixed Price	4.15

Risk_Management_and_Derivative3

Risk Management and Derivative Instruments (Details 2) (Commodity Derivatives, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
			bbl
Option | Oil | Put
Derivative liabilities:
Payment of deferred premium	$0	$0	$3,300,000
Number of barrels covered under the commodity contract			549,000
Not designated as Hedging Instrument
Risk Management and Derivative Instruments
Total derivative fair value	126,709,000	-30,812,000
Derivative assets:
Gross Recognized Assets	126,709,000	2,578,000
Gross Amounts Offset, Assets		1,859,000
Net Recognized Fair Value Assets	126,709,000	719,000
Derivative liabilities:
Gross Recognized Liabilities		33,390,000
Gross Amounts Offset, Liabilities		1,859,000
Net Recognized Fair Value Liabilities		31,531,000
Not designated as Hedging Instrument | Current Assets
Derivative assets:
Gross Recognized Assets	126,709,000	2,559,000
Gross Amounts Offset, Assets		1,859,000
Net Recognized Fair Value Assets	126,709,000	700,000
Not designated as Hedging Instrument | Non-Current Assets
Derivative assets:
Gross Recognized Assets		19,000
Net Recognized Fair Value Assets		19,000
Not designated as Hedging Instrument | Current Liabilities
Derivative liabilities:
Gross Recognized Liabilities		29,739,000
Gross Amounts Offset, Liabilities		1,859,000
Net Recognized Fair Value Liabilities		27,880,000
Not designated as Hedging Instrument | Non-Current Liabilities
Derivative liabilities:
Gross Recognized Liabilities		3,651,000
Net Recognized Fair Value Liabilities		3,651,000
Not designated as Hedging Instrument | Swaps | Current Assets | Oil
Derivative assets:
Gross Recognized Assets	106,450,000
Not designated as Hedging Instrument | Swaps | Current Assets | NGL
Derivative assets:
Gross Recognized Assets		469,000
Not designated as Hedging Instrument | Swaps | Current Assets | Natural Gas
Derivative assets:
Gross Recognized Assets	20,259,000	469,000
Not designated as Hedging Instrument | Swaps | Non-Current Assets | Natural Gas
Derivative assets:
Gross Recognized Assets		19,000
Not designated as Hedging Instrument | Swaps | Current Liabilities | Oil
Derivative liabilities:
Gross Recognized Liabilities		-28,871,000
Not designated as Hedging Instrument | Swaps | Current Liabilities | NGL
Derivative liabilities:
Gross Recognized Liabilities		-74,000
Not designated as Hedging Instrument | Swaps | Current Liabilities | Natural Gas
Derivative liabilities:
Gross Recognized Liabilities		-496,000
Not designated as Hedging Instrument | Swaps | Non-Current Liabilities | Oil
Derivative liabilities:
Gross Recognized Liabilities		-3,338,000
Not designated as Hedging Instrument | Swaps | Non-Current Liabilities | Natural Gas
Derivative liabilities:
Gross Recognized Liabilities		-313,000
Not designated as Hedging Instrument | Collars | Current Assets | Oil
Derivative assets:
Gross Recognized Assets		64,000
Not designated as Hedging Instrument | Collars | Current Assets | Natural Gas
Derivative assets:
Gross Recognized Assets		751,000
Not designated as Hedging Instrument | Collars | Current Liabilities | Oil
Derivative liabilities:
Gross Recognized Liabilities		-272,000
Not designated as Hedging Instrument | Collars | Current Liabilities | Natural Gas
Derivative liabilities:
Gross Recognized Liabilities		-26,000
Not designated as Hedging Instrument | Basis Differential Swaps | Current Assets
Derivative assets:
Gross Recognized Assets		$806,000

Risk_Management_and_Derivative4

Risk Management and Derivative Instruments (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Gains (losses) on Commodity Derivative Contracts
Realized net losses	$18,332	$17,585	$15,825
Unrealized net gains (losses)	157,500
Gains (losses) on commodity derivative contracts - net	139,189	-44,284	-11,158
Not designated as Hedging Instrument
Gains (losses) on Commodity Derivative Contracts
Realized net losses	-18,332	-17,585	-15,825
Unrealized net gains (losses)	157,521	-26,699	4,667
Gains (losses) on commodity derivative contracts - net	$139,189	($44,284)	($11,158)

