Amplify Energy (AMPY) 10-Q 10 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 07, 2018
Document and Entity Information
Entity Registrant Name	Midstates Petroleum Company, Inc.
Entity Central Index Key	1,533,924
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		25,256,957
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
CURRENT ASSETS:
Cash and cash equivalents	$ 8,428	$ 68,498
Accounts receivable:
Oil and gas sales	30,467	32,455
Joint interest billing	3,691	3,297
Other	259	166
Commodity derivative contracts		762
Other current assets	3,124	1,510
Total current assets	45,969	106,688
Oil and gas properties, on the basis of full-cost accounting
Proved properties	798,593	765,308
Unproved properties not being amortized	7,142	7,065
Other property and equipment	6,502	6,508
Less accumulated depreciation, depletion, amortization and impairment	(219,590)	(204,419)
Net property and equipment	592,647	574,462
OTHER NONCURRENT ASSETS	7,006	6,978
TOTAL	645,622	688,128
CURRENT LIABILITIES:
Accounts payable	6,652	11,547
Accrued liabilities	45,533	42,842
Commodity derivative contracts	6,062	3,433
Total current liabilities	58,247	57,822
LONG-TERM LIABILITIES:
Asset retirement obligations	15,853	15,506
Commodity derivative contracts	950	562
Long-term debt	78,059	128,059
Other long-term liabilities	585	592
Total long-term liabilities	95,447	144,719
COMMITMENTS AND CONTINGENCIES (Note 14)
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value, 50,000,000 shares authorized; no shares issued or outstanding at March 31, 2018 and December 31, 2017
Warrants, 6,625,554 warrants outstanding at March 31, 2018 and December 31,2017	37,329	37,329
Common stock, $0.01 par value, 250,000,000 shares authorized; 25,383,854 shares issued and 25,255,485 shares outstanding at March 31, 2018; 25,272,969 shares issued and 25,173,346 shares outstanding at December 31, 2017	254	253
Treasury stock	(2,062)	(1,603)
Additional paid-in-capital	527,550	524,755
Retained deficit	(71,143)	(75,147)
Total stockholders' equity	491,928	485,587
TOTAL	$ 645,622	$ 688,128

CONDENSED CONSOLIDATED BALANCE3

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Mar. 31, 2018	Dec. 31, 2017
CONDENSED CONSOLIDATED BALANCE SHEETS
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Warrants outstanding	6,625,554	6,625,554
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	250,000,000	250,000,000
Common stock, shares issued	25,383,854	25,272,969
Common stock, shares outstanding	25,255,485	25,173,346

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
REVENUES :
Gains (losses) on commodity derivative contracts-net	$ (3,939)	$ 4,865
Total revenues	48,905	65,015
EXPENSES :
Lease operating and workover	14,808	15,852
Gathering and transportation (Note 3)	57	3,687
Severance and other taxes	2,861	2,121
Asset retirement accretion	297	276
Depreciation, depletion, and amortization	15,213	15,342
General and administrative	9,857	8,275
Total expenses	43,093	45,553
OPERATING INCOME	5,812	19,462
OTHER EXPENSE:
Interest income	19
Interest expense-net of amounts capitalized	(1,827)	(977)
Total other expense	(1,808)	(977)
INCOME BEFORE TAXES	4,004	18,485
Income tax expense	0
NET INCOME	4,004	18,485
Participating securities-non-vested restricted stock	(99)	(546)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 3,905	$ 17,939
Basic and diluted net income per share attributable to common shareholders	$ 0.15	$ 0.72
Basic and diluted weighted average number of common shares outstanding (Note 12)	25,299	25,012
Revenue from contracts with customers
REVENUES :
Total revenues	$ 52,844	$ 60,150
Oil
REVENUES :
Total revenues	32,414	31,036
Natural gas liquid
REVENUES :
Total revenues	11,038	11,194
Natural gas
REVENUES :
Total revenues	8,337	17,098
Other
REVENUES :
Total revenues	$ 1,055	$ 822

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Common Stock	Warrants	Treasury Stock	Additional Paid-in-Capital	Retained Earnings (Deficit)	Total
Balance at Dec. 31, 2016	$ 250	$ 37,329		$ 514,305	$ 9,930	$ 561,814
Increase (Decrease) in Stockholders' Equity
Share-based compensation				3,790		3,790
Net income					18,485	18,485
Balance at Mar. 31, 2017	250	37,329		518,095	28,415	584,089
Balance at Dec. 31, 2017	253	37,329	$ (1,603)	524,755	(75,147)	485,587
Increase (Decrease) in Stockholders' Equity
Share-based compensation	1			2,795		2,796
Acquisition of treasury stock			(459)			(459)
Net income					4,004	4,004
Balance at Mar. 31, 2018	$ 254	$ 37,329	$ (2,062)	$ 527,550	$ (71,143)	$ 491,928

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 4,004	$ 18,485
Adjustments to reconcile net income to net cash provided by operating activities:
(Gains) losses on commodity derivative contracts-net	3,939	(4,865)
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments	(160)	811
Asset retirement accretion	297	276
Depreciation, depletion, and amortization	15,213	15,342
Share-based compensation, net of amounts capitalized to oil and gas properties	2,210	3,337
Amortization of deferred financing costs	108	80
Change in operating assets and liabilities:
Accounts receivable - oil and gas sales	1,293	2,812
Accounts receivable - JIB and other	(663)	(842)
Other current and noncurrent assets	(1,750)	(656)
Accounts payable	(1,467)	1,279
Accrued liabilities	(869)	(3,649)
Other	(8)	(37)
Net cash provided by operating activities	22,147	32,373
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(31,758)	(26,108)
Proceeds from the sale of oil and gas equipment		1,350
Net cash used in investing activities	(31,758)	(24,758)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of revolving credit facility	(50,000)
Repurchase of restricted stock for tax withholdings	(459)
Net cash used in financing activities	(50,459)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(60,070)	7,615
Cash and cash equivalents, beginning of period	68,498	76,838
Cash and cash equivalents, end of period	8,428	84,453
SUPPLEMENTAL INFORMATION:
Non-cash transactions - investments in property and equipment accrued - not paid	18,508	17,440
Cash paid for interest, net of capitalized interest of $0.1 million and $0.9 million, respectively	$ 1,785	$ 937

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Capitalized interest	$ 0.1	$ 0.9

Organization and Business

Organization and Business	3 Months Ended
	Mar. 31, 2018
Organization and Business
Organization and Business	1. Organization and Business Midstates Petroleum Company, Inc. engages in the business of exploring and drilling for, and the production of, oil, natural gas liquids (“NGLs”) and natural gas in Oklahoma and Texas. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”). The terms “Company,” “we,” “us,” “our,” and similar terms refer to Midstates Petroleum Company, Inc. and its subsidiary. The Company conducts oil and gas operations and owns and operates oil and natural gas properties in Oklahoma and Texas. The Company operates a significant portion of its oil and natural gas properties. The Company’s management evaluates performance based on one reportable segment as all of its operations are located in the United States and, therefore, it maintains one cost center.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2018
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies	2. Summary of Significant Accounting Policies Basis of Presentation These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“US GAAP”) for complete consolidated financial statements, and should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2017 included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 14, 2018. All intercompany transactions have been eliminated in consolidation. In the opinion of the Company’s management, the accompanying unaudited condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessary to fairly present the financial position as of, and the results of operations for, all periods presented. In preparing the accompanying unaudited condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the unaudited condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results. As a result of the adoption of Accounting Standards Update 2014-09, “Revenue from Contracts with Customers (Topic 606) ” (“ASU 2014-09”), certain balances included in the unaudited condensed consolidated statements of operations for prior periods have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on net income, cash flows or stockholders’ equity for any period presented. Recent Accounting Pronouncements Adopted During the Period In March 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2018-05, “Income Taxes (Topic 740), Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118” (“ASU 2018-05”). ASU 2018-05 amends certain SEC paragraphs pursuant to the issuance of the December 2017 SEC Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”), which provides guidance on accounting for the tax effects of the Tax Cuts and Jobs Act (“the Tax Act”). SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act’s enactment date for companies to complete its accounting under FASB Accounting Standards Codification (“ASC”) 740. In accordance with SAB 118, to the extent a company has not completed its analysis of the Tax Act but can provide a reasonable estimate, it must record a provisional estimate in its financial statements. The Company has accounted for certain tax effects of the Tax Act under the guidance of SAB 118, on a provisional basis. The Company’s accounting for certain income tax effects is incomplete due to forthcoming guidance and the ongoing analysis of final year-end data and tax positions. The Company expects to complete its analysis within the measurement period in accordance with SAB 118. In August 2016, the FASB issued Accounting Standards Update 2016-15, “ Statement of Cash Flows — Classification of Certain Cash Receipts and Cash Payments” (“ASU 2016-15”). ASU 2016-15 addresses eight specific cash flow issues with the objective of reducing existing diversity of practice. The eight specific cash flow issues contained within ASU 2016-15 are debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. ASU 2016-15 is effective for the Company for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The adoption of ASU 2016-15 did not have a material impact on our statements of cash flows. In May 2014, the FASB issued ASU 2014-09. ASU 2014-09 provides guidance concerning the recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09 is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The Company adopted ASU 2014-09 using the modified retrospective approach. The adoption of this guidance did not have a material impact on the Company’s financial statements. See Note 3 below for further details. Recent Accounting Pronouncements Issued But Not Yet Adopted In July 2017, the FASB issued Accounting Standards Update 2017-11, “ Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815) ” (“ASU 2017-11”). ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“EPS”) in accordance with Topic 260 to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company does not believe the adoption of ASU 2017-11 will have a material impact on its financial position, results of operations or cash flows. In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases (Topic 842)” (“ASU 2016-02”). ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. All leases create an asset and a liability for the lessee and therefore recognition of those lease assets and lease liabilities is required by ASU 2016-02. When measuring lease assets and liabilities, payments to be made in optional extension periods should be included if the lessee is reasonably certain to exercise the option. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. For finance leases, the Company will recognize a ROU asset and liability, initially measured at the present value of the lease payments. Interest expense will be recognized on the lease liability separately from the amortization of the ROU asset. The Company will recognize payments of principal on the lease liability within financing activities in the consolidated statement of cash flows and payments of interest within operating activities in the consolidated statement of cash flows. For operating leases, the Company will recognize a ROU asset and liability, initially measured at the present value of the lease payments. The Company will recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis and all cash payments will be recognized in operating activities within the consolidated statement of cash flows. In January 2018, the FASB issued Accounting Standards Update 2018-01, “ Leases (Topic 842)-Land Easement Practical Expedient for Transition to Topic 842 ” (“ASU 2018-01”). ASU 2018-01 permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expired prior to a company’s adoption of ASU 2016-02 and that were not accounted for as leases under previous lease guidance. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company is in the initial evaluation stage for ASU 2016-02 and related interpretations and guidance. The Company cannot reasonably quantify the impact of adoption at this time and expects to complete the assessment of ASU 2016-02 during the fourth quarter of 2018.

Impact of ASC 606 Adoption

Impact of ASC 606 Adoption	3 Months Ended
	Mar. 31, 2018
Impact of ASC 606 Adoption
Impact of ASC 606 Adoption	3. Impact of ASC 606 Adoption On January 1, 2018, the Company adopted ASC 606, Revenue from Contracts with Customers (“ASC 606”) using the modified retrospective method of transition. ASC 606 supersedes previous revenue recognition requirements in ASC 605, Revenue Recognition (“ASC 605”) and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The impact of adoption on the Company’s current period results is as follows (in thousands): Three Months Ended March 31, 2018 Under ASC 606 Under ASC 605 Increase/(Decrease) Revenues : Oil sales $ $ $ ) Natural gas liquid sales ) Natural gas sales ) Gathering and transportation ) Lease operating and workover expense ) Net income $ $ $ — Retained deficit $ ) $ ) $ — The primary impact to the Company’s revenues as a result of the adoption of ASC 606 is the netting of certain deductions and costs against revenue instead of its historical practice of presenting such expenses gross in gathering and transportation. These changes are due to analysis of the control model in ASC 606. Further discussion of the Company’s revenue recognition under ASC 606 is included below. Revenue Recognition Oil, NGLs and natural gas revenues are recognized at the point in time that control of the product is transferred to the customer and collectability is reasonably assured. Other revenue consists of iodine royalty income, which are point in time sales, and salt water disposal income, which is recognized over time. A more detailed summary of the underlying contracts that give rise to revenue and the method of recognition is included below. Natural Gas and NGLs Sales Under the Company’s gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas, sells the resulting NGLs and residue gas to third-parties and pays the Company for the NGLs and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts that the Company concluded that it was the principal, the ultimate third party is the customer, and it recognizes revenue on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Alternatively, for those contracts that the Company has concluded that it is the agent, the purchaser is its customer, and it recognizes revenue based on the net amount of the proceeds received from the purchaser. Oil Sales Under the Company’s oil sales contracts, it delivers all or a specified percentage of the crude oil production from specified leases to the purchaser at the wellhead. The Company sells oil production at the wellhead and collect an agreed-upon index price, net of applicable transport costs. The Company recognizes revenue when control transfers to the purchaser at the wellhead at the net price received. Other Revenue Other revenue consists of fees charged to outside working interest owners for salt water disposal as well as royalties received from a third-party for iodine extracted from the Company’s salt water. Salt water disposal revenue is recognized over time because the customer simultaneously receives and consumes the benefit of the salt water disposal service as the service is provided. For salt water disposal income the Company utilized the practical expedient in ASC 606-10-55-18 that states that if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date, the entity may recognize revenue in the amount to which the entity has a right to invoice. Iodine royalty revenue is recognized point-in-time when control transfers to the customer. Imbalances The Company recognizes revenue for all oil, NGLs and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company’s share of remaining proved oil and gas reserves. The Company had no significant imbalances at March 31, 2018 or December 31, 2017. Significant Judgments Principal versus agent The Company engages in various types of transactions in which midstream entities process its wet gas and, in some scenarios, subsequently market resulting NGLs and residue gas to third-party customers on its behalf, such as its percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. The Company analyzed control under ASC 606 and determined for those contracts where control passes at the wellhead, the Company acts as agent and revenue should be recognized net of amounts paid after such control passed for costs such as gathering, compression, processing and transportation, among others. The determination of control and the presentation of revenues was completed for ASC 606 purposes only. Amounts paid by the Company for royalties are calculated under a different methodology and may differ from the amount of revenues recognized under ASC 606. Transaction price allocated to remaining performance obligations A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in ASC 606-10-50-14A that states it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For salt water disposal income, the Company has utilized the practical expedient in ASC 606-10-50-14 that states that if it recognizes revenue from the satisfaction of the performance obligation in accordance with the right to invoice practical expedient then it is exempted from disclosure of the transaction price allocated to remaining performance obligations. Prior-period performance obligations The Company records revenue in the month production is delivered and control passes to the customer. However settlement statements and payment may not be received for 30 to 90 days after the date production occurs, and as a result, the Company is required to estimate the amount of production that was delivered and the price that will be received for the sale of the product. The Company utilizes its knowledge of the properties, its historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices and other pertinent factors as the basis for these estimates. The Company records the variances between its estimates and the actual amounts received in the month payment is received and such variances have historically not been significant. For the three months ended March 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	3 Months Ended
	Mar. 31, 2018
Fair Value Measurements of Financial Instruments
Fair Value Measurements of Financial Instruments	4. Fair Value Measurements of Financial Instruments Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative Instruments Commodity derivative contracts reflected in the unaudited condensed consolidated balance sheets are recorded at estimated fair value. At March 31, 2018, all of the Company’s commodity derivative contracts were with four bank counterparties and were classified as Level 2 in the fair value input hierarchy. The fair value of the Company’s commodity derivatives are determined using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. Derivative instruments listed below are presented gross and include swaps and collars that are carried at fair value. The Company records the net change in the fair value of these positions in gains (losses) on commodity derivative contracts — net in the Company’s unaudited condensed consolidated statements of operations. Fair Value Measurements at March 31, 2018 Significant Other Significant Quoted Prices in Active Observable Inputs Unobservable Inputs Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ $ — $ Commodity derivative gas swaps $ — $ $ — $ Commodity derivative oil collars $ — $ $ — $ Commodity derivative gas collars $ — $ $ — $ Total assets $ — $ $ — $ Derivative Liabilities: Commodity derivative oil swaps $ — $ ) $ — $ ) Commodity derivative gas swaps $ — $ ) $ — $ ) Commodity derivative oil collars $ — $ ) $ — $ ) Commodity derivative gas collars $ — $ ) $ — $ ) Total liabilities $ — $ ) $ — $ ) Fair Value Measurements at December 31, 2017 Significant Other Significant Quoted Prices in Active Observable Inputs Unobservable Inputs Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps $ — $ $ — $ Commodity derivative oil collars $ — $ $ — $ Commodity derivative gas collars $ — $ $ — $ Total assets $ — $ $ — $ Derivative Liabilities: Commodity derivative oil swaps $ — $ ) $ — $ ) Commodity derivative gas swaps $ — $ — $ — $ — Commodity derivative oil collars $ — $ ) $ — $ ) Commodity derivative gas collars $ — $ ) $ — $ ) Total liabilities $ — $ ) $ — $ )