Property_and_Equipment_Details

Property and Equipment (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property and Equipment
Proved properties	$3,398,146,000	$2,817,062,000
Unevaluated properties	44,535,000	243,599,000
Other property and equipment	13,454,000	11,113,000
Less accumulated depreciation, depletion, amortization and impairment	-1,333,019,000	-976,880,000
Net property and equipment	2,123,116,000	2,094,894,000
Other information
Capitalized qualifying share-based compensation expense	2,200,000	1,400,000
Other Property and Equipment
Other information
Depreciation expense	3,100,000	2,200,000	500,000
Oil and Gas Properties
Other information
Depletion expense related to oil and gas properties	266,800,000	248,200,000	125,100,000
Depletion expense (per Boe)	22.75	28.42	34.17
Costs capitalized to unevaluated properties	12,400,000	32,200,000	11,200,000
Internal cost capitalized	12,400,000	8,400,000	1,500,000
Capitalized qualifying share-based compensation expense	$2,200,000	$1,400,000	$200,000

Acquisition_and_Divestitures_o2

Acquisition and Divestitures of Oil and Gas Properties (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 25, 2014	1-May-14	31-May-13	Oct. 01, 2012	Apr. 01, 2013	Mar. 05, 2014
Oil and gas properties
Proved	$3,398,146,000	$2,817,062,000
Additional disclosures
Cost of acquiring additional acreage and producing wells		620,112,000	351,276,000
Proceeds from sale of other properties	1,400,000
Unaudited Pro forma information
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	67,271,000	-359,574,000	-156,597,000
Other accounts receivable	22,193,000	1,090,000
Acquisition and transaction costs	4,129,000	11,803,000	14,884,000
PetroQuest | Exploration agreement
Unaudited Pro forma information
Undivided right, title and interest (as a percent)				50.00%
Cash consideration	3,000,000
Additional cash consideration	7,000,000
Additional non-interest consideration	14,000,000
Other accounts receivable	7,000,000
Pro Forma
Unaudited Pro forma information
Revenues and other		539,562,000	490,241,000
Net income (loss)		-340,400,000	-129,885,000
Preferred stock dividends		-15,589,000	-26,000,000
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		-355,989,000	-155,885,000
Net loss per common share - basic and diluted		$5.41	$2.60
Pine Prairie Disposition
Unaudited Pro forma information
Purchase price of subject to standard post-closing adjustments received in cash					-147,700,000				-170,000,000
Acquisition and transaction costs	4,100,000
2020 Senior Notes
Additional disclosures
Interest rate (as a percent)							10.75%
2021 Senior Notes
Additional disclosures
Interest rate (as a percent)						9.25%
Credit Facility | Pine Prairie Disposition
Unaudited Pro forma information
Repayment of debt					131,000,000
Mandatorily redeemable convertible preferred units
Unaudited Pro forma information
Preferred stock dividends	-10,400,000	-15,600,000
Anadarko Basin Acquisition
Oil and gas properties
Proved						417,750,000
Unevaluated						207,606,000
Total assets acquired						625,356,000
Asset retirement obligations		6,296,000				6,296,000
Total liabilities assumed						6,296,000
Net assets acquired						619,060,000
Additional disclosures
Revenue included in the statement of consolidated operations	178,900,000	104,700,000
Unaudited Pro forma information
Acquisition and transaction costs		11,800,000
Anadarko Basin Acquisition | 2021 Senior Notes | Panther Energy LLC
Acquisition of Oil and Gas Properties
Purchase price, cash						618,000,000
Additional disclosures
Aggregate principal amount borrowed						700,000,000
Interest rate (as a percent)						9.25%
Eagle Property Acquisition
Acquisition of Oil and Gas Properties
Purchase price, cash							325,000,000
Oil and gas properties
Proved							419,549,000
Unevaluated							244,236,000
Commodity derivative contracts							8,453,000
Total assets acquired							672,238,000
Asset retirement obligations			2,662,000				2,662,000
Deferred income tax liabilities		-727,000	26,712,000				25,985,000
Total liabilities assumed							28,647,000
Net assets acquired							643,591,000
Additional disclosures
Revenue included in the statement of consolidated operations			28,400,000
Unaudited Pro forma information
Acquisition and transaction costs			14,900,000
Eagle Property Acquisition | 2020 Senior Notes
Additional disclosures
Aggregate principal amount borrowed							600,000,000
Interest rate (as a percent)							10.75%
Eagle Property Acquisition | Mandatorily redeemable convertible preferred units
Acquisition of Oil and Gas Properties
Purchase price, preferred shares							325,000
Liquidation value (in dollars per share)							$1,000
Other Property Acquisitions | Gulf Coast
Additional disclosures
Cost of acquiring additional acreage and producing wells								$3,400,000