Risk Management and Derivative

Risk Management and Derivative Instruments	3 Months Ended
	Mar. 31, 2018
Risk Management and Derivative Instruments
Risk Management and Derivative Instruments	5. Risk Management and Derivative Instruments The Company’s production is exposed to fluctuations in crude oil, NGLs and natural gas prices. The Company believes it is prudent to manage the variability in cash flows by, at times, entering into derivative financial instruments to economically hedge a portion of its crude 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. · Swaps: The Company receives or pays a fixed price for the commodity and pays or receives a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. · Three-way collars: A three-way collar contains a fixed floor price (long put), fixed sub-floor price (short put), and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, the Company receives the ceiling strike price and pays the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the sub-floor price, the Company receives the floor strike price and pays the market price. If the market price is below the sub-floor price, the Company receives the market price plus the difference between the floor and the sub-floor strike prices and pays the market price. These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The crude oil and natural gas reference prices upon which the commodity derivative contracts are based reflect various market indices that management believes correlates with actual prices received by the Company for its crude and natural gas production. Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties 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 at March 31, 2018, the Company would not have experienced a loss. Commodity Derivative Contracts The Company entered into various oil and natural gas derivative contracts that extend through December 31, 2020, summarized as follows: NYMEX WTI Fixed Swaps Three-Way Collars Hedge Weighted Hedge Weighted Weighted Weighted Quarter Ended: March 31, 2018(1) $ $ $ $ June 30, 2018(1) $ $ $ $ September 30, 2018(1) $ $ $ $ December 31, 2018(1) $ $ $ $ March 31, 2019(1) — $ — $ $ $ June 30, 2019(1) — $ — $ $ $ September 30, 2019(1) — $ — $ $ $ December 31, 2019(1) — $ — $ $ $ March 31, 2020(1) — $ — $ $ $ June 30, 2020(1) — $ — $ $ $ September 30, 2020(1) — $ — $ $ $ December 31, 2020(1) — $ — $ $ $ NYMEX HENRY HUB Fixed Swaps Three-Way Collars Hedge Weighted Hedge Weighted Weighted Weighted Quarter Ended: March 31, 2018(1)(2) $ $ $ $ June 30, 2018(1) $ $ $ $ September 30, 2018(1) $ $ $ $ December 31, 2018(1) $ $ $ $ March 31, 2019(1) $ $ $ $ (1) Positions shown represent open commodity derivative contract positions as of March 31, 2018. (2) During the second quarter of 2017, the Company entered into natural gas three-way collars with long call ceilings in order to offset its Q1 2018 natural gas fixed swaps. Balance Sheet Presentation The following table summarizes the net fair values of commodity derivative instruments by the appropriate balance sheet classification in the Company’s unaudited condensed consolidated balance sheets for the periods presented (in thousands): Type Balance Sheet Location (1) March 31, 2018 December 31, 2017 Gas swaps Derivative financial instruments — current assets $ — $ Oil collars Derivative financial instruments — current assets — ) Gas collars Derivative financial instruments — current assets — Total derivative financial instruments — current assets $ — $ Oil swaps Derivative financial instruments — current liabilities $ ) $ ) Gas swaps Derivative financial instruments — current liabilities ) — Oil collars Derivative financial instruments — current liabilities ) ) Gas collars Derivative financial instruments — current liabilities Total derivative financial instruments — current liabilities $ ) $ ) Oil collars Derivative financial instruments — noncurrent liabilities $ ) $ ) Gas collars Derivative financial instruments — noncurrent liabilities — ) Total derivative financial instruments — noncurrent liabilities $ ) $ ) Total derivative fair value at period end $ ) $ ) (1) The fair values of commodity derivative instruments reported in the Company’s unaudited condensed consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table summarizes the location and fair value amounts of all commodity derivative instruments in the unaudited condensed consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited condensed consolidated balance sheets for the periods presented (in thousands): March 31, 2018 Not Designated as Gross Recognized Gross Amounts Net Recognized ASC 815 Hedges Balance Sheet Location Classification Assets/Liabilities Offset Assets/Liabilities Derivative Assets: Commodity contracts Derivative financial instruments — current $ $ ) $ — Commodity contracts Derivative financial instruments — noncurrent ) — $ $ ) $ — Derivative Liabilities: Commodity contracts Derivative financial instruments — current $ ) $ $ ) Commodity contracts Derivative financial instruments — noncurrent ) ) $ ) $ $ ) December 31, 2017 Not Designated as Gross Recognized Gross Amounts Net Recognized ASC 815 Hedges Balance Sheet Location Classification Assets/Liabilities Offset Assets/Liabilities Derivative Assets: Commodity contracts Derivative financial instruments — current $ $ ) $ Commodity contracts Derivative financial instruments — noncurrent ) — $ $ ) $ Derivative Liabilities: Commodity contracts Derivative financial instruments — current $ ) $ $ ) Commodity contracts Derivative financial instruments — noncurrent ) ) $ ) $ $ ) 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 unaudited condensed consolidated statements of operations. The following table presents net cash received for commodity derivative contracts and unrealized net gains recorded by the Company related to the change in fair value of the derivative instruments in gains (losses) on commodity derivative contracts—net for the periods presented (in thousands): For the Three Months Ended March 31, 2018 2017 Net cash received (paid) for commodity derivative contracts $ ) $ Unrealized net gains (losses) ) Gains (losses) on commodity derivative contracts—net $ ) $ Cash settlements, as presented in the table above, represent realized gains (losses) related to the Company’s derivative instruments. In addition to cash settlements, the Company also recognizes fair value changes on its derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.

Property and Equipment

Property and Equipment	3 Months Ended
	Mar. 31, 2018
Property and Equipment
Property and Equipment	6. Property and Equipment Property and equipment consisted of the following as of the dates presented: March 31, 2018 December 31, 2017 (in thousands) Oil and gas properties, on the basis of full-cost accounting: Proved properties $ $ Unproved properties not being amortized Other property and equipment Less accumulated depreciation, depletion, amortization and impairment ) ) Net property and equipment $ $ Oil and Gas Properties The Company capitalizes internal costs directly related to exploration and development activities to oil and gas properties. During the three months ended March 31, 2018 and 2017, the Company capitalized the following (in thousands): 2018 2017 Internal costs capitalized to oil and gas properties (1) $ $ (1) Inclusive of $0.2 million and $0.7 million of qualifying share-based compensation expense for the three months ended March 31, 2018 and 2017, respectively. The Company accounts for its oil and gas properties under the full cost method. Under the full cost method, proceeds realized from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company’s reserve quantities are sold such that it results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income. During the three months ended March 31, 2018, the Company signed a purchase and sale agreement for its Anadarko Basin assets for $58.0 million before customary closing or post-closing adjustments. The sale of the Anadarko Basin assets will not result in a significant alteration of the full cost pool and therefore, no gain or loss will be recognized when the transaction closes. During the three months ended March 31, 2017, the Company disposed of certain oil and gas equipment for cash proceeds of $1.4 million, which were reflected as reduction of oil and gas properties with no gain or loss recognized. The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of the Company’s oil and gas properties. The capitalized costs of oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“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 held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved 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 unaudited condensed consolidated statements of operations. The Company did not record an impairment of oil and gas properties during the three months ended March 31, 2018 or 2017. Depreciation, depletion and amortization is calculated using the Units of Production Method (“UOP”). The UOP calculation multiplies the percentage of total estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reservoirs are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated depreciation, depletion, amortization and impairment, 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. The following table presents depletion expense related to oil and gas properties for the periods presented: Three Months Ended Three Months Ended 2018 2017 2018 2017 (in thousands) (per Boe) Depletion expense $ $ $ $ Depreciation on other property and equipment Depreciation, depletion, and amortization $ $ $ $ Oil and gas unproved properties include costs that are not being depleted or amortized. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are transferred to proved properties and become part of our depletion base and subject to the full cost ceiling limitation. No impairment of unproved properties was recorded during the three months ended March 31, 2018 or 2017. Unproved property was $7.1 million at March 31, 2018 and December 31, 2017, 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 calculated principally using the straight-line method over the estimated useful lives of the assets, which range from two to ten years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.

Accrued Liabilities

Accrued Liabilities	3 Months Ended
	Mar. 31, 2018
Accrued Liabilities
Accrued Liabilities	7. Accrued Liabilities The following table presents the components of accrued liabilities as of the dates presented: March 31, 2018 December 31, 2017 (in thousands) Accrued oil and gas capital expenditures $ $ Accrued revenue and royalty distributions Accrued lease operating and workover expense Accrued interest Accrued taxes Compensation and benefit related accruals Other Accrued liabilities $ $

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2018
Asset Retirement Obligations
Asset Retirement Obligations	8. Asset Retirement Obligations Asset Retirement Obligations (“AROs”) represent the estimated future abandonment costs of tangible assets, such as wells, service assets and other facilities. The estimated fair value of the AROs at inception are capitalized as part of the carrying amount of the related long-lived assets.The following table reflects the changes in the Company’s AROs for the periods presented (in thousands): Three Months Ended 2018 2017 Asset retirement obligations — beginning of period $ $ Liabilities incurred Revisions — — Liabilities settled ) ) Liabilities eliminated through asset sales ) — Current period accretion expense Asset retirement obligations — end of period $ $

Debt

Debt	3 Months Ended
	Mar. 31, 2018
Debt
Debt	9. Debt Reserves-Based Revolving Credit Facility (“RBL”) At March 31, 2018 and December 31, 2017, the Company maintained an RBLwith a borrowing base of $170.0 million. During the three months ended March 31, 2018, the Company paid down $50.0 million on its RBL. At March 31, 2018 and December 31, 2017, the Company had $78.1 million and $128.1 million, respectively, drawn on the RBL and had outstanding letters of credit obligations totaling $1.9 million. As a result, at March 31, 2018, the Company had $90.0 million of availability on the RBL. The RBL matures on September 30, 2020 and bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. At March 31, 2018, the weighted average interest rate, including amortization expense of deferred financing costs, was 6.9%. Unamortized debt issuance costs of $1.1 million and $1.2 million associated with the RBL are included in other noncurrent assets on the unaudited condensed consolidated balance sheets at March 31, 2018 and December 31, 2017, respectively. In addition to interest expense, the RBL requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of 0.50% per annum based on the average daily amount by which the borrowing base exceeds outstanding borrowings during each quarter. The RBL, as amended, includes certain financial maintenance covenants that are required to be calculated on a quarterly basis for compliance purposes. These financial maintenance covenants include EBITDA to interest expense for the trailing four fiscal quarters of not less than 2.50:1.00 and a limitation of Total Net Indebtedness (as defined in the RBL) to EBITDA for the trailing four fiscal quarters of not more than 4.00:1.00. In addition, the RBL contains various other covenants that, among other things, may restrict the Company’s ability to: (i) incur additional indebtedness or guarantee indebtedness (ii) make loans and investments; (iii) pay dividends on capital stock and make other restricted payments, including the prepayment or redemption of other indebtedness; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with the Company’s affiliates; (vii) acquire, consolidate or merge with another entity upon certain terms and conditions; (viii) sell all or substantially all of the Company’s assets; (ix) prepay, redeem or repurchase certain debt; (x) alter the business the Company conducts and make amendments to the Company’s organizational documents, (xi) enter into certain derivative transactions and (xii) enter into certain marketing agreements and take-or-pay arrangements. The Company was in compliance with all debt covenants at March 31, 2018. On April 19, 2018, the Company’s borrowing base was redetermined at the existing amount of $170.0 million. The Company’s Anadarko Basin assets in Texas and Oklahoma were excluded from the redetermination of the borrowing base. The Company believes the carrying amount of the RBL at March 31, 2018 approximates its fair value (Level 2) due to the variable nature of the RBL interest rate.

Equity and Share-Based Compensa

Equity and Share-Based Compensation	3 Months Ended
	Mar. 31, 2018
Equity and Share-Based Compensation
Equity and Share-Based Compensation	10. Equity and Share-Based Compensation Common Shares Share Activity The following table summarizes changes in the number of shares of common stock and treasury stock during the three months ended March 31, 2018: Common Treasury Share count as of December 31, 2017 ) Common stock issued — Acquisition of treasury stock — ) Share count as of March 31, 2018 ) (1) Treasury stock represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory tax withholding requirements. Share-Based Compensation 2016 Long Term Incentive Plan On October 21, 2016 (the “Effective Date”), the Company established the 2016 LTIP and filed a Form S-8 with the SEC, registering 3,513,950 shares for issuance under the terms of the 2016 LTIP to employees, directors and certain other persons (the “Award Shares”). The types of awards that may be granted under the 2016 LTIP include stock options, restricted stock units, restricted stock, performance awards and other forms of awards granted or denominated in shares of common stock of the reorganized Company, as well as certain cash-based awards (the “Awards”). The terms of each award are as determined by the Compensation Committee of the Board of Directors. Awards that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future issuance under the 2016 LTIP. At March 31, 2018, 1,763,238 Award Shares remain available for issuance under the terms of the 2016 LTIP. Restricted Stock Units At March 31, 2018, the Company had 491,693 non-vested restricted stock units outstanding to employees and non-employee directors pursuant to the 2016 LTIP, excluding restricted stock units issued to non-employee directors containing a market condition, which are discussed below. During the three months ended March 31, 2018, 269,468 non-vested restricted stock units were issued to employees and non-employee directors. Restricted stock units granted to employees in 2018 under the 2016 LTIP vest ratably over a period of three years: one-third will vest on December 31, 2018, an additional one-third will vest on December 31, 2019 and the final one-third will vest on December 31, 2020. Restricted stock units granted to non-employee directors during 2018 vest on the first to occur of (i) December 31, 2018, (ii) the date the non-employee director ceases to be a director of the Board (other than for cause), (iii) the director’s death, (iv) the director’s disability or (v) a change in control of the Company. The fair value of restricted stock units granted to employees and non-employee directors during 2018 was based on grant date fair value of the Company’s common stock. Compensation expense is recognized ratably over the requisite service period. The following table summarizes the Company’s non-vested restricted stock unit award activity for the three months ended March 31, 2018: Restricted Stock Weighted Average Non-vested shares outstanding at December 31, 2017 $ Granted $ Vested(1) ) $ Forfeited — $ — Non-vested shares outstanding at March 31, 2018 $ (1) Vested restricted stock units include 102,092 shares in which vesting was accelerated as a result of a reduction in workforce that occurred during the three months ended March 31, 2018. Unrecognized expense as of March 31, 2018 for all outstanding restricted stock units under the 2016 LTIP Plan was $5.5 million and will be recognized over a weighted average period of 1.4 years. Stock Options At March 31, 2018, the Company had 143,086 non-vested options outstanding pursuant to the 2016 LTIP. Stock Option Awards granted under the 2016 LTIP vest ratably over a period of three years: one-sixth will vest on the six-month anniversary of the grant date, an additional one-sixth will vest on the twelve-month anniversary of the grant date, an additional one-third will vest on the twenty-four month anniversary of the grant date and the final one-third will vest on the thirty-six month anniversary of the grant date. Stock Option Awards expire 10 years from the grant date. There were no issuances of stock options during the three months ended March 31, 2018. The following table summarizes the Company’s 2016 LTIP non-vested stock option activity for the three months ended March 31, 2018: Options Range of Weighted Average Weighted Stock options outstanding at December 31, 2017 $ Granted — $ — $ — — Vested(1) ) $ 19.08-19.66 $ Forfeited — $ — $ — — Stock options outstanding at March 31, 2018 $ Vested and exercisable at end of period(2) $ 19.08-20.97 $ (1) Vested stock options include 102,092 options in which vesting was accelerated as a result of a reduction in workforce that occurred during the three months ended March 31, 2018. (2) Vested and exercisable options at March 31, 2018, had no aggregate intrinsic value. Unrecognized expense as of March 31, 2018 for all outstanding stock options under the 2016 LTIP Plan was $0.6 million and will be recognized over a weighted average period of 1.1 years. Non-Employee Director Restricted Stock Units Containing a Market Condition On November 23, 2016, the Company issued restricted stock units to non-employee directors that contain a market vesting condition. These restricted stock units will vest (i) on the first business day following the date on which the trailing 60-day average share price (including any dividends paid) of the Company’s common stock is equal to or greater than $30.00 or (ii) upon a change in control (as defined in the 2016 LTIP) of the Company. Additionally, all unvested restricted stock units containing a market vesting condition will be immediately forfeited upon the first to occur of (i) the fifth anniversary of the grant date or (ii) any participant’s termination as a director for any reason (except for a termination as part of a change in control of the Company). These restricted stock awards are accounted for as liability awards under FASB ASC 718 — Stock Compensation (“ASC 718”) as the awards allow for the withholding of taxes at the discretion of the non-employee director. The liability is re-measured, with a corresponding adjustment to earnings, at each fiscal quarter-end during the performance cycle. The derived service period related to these awards ended in November of 2017. As such, changes in the fair value of the liability and related compensation expense of these awards are no longer recognized pro-rata over the period for which service has already been provided but rather are compensation cost in the period in which the changes occur. As there are inherent uncertainties related to these factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded compensation may not accurately reflect the amount ultimately earned by the non-employee directors. At March 31, 2018 the Company recorded a $0.5 million liability included within accrued liabilities on the unaudited condensed consolidated balance sheets related to the market condition awards. The weighted-average fair value of the restricted stock units containing a market condition was $6.90 at March 31, 2018. As of March 31, 2018, there was no unrecognized stock-based compensation expense related to market condition awards. Chief Executive Officer (“CEO”) Restricted Stock Units Containing a Market Condition On November 1, 2017, the Company issued restricted stock units to its CEO that contain a market vesting condition. These restricted stock units will vest, if at all, based on the Company’s total stockholder return for the performance period of October 25, 2017 through October 31, 2020. Market conditions under this grant are (1) with respect to 50% of the RSUs granted, the Company’s cumulative total shareholder return (“TSR”) which is defined as the change in the value of the stock over the performance period with the beginning and ending stock price based on a 20-day average stock price and (2) with respect to the remaining 50% of the RSUs granted, the percentile rank of the Company’s TSR compared to the TSR of the Peer Group over the performance period (“Relative TSR”). To the extent that actual TSR or Relative TSR for the performance period is between specified vesting levels, the portion of the RSUs that shall become vested based on actual and Relative TSR performance shall be determined on a pro-rata basis using straight-line interpolation; provided that the maximum portion of the RSUs that may become vested based on actual cumulative TSR or Relative TSR for the performance period shall not exceed 120% of the awards granted. The RSUs issued to the CEO containing a market condition have a service period of three years. The share-based compensation costs related to the CEO restricted stock units containing a market condition recognized as general and administrative expense by the Company was $0.1 million at March 31, 2018. As of March 31, 2018, unrecognized stock-based compensation related to CEO RSUs containing a market condition was $1.3 million and will be recognized over a weighted-average period of 2.6 years. Performance Stock Units Issued to Certain Members of Executive Management Containing a Market Condition On March 1, 2018, the Company issued restricted stock units to certain members of executive management that contain a market vesting condition. These restricted stock units will vest, if at all, based on the Company’s total stockholder return for the performance period of January 1, 2018 through December 31, 2020. Market conditions under this grant relate to the Company’s Relative TSR as follows: Relative TSR for the Performance Period Vesting as % of RSUs Granted Maximum Top 35% or better Relative TSR to Peer Group % Target Top 50% or better Relative TSR to Peer Group % Threshold Top 60% or better Relative TSR to Peer Group % Below Threshold Less than 60% of Relative TSR to Peer Group % To the extent that the Relative TSR for the performance period is between specified vesting levels, the portion of the restricted stock units that become vested based on the Relative TSR performance shall be determined on a pro-rata basis using straight-line interpolation; provided that the maximum portion of the restricted stock units that may become vested based on the Relative TSR for the performance period shall not exceed 150% of the awards granted. In addition, if the Relative TSR for the Company is negative over the performance period, vesting of these performance stock units is limited to no more than 100%. If a member of executive management terminates employment prior to vesting, the outstanding award is forfeited. Executive management restricted stock units with a market condition are subject to accelerated vesting in the event the executive’s employment is terminated prior to vesting by the Company without “Cause” or by the participant with “Good Reason” (each, as defined in the 2016 LTIP) or due to the executive’s death or disability. Upon a change in control (as defined in the 2016 LTIP), the compensation committee of the board of directors could (1) accelerate all or a portion of the award, (2) cancel all of the award and pay cash, stock or combination equal to the change in control price, (3) provide for the assumption or substitution or continuation by the successor company, (4) certify to the extent to which the vesting conditions had been achieved prior to the conclusion of the performance period or (5) adjust restricted stock units to reflect the change in control. These restricted stock awards are accounted for as equity awards under ASC 718 as the awards are settled in shares of the Company with no additional settlement options permitted. At the grant date, the Company estimated the fair value of this equity award. The compensation expense of this award each period is recognized by dividing the fair value of the total award by the requisite service period and recording the pro rata share for the period for which service has already been provided. As there are inherent uncertainties related to these factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded compensation may not accurately reflect the amount ultimately earned by the executives. A Monte Carlo simulation was used in order to determine the fair value of these awards at the grant date. The assumptions used to estimate the fair value of the executive management restricted stock unit awards with a market condition are as follows: Awards Issued Risk-free interest rate (1) Dividend yield — Expected volatility 40.0% - 127.2% Calculated fair value per unit $ (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the life of the executives restricted stock unit award with a market condition. The restricted stock units issued to executive management containing a market condition have a service period of three years. The share-based compensation costs related to executive management’s restricted stock units containing a market condition recognized as general and administrative expense by the Company was $0.1 million for the period ended March 31, 2018. As of March 31, 2018, unrecognized stock-based compensation related to executive management’s restricted stock units containing a market condition was $1.2 million and will be recognized over a weighted-average period of 2.8 years. The following table reflects the outstanding Executive Management restricted stock units containing a market condition for the three months ended March 31, 2018: Shares Weighted Average Outstanding at December 31, 2017 — $ — Granted $ Vested — $ — Forfeited — $ — Outstanding at March 31, 2018 $