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligations
Asset retirement obligations	$21,599,000	$26,308,000	$15,245,000
Changes in Company's asset retirement obligations
Asset retirement obligations at beginning of year	26,308,000	15,245,000	7,627,000
Liabilities incurred	996,000	2,535,000	3,044,000
Liabilities assumed in Anadarko Basin and Eagle Property Acquisition for year ended 2013 and 2012 respectively		6,296,000	2,662,000
Revisions	288,000	858,000	1,189,000
Liabilities settled	-47,000	-61,000
Liabilities eliminated through asset sale	-7,652,000
Current period accretion expense	1,706,000	1,435,000	723,000
Asset retirement obligations at end of year	21,599,000	26,308,000	15,245,000
Liabilities reduced in Prairie Disposition	$7,700,000

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	12 Months Ended	24 Months Ended	0 Months Ended		12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Oct. 01, 2012	31-May-13	Dec. 31, 2013	Aug. 30, 2013	Mar. 31, 2015	Sep. 30, 2014	Sep. 29, 2014
Long-Term Debt
Total long-term debt	$1,735,150,000	$1,735,150,000			$1,701,150,000
Leverage ratio	3.7	3.7
Actual current ratio	1.1
Midstates Sub
Long-Term Debt
Ownership interest (as a percent)						100.00%
Credit Facility Amendment - September 26, 2013 | Fiscal quarter ending March 31, 2015 and each fiscal quarter thereafter
Long-Term Debt
Leverage ratio							4
Maximum | Credit Facility Amendment - September 26, 2013 | Fiscal quarter ending December 31, 2014
Long-Term Debt
Leverage ratio	4.75	4.75
Senior Revolving Credit Facility, due 2018
Long-Term Debt
Long-term debt	435,150,000	435,150,000			401,150,000
Maximum borrowing capacity	750,000,000	750,000,000
Borrowing base								525,000,000	475,000,000
Interest rate, description	LIBOR
Weighted-average interest rate (as a percent)	2.80%	2.80%			2.50%
Commitment fee, option one (as a percent)	0.38%
Commitment fee, option two (as a percent)	0.50%
Period during which Company may request additional redetermination of borrowing base	6 months
Outstanding letters of credit amount	1,400,000	1,400,000
Number of equal successive monthly payments to make repayment on reduction of borrowing base	6
Period for commencement of repayment of equal successive monthly payments following the administrative agent's notice regarding borrowing base reduction	30 days
Actual current ratio	1.1
Actual Debt to EBITDA	3.7	3.7
Senior Revolving Credit Facility, due 2018 | Minimum
Long-Term Debt
Interest rate added to base rate (as a percent)	2.00%
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%
Current ratio	1	1
Senior Revolving Credit Facility, due 2018 | Maximum
Long-Term Debt
Interest rate added to base rate (as a percent)	3.00%
Additional borrowing base redeterminations at company request per 6 month period following each scheduled borrowing base redetermination	1
2020 Senior Notes
Long-Term Debt
Long-term debt	600,000,000	600,000,000			600,000,000
Interest rate (as a percent)			10.75%
Estimated fair value of the Notes	327,000,000	327,000,000
Aggregate principal amount borrowed			600,000,000
Redemption price, expressed as percentage of principal amount	101.00%
Effective annual interest rate (as a percent)		11.10%
2020 Senior Notes | Period One
Long-Term Debt
Debt instrument redemption period end date			30-Sep-15
Redemption price, expressed as percentage of principal amount			110.75%
2020 Senior Notes | Period Two
Long-Term Debt
Debt instrument redemption period end date			30-Sep-16
Redemption price, percentage			100.00%
2020 Senior Notes | Maximum | Period One
Long-Term Debt
Percentage of debt that can be redeemed			35.00%
2021 Senior Notes
Long-Term Debt
Long-term debt	700,000,000	700,000,000			700,000,000
Interest rate (as a percent)				9.25%
Proceeds from the offering (net of the initial purchasers' discount and related offering expenses)				700,000,000
Repayment of outstanding facility balance				34,300,000
Estimated fair value of the Notes	357,000,000	357,000,000
Aggregate principal amount borrowed				$700,000,000
Effective annual interest rate (as a percent)	9.60%				9.50%
2021 Senior Notes | Midstates Sub
Long-Term Debt
Ownership interest (as a percent)				100.00%
2021 Senior Notes | Period One
Long-Term Debt
Debt instrument redemption period end date				31-May-16
Redemption price, percentage				100.00%
Redemption price, expressed as percentage of principal amount				109.25%
2021 Senior Notes | Maximum | Period Two
Long-Term Debt
Percentage of debt that can be redeemed				35.00%
Credit Facility
Long-Term Debt
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
Credit Facility | Maximum
Long-Term Debt
Leverage ratio	4	4

Preferred_StockUnits_Details

Preferred Stock/Units (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 26, 2012	Dec. 31, 2011	Sep. 28, 2012
Financial Instruments Subject to Mandatory Redemption, Settlement Terms, Share Value, Amount [Abstract]
Proceeds from issuance of preferred units			$65,000,000
Interest Expense	137,548,000	83,138,000	12,999,000
Mandatorily redeemable convertible preferred units
Financial Instruments Subject to Mandatory Redemption, Settlement Terms, Share Value, Amount [Abstract]
Number of shares authorized					65,000
Value of shares authorized to be issued					65,000,000
Redemption amount				67,100,000
Interest Expense	0	0	2,100,000
Common Stock
Changes in number of outstanding shares
Share count at the end of the period (in shares)	70,491,732	68,925,745	66,619,711
Mandatorily redeemable convertible preferred units
Series A Preferred Stock
Conversion rate for preferred stock (in dollars per share)	$11	$11
Preferred stock dividends	10,400,000	15,600,000
Number of Common Shares Issuable Upon Conversion	2,659,792	2,459,127
Notional dividend amount of convertible preferred stock	29,300,000	27,100,000
Eagle Property Acquisition | Mandatorily redeemable convertible preferred units
Series A Preferred Stock
Preferred stock, shares designated						325,000
Liquidation value (in dollars per share)						$1,000
Rate of interest for preferred stock (as a percent)	8.00%
Conversion rate for preferred stock (in dollars per share)	$13.50
Period required to convert preferred stock into common stock	15 days
Eagle Property Acquisition | Maximum | Mandatorily redeemable convertible preferred units
Series A Preferred Stock
Conversion rate for preferred stock (in dollars per share)	$13.50
Eagle Property Acquisition | Minimum | Mandatorily redeemable convertible preferred units
Series A Preferred Stock
Conversion rate for preferred stock (in dollars per share)	$11
Series A Preferred Stock
Series A Preferred Stock
Preferred stock, shares issued	325,000	325,000
Preferred stock, shares outstanding	325,000	325,000
Rate of interest for preferred stock (as a percent)	8.00%	8.00%
Changes in number of outstanding shares
Share count at the beginning of the period (in shares)	325,000	325,000
Issuance of preferred stock as consideration in Eagle Property Acquisition (in shares)			325,000
Share count at the end of the period (in shares)	325,000	325,000	325,000
Holdings LLC | Mandatorily redeemable convertible preferred units
Series A Preferred Stock
Preferred stock, shares issued			65,000
Financial Instruments Subject to Mandatory Redemption, Settlement Terms, Share Value, Amount [Abstract]
Proceeds from issuance of preferred units			$65,000,000
$13.50 | Series A Preferred Stock
Series A Preferred Stock
Number of Common Shares Issuable Upon Conversion	28,726,527
$11.00 | Series A Preferred Stock
Series A Preferred Stock
Number of Common Shares Issuable Upon Conversion	35,255,283