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2018
Income Taxes
Income Taxes	11. Income Taxes On December 22, 2017, the Tax Act was enacted into law and the new legislation contains several key tax provisions that affected the Company, primarily a reduction of the corporate income tax rate to 21% effective January 1, 2018. The Company was required to recognize the effect of the tax law changes in the period of enactment. The Company re-measured its U.S. deferred tax assets and liabilities as well as reassessed the net realizability of its deferred tax assets and liabilities. In December 2017, the SEC staff issued SAB 118, which allows the Company to record provisional amounts during a measurement period not to extend beyond one year of the enactment date. As the Tax Act was passed late in the fourth quarter of 2017, ongoing guidance from the Department of Treasury and state agencies and accounting interpretation is expected to be issued over the next 9-12 months. Therefore, for the three months ended March 31, 2018, the Company considered the accounting of certain items to be incomplete due to forthcoming guidance and the ongoing analysis of final year-end data and tax positions. For the three months ended March 31, 2018, the Company has estimated deductions of $9.0 million associated with the full expensing of the costs of qualified property that were incurred and placed into service during the period from January 1, 2018 to March 31, 2018. The Company continues to analyze assets placed into service after September 27, 2017, but not qualifying for full expensing as a result of being acquired under an agreement entered into prior to that date. In addition, further guidance and analysis is required in order to review the terms of the Company’s compensation plans and agreements and assess the impact of transitional guidance related to IRC Section 162(m) on awards granted prior to November 2, 2017, subject to the grandfather provisions. As a result, the Company has not adjusted certain tax items previously reported on its financial statements for IRC Section 162(m) until the Company is able to obtain sufficient information to make a reasonable estimate of the effects of the Tax Act. The Company expects to complete its analysis within the measurement period in accordance with SAB No. 118. For the three months ended March 31, 2018, the Company recorded no income tax expense or benefit. The significant difference between its effective tax rate and the federal statutory income tax rate of 21% is primarily due to the effect of changes in the Company’s valuation allowance. During the three months ended March 31, 2018, the Company’s valuation allowance decreased by $1.1 million from December 31, 2017, bringing the total valuation allowance to $119.0 million at March 31, 2018. A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its deferred tax assets are realizable. The Company expects to incur a tax loss in the current year due to the flexibility in deducting or capitalizing current year intangible drilling costs; thus no current income taxes are anticipated to be paid.

Income Per Share

Income Per Share	3 Months Ended
	Mar. 31, 2018
Income Per Share
Income Per Share	12. Income Per Share The following table provides a reconciliation of net income attributable to common shareholders and weighted average common shares outstanding for basic and diluted income per share for the periods presented: Three Months Ended March 31, 2018 2017 (in thousands, except per share amounts) Net Income: Net income $ $ Participating securities—non-vested restricted stock ) ) Basic and diluted income $ $ Common Shares: Common shares outstanding — basic (1) Dilutive effect of potential common shares — — Common shares outstanding — diluted Net Income Per Share: Basic $ $ Diluted $ $ Antidilutive stock options (2) Antidilutive warrants (3) (1) Weighted-average common shares outstanding for basic and diluted income per share purposes includes 9,407 and 17,533 shares of common stock that, while not issued and outstanding at March 31, 2018 or 2017, respectively, are required by the First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate as filed on September 28, 2016 (the “Plan”) to be issued. Weighted-average common shares outstanding for basic and diluted income per share purposes also includes 57,856 director shares that vested as of December 31, 2017, but final issuance of the vested shares was deferred by the non-employee directors until 2020. (2) Amount represents options to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect. (3) Amount represents warrants to purchase common stock that are excluded from the diluted net income per share calculations because of their antidilutive effect.

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2018
Related Party Transactions
Related Party Transactions	13. Related Party Transactions During 2017, the Company entered into an arrangement with EcoStim Energy Solutions, Inc. (“EcoStim”) for well stimulation and completion services. EcoStim is an affiliate of Fir Tree Inc. who is a holder of the Company’s outstanding common stock. The Company had $2.1 million included in accounts payable in the Company’s unaudited condensed consolidated balance sheets at December 31, 2017 to EcoStim that was paid during the three months ended March 31, 2018. No transactions with EcoStim occurred during the three months ended March 31, 2017.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2018
Commitments and Contingencies
Commitments and Contingencies	14. Commitments and Contingencies The Company is involved in various matters incidental to its operations and business that might give rise to a loss contingency. These matters may include legal and regulatory proceedings, commercial disputes, claims from royalty, working interest and surface owners, property damage and personal injury claims and environmental or other matters. In addition, the Company may be subject to customary audits by governmental authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as compliance with unclaimed property (escheatment) requirements and other laws. Further, other parties with an interest in wells operated by the Company have the ability under various contractual agreements to perform audits of its joint interest billing practices. The Company vigorously defends itself in these matters. If the Company determines that an unfavorable outcome or loss of a particular matter is probable and the amount of loss can be reasonably estimated, it accrues a liability for the contingent obligation. As new information becomes available or as a result of legal or administrative rulings in similar matters or a change in applicable law, the Company’s conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. The impact of subsequent changes to the Company’s accruals could have a material effect on its results of operations. As of March 31, 2018 and December 31, 2017, the Company’s total accrual for all loss contingencies was $1.1 million.