Equity_and_ShareBased_Compensa2

Equity and Share-Based Compensation (Details) (USD $)	0 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Apr. 25, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 25, 2012
		item
Transactions with Chief Executive Officer of Petroleum Inc.
Common stock, par value (in dollars per share)		0.01	0.01
Common stock, shares authorized		300,000,000	300,000,000
Restricted stock awards
Changes in number of outstanding shares
Granted (in dollars per share)		4.66	6.82
Unrecognized expense, adjusted for estimated forfeitures (in dollars)		10.9
Eagle Property Acquisition | Mandatorily redeemable convertible preferred units
Changes in number of outstanding shares
Rate of interest for preferred stock (as a percent)		8.00%
Common Stock
Transactions with Chief Executive Officer of Petroleum Inc.
Shares issued upon conversion				47,634,353
Numbers of shares sold	27,600,000
Common stock, par value (in dollars per share)	$0.01				$0.01
Number of shares of stock sold by the selling shareholders	6,000,000
Number of shares of sold by the selling shareholders pursuant to an option granted to the underwriters to cover over-allotments	3,600,000
Common stock, shares authorized	300,000,000				300,000,000
Number of votes per share entitled to holders		1
Number of preferences or rights of conversion or rights of conversion, exchange, pre-exemption or other subscription rights for common stock		0
Changes in number of outstanding shares
Share count at the beginning of the period (in shares)		68,925,745	66,619,711
Issuance of common stock in pre IPO reorganization (in shares)				47,634,353
Proceeds from the sale of common stock to public (in shares)				18,000,000
Grants of restricted stock (in shares)		3,447,485	2,840,241	1,029,509
Forfeitures of restricted stock (in shares)		-1,881,498	-534,207	-44,151
Share count at the end of the period (in shares)		70,491,732	68,925,745	66,619,711
Other shares or units were issued		70,491,732	68,925,745	66,619,711
Treasury Stock
Changes in number of outstanding shares
Share count at the beginning of the period (in shares)		-118,702
Acquisition of treasury stock (in shares)		-415,975	-118,702
Share count at the end of the period (in shares)		-534,677	-118,702
Other shares or units were issued		-534,677	-118,702
Preferred Stock
Transactions with Chief Executive Officer of Petroleum Inc.
Preferred stock, shares authorized	50,000,000				50,000,000
Preferred stock, par value (in dollars per share)	$0.01				$0.01

Equity_and_ShareBased_Compensa3

Equity and Share-Based Compensation (Details 2) (Incentive units, USD $)	12 Months Ended
	Dec. 31, 2014
Incentive units
Restricted Stock Awards
Incentive units issued	1,099
Stock-based compensation expense (in dollars)	$0

Equity_and_ShareBased_Compensa4

Equity and Share-Based Compensation (Details 3) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	27-May-14	Apr. 20, 2012
Restricted stock awards
Restricted Stock Awards
Requisite service period for recognition of compensation expense	3 years
Shares
Non-vested shares outstanding at the beginning of the period	2,963,672	985,358
Granted (in shares)	3,447,485	2,840,241
Vested (in shares)	-1,467,644	-327,720
Forfeited (in shares)	-1,881,498	-534,207
Non-vested shares outstanding at the end of the period	3,062,015	2,963,672
Weighted Average Grant Date Fair Value
Non-vested shares outstanding at the beginning of the period (in dollars per share)	$7.78	$12.61
Granted (in dollars per share)	$4.66	$6.82
Vested (in dollars per share)	$7.21	$12.62
Forfeited (in dollars per share)	$6.58	$8.65
Non-vested shares outstanding at the end of the period (in dollars per share)	$5.28	$7.78
Additional information
Unrecognized expense, adjusted for estimated forfeitures (in dollars)	$10.90
Weighted-average period for over which unrecognized expense will be recognized	1 year 11 months 19 days
LTIP
Restricted Stock Awards
Number of shares registered for future issuance	8,638,435		8,638,435	6,563,435
Additional information
Shares available for issuance	3,781,056
LTIP | Restricted stock awards
Restricted Stock Awards
Number of restricted common stock issued to directors, management and employees under the long term incentive plan (in shares)	3,062,015
Vesting period	3 years
Percentage of awards vesting on each anniversary of the grant	33.00%
LTIP | Restricted stock awards | Directors
Restricted Stock Awards
Vesting period	1 year

Equity_and_ShareBased_Compensa5

Equity and Share-Based Compensation (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation, Post-Initial Public Offering
Total share-based compensation expense	$8,618,000	$5,713,000	$2,459,000
Capitalized qualifying share-based compensation costs to oil and gas properties	2,200,000	1,400,000
Severance
Share-based Compensation, Post-Initial Public Offering
Total share-based compensation expense	2,900,000
LTIP | General and administrative expense Member
Share-based Compensation, Post-Initial Public Offering
Share-based compensation costs recognized	$8,600,000	$5,700,000	$2,500,000

Income_Taxes_Details

Income Taxes (Details) (USD $)	3 Months Ended	12 Months Ended
	Jun. 30, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes
Provision for federal or state income tax prior to company reorganization		$0
Net deferred income tax expense	149,500,000	5,586,000	-146,529,000	157,886,000
Unrealized net gains (losses)		157,500,000
Income before taxes		123,324,000	-490,514,000	7,789,000
Income tax payments expected in the upcoming four quarterly reporting periods		0
Income tax expense benefit expected in Texas margin tax payment in 2015		600,000
Income Taxes
Tax refund		0
Current income taxes		809,000
Current
State		809,000
Total current		809,000
Deferred
United States		3,863,000	-130,906,000	137,496,000
State		1,723,000	-15,623,000	20,390,000
Total deferred	149,500,000	5,586,000	-146,529,000	157,886,000
Income tax benefit (expense)		-6,395,000	146,529,000	-157,886,000
Reconciliation of income tax expense
Income before taxes		123,324,000	-490,514,000	7,789,000
Statutory rate		35.00%	35.00%	35.00%
Income tax expense computed at statutory rate		43,164,000	-171,680,000	2,726,000
Reconciling items:
Non-deductible pre-IPO loss				4,561,000
State income taxes, net of federal benefit		4,398,000	-10,886,000	1,053,000
Change in valuation allowance		-42,134,000	45,688,000
Change in state rate		-414,000	-10,500,000
Other, net		1,381,000	849,000	57,000
Change in tax status (1)				149,489,000
Tax income tax provision (benefit)		6,395,000	-146,529,000	157,886,000
Federal change in tax status				130,200,000
State change in tax status				19,300,000
Deferred tax assets - current
Derivative instruments and other			15,581,000
Less valuation allowance			-3,744,000
Total deferred tax assets, current			11,837,000
Deferred tax assets - noncurrent
US tax loss carryforwards		75,604,000	151,872,000
State tax loss carryforwards		7,122,000	14,154,000
Employee benefit plans		2,193,000	1,539,000
Less valuation allowance		-3,826,000	-41,944,000
Total deferred tax assets, noncurrent		81,093,000	125,621,000
Deferred tax liabilities
Derivative instruments and other		44,862,000
Total deferred tax liabilities - current		44,862,000
Oil and gas properties and equipment		45,272,000	140,912,000
Total deferred tax liabilities, noncurrent		45,272,000	140,912,000
Reflected in the accompanying balance sheet as:
Net deferred tax assets, current			11,837,000
Net deferred tax liability, current		44,862,000
Net deferred tax asset, noncurrent		35,821,000
Net deferred tax liability noncurrent			15,291,000
Louisiana
Income Taxes
Valuation allowance against net operating loss carryforwards		45,700,000
Federal
Income Taxes
Valuation allowance		39,900,000
State | Louisiana
Income Taxes
Valuation allowance		$3,800,000