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2018
Summary of Significant Accounting Policies
Basis of Presentation	Basis of Presentation These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“US GAAP”) for complete consolidated financial statements, and should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2017 included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 14, 2018. All intercompany transactions have been eliminated in consolidation. In the opinion of the Company’s management, the accompanying unaudited condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessary to fairly present the financial position as of, and the results of operations for, all periods presented. In preparing the accompanying unaudited condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the unaudited condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results. As a result of the adoption of Accounting Standards Update 2014-09, “Revenue from Contracts with Customers (Topic 606) ” (“ASU 2014-09”), certain balances included in the unaudited condensed consolidated statements of operations for prior periods have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on net income, cash flows or stockholders’ equity for any period presented.
Recent Accounting Pronouncements Adopted and Not Yet Adopted During the Period	Recent Accounting Pronouncements Adopted During the Period In March 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2018-05, “Income Taxes (Topic 740), Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118” (“ASU 2018-05”). ASU 2018-05 amends certain SEC paragraphs pursuant to the issuance of the December 2017 SEC Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”), which provides guidance on accounting for the tax effects of the Tax Cuts and Jobs Act (“the Tax Act”). SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act’s enactment date for companies to complete its accounting under FASB Accounting Standards Codification (“ASC”) 740. In accordance with SAB 118, to the extent a company has not completed its analysis of the Tax Act but can provide a reasonable estimate, it must record a provisional estimate in its financial statements. The Company has accounted for certain tax effects of the Tax Act under the guidance of SAB 118, on a provisional basis. The Company’s accounting for certain income tax effects is incomplete due to forthcoming guidance and the ongoing analysis of final year-end data and tax positions. The Company expects to complete its analysis within the measurement period in accordance with SAB 118. In August 2016, the FASB issued Accounting Standards Update 2016-15, “ Statement of Cash Flows — Classification of Certain Cash Receipts and Cash Payments” (“ASU 2016-15”). ASU 2016-15 addresses eight specific cash flow issues with the objective of reducing existing diversity of practice. The eight specific cash flow issues contained within ASU 2016-15 are debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. ASU 2016-15 is effective for the Company for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The adoption of ASU 2016-15 did not have a material impact on our statements of cash flows. In May 2014, the FASB issued ASU 2014-09. ASU 2014-09 provides guidance concerning the recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09 is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The Company adopted ASU 2014-09 using the modified retrospective approach. The adoption of this guidance did not have a material impact on the Company’s financial statements. See Note 3 below for further details. Recent Accounting Pronouncements Issued But Not Yet Adopted In July 2017, the FASB issued Accounting Standards Update 2017-11, “ Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815) ” (“ASU 2017-11”). ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“EPS”) in accordance with Topic 260 to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company does not believe the adoption of ASU 2017-11 will have a material impact on its financial position, results of operations or cash flows. In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases (Topic 842)” (“ASU 2016-02”). ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. All leases create an asset and a liability for the lessee and therefore recognition of those lease assets and lease liabilities is required by ASU 2016-02. When measuring lease assets and liabilities, payments to be made in optional extension periods should be included if the lessee is reasonably certain to exercise the option. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. For finance leases, the Company will recognize a ROU asset and liability, initially measured at the present value of the lease payments. Interest expense will be recognized on the lease liability separately from the amortization of the ROU asset. The Company will recognize payments of principal on the lease liability within financing activities in the consolidated statement of cash flows and payments of interest within operating activities in the consolidated statement of cash flows. For operating leases, the Company will recognize a ROU asset and liability, initially measured at the present value of the lease payments. The Company will recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis and all cash payments will be recognized in operating activities within the consolidated statement of cash flows. In January 2018, the FASB issued Accounting Standards Update 2018-01, “ Leases (Topic 842)-Land Easement Practical Expedient for Transition to Topic 842 ” (“ASU 2018-01”). ASU 2018-01 permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expired prior to a company’s adoption of ASU 2016-02 and that were not accounted for as leases under previous lease guidance. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company is in the initial evaluation stage for ASU 2016-02 and related interpretations and guidance. The Company cannot reasonably quantify the impact of adoption at this time and expects to complete the assessment of ASU 2016-02 during the fourth quarter of 2018.

Impact of ASC 606 Adoption (Tab

Impact of ASC 606 Adoption (Tables)	3 Months Ended
	Mar. 31, 2018
Impact of ASC 606 Adoption
Impact of adoption on the Company's current period results	The impact of adoption on the Company’s current period results is as follows (in thousands): Three Months Ended March 31, 2018 Under ASC 606 Under ASC 605 Increase/(Decrease) Revenues : Oil sales $ $ $ ) Natural gas liquid sales ) Natural gas sales ) Gathering and transportation ) Lease operating and workover expense ) Net income $ $ $ — Retained deficit $ ) $ ) $ —

Fair Value Measurements of Fi24

Fair Value Measurements of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2018
Fair Value Measurements of Financial Instruments
Schedule of derivative instruments measured at fair value	Fair Value Measurements at March 31, 2018 Significant Other Significant Quoted Prices in Active Observable Inputs Unobservable Inputs Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ $ — $ Commodity derivative gas swaps $ — $ $ — $ Commodity derivative oil collars $ — $ $ — $ Commodity derivative gas collars $ — $ $ — $ Total assets $ — $ $ — $ Derivative Liabilities: Commodity derivative oil swaps $ — $ ) $ — $ ) Commodity derivative gas swaps $ — $ ) $ — $ ) Commodity derivative oil collars $ — $ ) $ — $ ) Commodity derivative gas collars $ — $ ) $ — $ ) Total liabilities $ — $ ) $ — $ ) Fair Value Measurements at December 31, 2017 Significant Other Significant Quoted Prices in Active Observable Inputs Unobservable Inputs Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps $ — $ $ — $ Commodity derivative oil collars $ — $ $ — $ Commodity derivative gas collars $ — $ $ — $ Total assets $ — $ $ — $ Derivative Liabilities: Commodity derivative oil swaps $ — $ ) $ — $ ) Commodity derivative gas swaps $ — $ — $ — $ — Commodity derivative oil collars $ — $ ) $ — $ ) Commodity derivative gas collars $ — $ ) $ — $ ) Total liabilities $ — $ ) $ — $ )

Risk Management and Derivativ25

Risk Management and Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2018
Risk Management and Derivative Instruments
Schedule of commodity derivative contracts	NYMEX WTI Fixed Swaps Three-Way Collars Hedge Weighted Hedge Weighted Weighted Weighted Quarter Ended: March 31, 2018(1) $ $ $ $ June 30, 2018(1) $ $ $ $ September 30, 2018(1) $ $ $ $ December 31, 2018(1) $ $ $ $ March 31, 2019(1) — $ — $ $ $ June 30, 2019(1) — $ — $ $ $ September 30, 2019(1) — $ — $ $ $ December 31, 2019(1) — $ — $ $ $ March 31, 2020(1) — $ — $ $ $ June 30, 2020(1) — $ — $ $ $ September 30, 2020(1) — $ — $ $ $ December 31, 2020(1) — $ — $ $ $ NYMEX HENRY HUB Fixed Swaps Three-Way Collars Hedge Weighted Hedge Weighted Weighted Weighted Quarter Ended: March 31, 2018(1)(2) $ $ $ $ June 30, 2018(1) $ $ $ $ September 30, 2018(1) $ $ $ $ December 31, 2018(1) $ $ $ $ March 31, 2019(1) $ $ $ $ (1) Positions shown represent open commodity derivative contract positions as of March 31, 2018. (2) During the second quarter of 2017, the Company entered into natural gas three-way collars with long call ceilings in order to offset its Q1 2018 natural gas fixed swaps.
Schedule of open commodity derivative contract positions	The following table summarizes the net fair values of commodity derivative instruments by the appropriate balance sheet classification in the Company’s unaudited condensed consolidated balance sheets for the periods presented (in thousands): Type Balance Sheet Location (1) March 31, 2018 December 31, 2017 Gas swaps Derivative financial instruments — current assets $ — $ Oil collars Derivative financial instruments — current assets — ) Gas collars Derivative financial instruments — current assets — Total derivative financial instruments — current assets $ — $ Oil swaps Derivative financial instruments — current liabilities $ ) $ ) Gas swaps Derivative financial instruments — current liabilities ) — Oil collars Derivative financial instruments — current liabilities ) ) Gas collars Derivative financial instruments — current liabilities Total derivative financial instruments — current liabilities $ ) $ ) Oil collars Derivative financial instruments — noncurrent liabilities $ ) $ ) Gas collars Derivative financial instruments — noncurrent liabilities — ) Total derivative financial instruments — noncurrent liabilities $ ) $ ) Total derivative fair value at period end $ ) $ ) (1) The fair values of commodity derivative instruments reported in the Company’s unaudited condensed consolidated balance sheets are subject to netting arrangements and qualify for net presentation.
Summary of location and fair values amounts of all commodity derivative instruments as well as the gross recognized derivative assets, liabilities and amounts offset in the condensed consolidated balance sheet	The following table summarizes the location and fair value amounts of all commodity derivative instruments in the unaudited condensed consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited condensed consolidated balance sheets for the periods presented (in thousands): March 31, 2018 Not Designated as Gross Recognized Gross Amounts Net Recognized ASC 815 Hedges Balance Sheet Location Classification Assets/Liabilities Offset Assets/Liabilities Derivative Assets: Commodity contracts Derivative financial instruments — current $ $ ) $ — Commodity contracts Derivative financial instruments — noncurrent ) — $ $ ) $ — Derivative Liabilities: Commodity contracts Derivative financial instruments — current $ ) $ $ ) Commodity contracts Derivative financial instruments — noncurrent ) ) $ ) $ $ ) December 31, 2017 Not Designated as Gross Recognized Gross Amounts Net Recognized ASC 815 Hedges Balance Sheet Location Classification Assets/Liabilities Offset Assets/Liabilities Derivative Assets: Commodity contracts Derivative financial instruments — current $ $ ) $ Commodity contracts Derivative financial instruments — noncurrent ) — $ $ ) $ Derivative Liabilities: Commodity contracts Derivative financial instruments — current $ ) $ $ ) Commodity contracts Derivative financial instruments — noncurrent ) ) $ ) $ $ )
Schedule of net cash received for commodity derivative contracts and unrealized net gains related to the change in fair value of derivative instruments - net for the periods	The following table presents net cash received for commodity derivative contracts and unrealized net gains recorded by the Company related to the change in fair value of the derivative instruments in gains (losses) on commodity derivative contracts—net for the periods presented (in thousands): For the Three Months Ended March 31, 2018 2017 Net cash received (paid) for commodity derivative contracts $ ) $ Unrealized net gains (losses) ) Gains (losses) on commodity derivative contracts—net $ ) $

Property and Equipment (Tables)

Property and Equipment (Tables)	3 Months Ended
	Mar. 31, 2018
Property and Equipment
Schedule of property and equipment	March 31, 2018 December 31, 2017 (in thousands) Oil and gas properties, on the basis of full-cost accounting: Proved properties $ $ Unproved properties not being amortized Other property and equipment Less accumulated depreciation, depletion, amortization and impairment ) ) Net property and equipment $ $
Schedule of costs incurred in oil and natural gas property acquisition, exploration and development activities	The Company capitalizes internal costs directly related to exploration and development activities to oil and gas properties. During the three months ended March 31, 2018 and 2017, the Company capitalized the following (in thousands): 2018 2017 Internal costs capitalized to oil and gas properties (1) $ $ (1) Inclusive of $0.2 million and $0.7 million of qualifying share-based compensation expense for the three months ended March 31, 2018 and 2017, respectively.
Schedule of depletion expense related to oil and gas properties	Three Months Ended Three Months Ended 2018 2017 2018 2017 (in thousands) (per Boe) Depletion expense $ $ $ $ Depreciation on other property and equipment Depreciation, depletion, and amortization $ $ $ $

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	3 Months Ended
	Mar. 31, 2018
Accrued Liabilities
Schedule of the components of accrued liabilities	March 31, 2018 December 31, 2017 (in thousands) Accrued oil and gas capital expenditures $ $ Accrued revenue and royalty distributions Accrued lease operating and workover expense Accrued interest Accrued taxes Compensation and benefit related accruals Other Accrued liabilities $ $

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2018
Asset Retirement Obligations
Schedule of change in the AROs	The following table reflects the changes in the Company’s AROs for the periods presented (in thousands): Three Months Ended 2018 2017 Asset retirement obligations — beginning of period $ $ Liabilities incurred Revisions — — Liabilities settled ) ) Liabilities eliminated through asset sales ) — Current period accretion expense Asset retirement obligations — end of period $ $

Equity and Share-Based Compen29

Equity and Share-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2018
Equity and Share-Based Compensation
Summary of changes in the number of shares of common stock and treasury stock	Common Treasury Share count as of December 31, 2017 ) Common stock issued — Acquisition of treasury stock — ) Share count as of March 31, 2018 ) (1) Treasury stock represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory tax withholding requirements.
Summary of non-vested restricted stock unit award activity	Restricted Stock Weighted Average Non-vested shares outstanding at December 31, 2017 $ Granted $ Vested(1) ) $ Forfeited — $ — Non-vested shares outstanding at March 31, 2018 $ (1) Vested restricted stock units include 102,092 shares in which vesting was accelerated as a result of a reduction in workforce that occurred during the three months ended March 31, 2018.
Summary of non-vested stock option activity	Options Range of Weighted Average Weighted Stock options outstanding at December 31, 2017 $ Granted — $ — $ — — Vested(1) ) $ 19.08-19.66 $ Forfeited — $ — $ — — Stock options outstanding at March 31, 2018 $ Vested and exercisable at end of period(2) $ 19.08-20.97 $ (1) Vested stock options include 102,092 options in which vesting was accelerated as a result of a reduction in workforce that occurred during the three months ended March 31, 2018. (2) Vested and exercisable options at March 31, 2018, had no aggregate intrinsic value.
Schedule of executive officer restricted stock units containing a market condition with respect to RSUs granted	Relative TSR for the Performance Period Vesting as % of RSUs Granted Maximum Top 35% or better Relative TSR to Peer Group % Target Top 50% or better Relative TSR to Peer Group % Threshold Top 60% or better Relative TSR to Peer Group % Below Threshold Less than 60% of Relative TSR to Peer Group %
Schedule of executive officer restricted stock units with market condition valuation assumptions	Awards Issued Risk-free interest rate (1) Dividend yield — Expected volatility 40.0% - 127.2% Calculated fair value per unit $ (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the life of the executives restricted stock unit award with a market condition.
Schedule of executive officer restricted stock units with market condition award activity	Shares Weighted Average Outstanding at December 31, 2017 — $ — Granted $ Vested — $ — Forfeited — $ — Outstanding at March 31, 2018 $

Income Per Share (Tables)

Income Per Share (Tables)	3 Months Ended
	Mar. 31, 2018
Income Per Share
Schedule of reconciliation of net income attributable to common shareholders and weighted average common shares outstanding for basic and diluted earnings per share	Three Months Ended March 31, 2018 2017 (in thousands, except per share amounts) Net Income: Net income $ $ Participating securities—non-vested restricted stock ) ) Basic and diluted income $ $ Common Shares: Common shares outstanding — basic (1) Dilutive effect of potential common shares — — Common shares outstanding — diluted Net Income Per Share: Basic $ $ Diluted $ $ Antidilutive stock options (2) Antidilutive warrants (3) (1) Weighted-average common shares outstanding for basic and diluted income per share purposes includes 9,407 and 17,533 shares of common stock that, while not issued and outstanding at March 31, 2018 or 2017, respectively, are required by the First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate as filed on September 28, 2016 (the “Plan”) to be issued. Weighted-average common shares outstanding for basic and diluted income per share purposes also includes 57,856 director shares that vested as of December 31, 2017, but final issuance of the vested shares was deferred by the non-employee directors until 2020. (2) Amount represents options to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect. (3) Amount represents warrants to purchase common stock that are excluded from the diluted net income per share calculations because of their antidilutive effect.

Organization and Business (Deta

Organization and Business (Details)	3 Months Ended
	Mar. 31, 2018segment
Organization and Business
Number of reportable segments	1

Impact of ASC 606 Adoption (Det

Impact of ASC 606 Adoption (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	$ 48,905	$ 65,015
Gathering and transportation	57	3,687
Lease operating and workover expense	14,808	15,852
Net Income	4,004	18,485
Retained deficit	(71,143)		$ (75,147)
Oil
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	32,414	$ 31,036
Natural gas liquid
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	11,038
Natural gas
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	8,337
ASU 2014-09 | Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Gathering and transportation	3,070
Lease operating and workover expense	14,895
Net Income	4,004
Retained deficit	(71,143)
ASU 2014-09 | Increase/(Decrease)
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Gathering and transportation	(3,013)
Lease operating and workover expense	(87)
ASU 2014-09 | Oil | Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	32,424
ASU 2014-09 | Oil | Increase/(Decrease)
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	(10)
ASU 2014-09 | Natural gas liquid | Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	11,065
ASU 2014-09 | Natural gas liquid | Increase/(Decrease)
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	(27)
ASU 2014-09 | Natural gas | Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	11,400
ASU 2014-09 | Natural gas | Increase/(Decrease)
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	$ (3,063)