Earnings_Loss_Per_Share_Detail

Earnings (Loss) Per Share (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings (Loss) Per Share
Net income (loss)	$116,929	($343,985)	($150,097)
Preferred Dividend	-10,378	-15,589	-6,500
Net income (loss) attributable to shareholders	106,551	-359,574	-156,597
Participating securities - Series A Preferred Stock	-35,696
Participating securities - Non-vested Restricted Stock	-3,584
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	67,271	-359,574	-156,597
Weighted average shares outstanding	66,440,000	65,766,000	59,979,000
Basic and diluted income (loss) per share	$1.01	($5.47)	($2.61)
Series A Preferred Stock
Earnings (Loss) Per Share
Participating securities - Series A Preferred Stock	($35,696)
Preferred stock, shares outstanding	325,000	325,000

Concentrations_of_Credit_Risk_

Concentrations of Credit Risk (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	item	item	item
Concentrations of Credit Risk
Short-term contracts usual term	1 month
Revenue | Customer concentration
Concentrations of Credit Risk
Number of purchasers	4	5	3
Revenue | Customer concentration | Purchaser one
Concentrations of Credit Risk
Concentration risk (as a percent)	28.00%	28.00%	41.00%
Revenue | Customer concentration | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)	18.00%	16.00%	32.00%
Revenue | Customer concentration | Purchaser three
Concentrations of Credit Risk
Concentration risk (as a percent)	15.00%	13.00%	10.00%
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	4	3
Accounts receivable | Customer concentration | Purchaser one
Concentrations of Credit Risk
Concentration risk (as a percent)	25.00%	31.00%
Accounts receivable | Customer concentration | Purchaser two
Concentrations of Credit Risk
Concentration risk (as a percent)	23.00%	16.00%
Accounts receivable | Customer concentration | Purchaser three
Concentrations of Credit Risk
Concentration risk (as a percent)	15.00%	13.00%
Accounts receivable | Customer concentration | Purchaser four
Concentrations of Credit Risk
Concentration risk (as a percent)	13.00%

Commitments_and_Contingencies_1

Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net minimum commitments
Total	$29,210,000
2015	20,868,000
2016	2,756,000
2017	1,941,000
2018	1,471,000
2019 and beyond	2,174,000
Interest payments due on the senior notes during the year ended December 31, 2015	130,000,000
Total obligations due in December 31, 2015	150,000,000
Office rent	2,300,000	1,700,000	1,100,000
Natural Gas | Delivery during first 60 months of the contract
Net minimum commitments
Period after which company would receive volumetric credit for any deficiency payment under contract	60 months
Drilling contracts
Net minimum commitments
Total	16,698,000
2015	15,819,000
2016	879,000
Non-cancellable office lease commitments
Net minimum commitments
Total	9,320,000
2015	1,857,000
2016	1,877,000
2017	1,941,000
2018	1,471,000
2019 and beyond	2,174,000
Non-cancellable office lease commitments | Houston
Net minimum commitments
Total	3,400,000
Seismic contracts
Net minimum commitments
Total	3,192,000
2015	$3,192,000
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)	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)	0.125
Gas transportation gathering and processing contract | Natural Gas
Net minimum commitments
Period after which company would receive volumetric credit for any deficiency payment under contract	30 months
Gas transportation gathering and processing contract | Natural Gas | Delivery during first 30 months of the contract
Net minimum commitments
Fee used as multiple for payment to the counterparty equal to the shortfall amount (in dollars per gallon/MMBTU)	0.36
Contractual obligation	38,100,000
Gas transportation gathering and processing contract | Natural Gas | Delivery during first 60 months of the contract
Net minimum commitments
Fee used as multiple for payment to the counterparty equal to the shortfall amount (in dollars per gallon/MMBTU)	0.36
Contractual obligation	76,200,000
Gas transportation gathering and processing contract | NGL | Minimum
Net minimum commitments
Volume commitments per day over the remaining term of the contract	2,800
Gas transportation gathering and processing contract | NGL | Maximum
Net minimum commitments
Volume commitments per day over the remaining term of the contract	5,780

Subsequent_Evenets_Details

Subsequent Evenets (Details) (Subsequent event, Dequincy assets, USD $)	Mar. 01, 2015
In Millions, unless otherwise specified
Subsequent event | Dequincy assets
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	$44