Fair Value Measurements of Fi33

Fair Value Measurements of Financial Instruments (Details) $ in Thousands	Mar. 31, 2018USD ($)item	Dec. 31, 2017USD ($)
Fair Value Measurements of Financial Instruments
Number of bank counterparties for company's commodity derivative contracts | item	4
Recurring | Total | Commodity Derivatives
Derivative Assets:
Total assets	$ 6,255	$ 4,384,000
Derivative Liabilities:
Gross Recognized Liabilities	(13,267)	(7,617,000)
Recurring | Total | Commodity Derivatives | Swaps | Oil
Derivative Assets:
Total assets	2
Derivative Liabilities:
Gross Recognized Liabilities	(4,293)	(3,679,000)
Recurring | Total | Commodity Derivatives | Swaps | Natural gas
Derivative Assets:
Total assets	74	821,000
Derivative Liabilities:
Gross Recognized Liabilities	(205)
Recurring | Total | Commodity Derivatives | Collars | Oil
Derivative Assets:
Total assets	4,764	952,000
Derivative Liabilities:
Gross Recognized Liabilities	(8,208)	(2,605,000)
Recurring | Total | Commodity Derivatives | Collars | Natural gas
Derivative Assets:
Total assets	1,415	2,611,000
Derivative Liabilities:
Gross Recognized Liabilities	(561)	(1,333,000)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives
Derivative Assets:
Total assets	6,255	4,384,000
Derivative Liabilities:
Gross Recognized Liabilities	(13,267)	(7,617,000)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Swaps | Oil
Derivative Assets:
Total assets	2
Derivative Liabilities:
Gross Recognized Liabilities	(4,293)	(3,679,000)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Swaps | Natural gas
Derivative Assets:
Total assets	74	821,000
Derivative Liabilities:
Gross Recognized Liabilities	(205)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Collars | Oil
Derivative Assets:
Total assets	4,764	952,000
Derivative Liabilities:
Gross Recognized Liabilities	(8,208)	(2,605,000)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Collars | Natural gas
Derivative Assets:
Total assets	1,415	2,611,000
Derivative Liabilities:
Gross Recognized Liabilities	$ (561)	$ (1,333,000)

Risk Management and Derivativ34

Risk Management and Derivative Instruments- Hedging (Details) - Designated as Hedging Instrument - NYMEX	3 Months Ended
	Mar. 31, 2018MMBTU$ / bbl$ / MMBTUbbl
WTI | Swap Contract Quarter Ended March 31, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	99,000
Swap weighted average strike price	50.61
WTI | Swap Contract Quarter Ended June 30, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	154,750
Swap weighted average strike price	51.97
WTI | Swap Contract Quarter Ended September 30, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	151,800
Swap weighted average strike price	55.23
WTI | Swap Contract Quarter Ended December 31, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	289,800
Swap weighted average strike price	57.79
WTI | Three Way Collar Contract Quarter Ended March 31, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	225,000
Weighted average ceiling price	62.14
Weighted average floor price	50
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended June 30, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	182,000
Weighted average ceiling price	60.65
Weighted average floor price	50
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended September 30, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	184,000
Weighted average ceiling price	59.93
Weighted average floor price	50
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended December 31, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	46,000
Weighted average ceiling price	56.70
Weighted average floor price	50
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended March 31, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	180,000
Weighted average ceiling price	63.14
Weighted average floor price	53.75
Weighted average sub-floor price	43.75
WTI | Three Way Collar Contract Quarter Ended June 30, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	182,000
Weighted average ceiling price	63.14
Weighted average floor price	53.75
Weighted average sub-floor price	43.75
WTI | Three Way Collar Contract Quarter Ended September 30, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	184,000
Weighted average ceiling price	63.14
Weighted average floor price	53.75
Weighted average sub-floor price	43.75
WTI | Three Way Collar Contract Quarter Ended December 31, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	184,000
Weighted average ceiling price	63.14
Weighted average floor price	53.75
Weighted average sub-floor price	43.75
WTI | Three Way Collar Contract Quarter Ended March 31, 2020
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	91,000
Weighted average ceiling price	65.75
Weighted average floor price	50
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended June 30, 2020
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	91,000
Weighted average ceiling price	65.75
Weighted average floor price	50
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended September 30, 2020
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	92,000
Weighted average ceiling price	65.75
Weighted average floor price	50
Weighted average sub-floor price	40
WTI | Three Way Collar Contract Quarter Ended December 31, 2020
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	92,000
Weighted average ceiling price	65.75
Weighted average floor price	50
Weighted average sub-floor price	40
HENRY HUB | Swap Contract Quarter Ended March 31, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,350,000
Swap weighted average strike price | $ / MMBTU	3.47
HENRY HUB | Swap Contract Quarter Ended June 30, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	915,000
Swap weighted average strike price | $ / MMBTU	2.79
HENRY HUB | Swap Contract Quarter Ended September 30, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,380,000
Swap weighted average strike price | $ / MMBTU	2.79
HENRY HUB | Swap Contract Quarter Ended December 31, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,380,000
Swap weighted average strike price | $ / MMBTU	2.91
HENRY HUB | Swap Contract Quarter Ended March 31, 2019
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,350,000
Swap weighted average strike price | $ / MMBTU	2.98
HENRY HUB | Three Way Collar Contract Quarter Ended March 31, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,530,000
Weighted average ceiling price | $ / MMBTU	4.38
Weighted average floor price | $ / MMBTU	3.25
Weighted average sub-floor price | $ / MMBTU	2.50
HENRY HUB | Three Way Collar Contract Quarter Ended June 30, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,365,000
Weighted average ceiling price | $ / MMBTU	3.40
Weighted average floor price | $ / MMBTU	3
Weighted average sub-floor price | $ / MMBTU	2.50
HENRY HUB | Three Way Collar Contract Quarter Ended September 30, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,380,000
Weighted average ceiling price | $ / MMBTU	3.40
Weighted average floor price | $ / MMBTU	3
Weighted average sub-floor price | $ / MMBTU	2.50
HENRY HUB | Three Way Collar Contract Quarter Ended December 31, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,380,000
Weighted average ceiling price | $ / MMBTU	3.40
Weighted average floor price | $ / MMBTU	3
Weighted average sub-floor price | $ / MMBTU	2.50
HENRY HUB | Three Way Collar Contract Quarter Ended March 31, 2019
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,350,000
Weighted average ceiling price | $ / MMBTU	3.40
Weighted average floor price | $ / MMBTU	3
Weighted average sub-floor price | $ / MMBTU	2.50

Risk Management and Derivativ35

Risk Management and Derivative Instruments- Balance Sheet Presentation (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Total derivative financial instruments - current liabilities	$ (6,062)	$ (3,433)
Total derivative financial instruments - noncurrent liabilities	(950)	(562)
Commodity Derivatives | Not designated as Hedging Instrument
Total derivative financial instruments - current assets		762
Total derivative financial instruments - current liabilities	(6,062)	(3,433)
Total derivative financial instruments - noncurrent liabilities	(950)	(562)
Total derivative fair value at period end	(7,012)	(3,233)
Derivative assets:
Gross Recognized Assets	6,255	4,384
Gross Amounts Offset, Assets	(6,255)	(3,622)
Net Recognized Fair Value Assets		762
Derivative liabilities:
Gross Recognized Liabilities	(13,267)	(7,617)
Gross Amounts Offset, Liabilities	6,255	3,622
Net Recognized Fair Value Liabilities	(7,012)	(3,995)
Current Assets | Commodity Derivatives | Not designated as Hedging Instrument
Derivative assets:
Gross Recognized Assets	2,134	3,479
Gross Amounts Offset, Assets	(2,134)	(2,717)
Net Recognized Fair Value Assets		762
Current Assets | Commodity Derivatives | Not designated as Hedging Instrument | Leasehold interest swap | Natural gas
Total derivative financial instruments - current assets		821
Current Assets | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Oil
Total derivative financial instruments - current assets		(760)
Current Assets | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Natural gas
Total derivative financial instruments - current assets		701
Non-Current Assets | Commodity Derivatives | Not designated as Hedging Instrument
Derivative assets:
Gross Recognized Assets	4,121	905
Gross Amounts Offset, Assets	(4,121)	(905)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument
Derivative liabilities:
Gross Recognized Liabilities	(8,196)	(6,150)
Gross Amounts Offset, Liabilities	2,134	2,717
Net Recognized Fair Value Liabilities	(6,062)	(3,433)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Leasehold interest swap | Oil
Total derivative financial instruments - current liabilities	(4,291)	(3,679)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Leasehold interest swap | Natural gas
Total derivative financial instruments - current liabilities	(131)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Oil
Total derivative financial instruments - current liabilities	(2,494)	(370)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Natural gas
Total derivative financial instruments - current liabilities	854	616
Non-Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument
Derivative liabilities:
Gross Recognized Liabilities	(5,071)	(1,467)
Gross Amounts Offset, Liabilities	4,121	905
Net Recognized Fair Value Liabilities	(950)	(562)
Non-Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Oil
Total derivative financial instruments - noncurrent liabilities	$ (950)	(523)
Non-Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Natural gas
Total derivative financial instruments - noncurrent liabilities		$ (39)

Risk Management and Derivativ36

Risk Management and Derivative Instruments - Gain Loss (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Gains (losses) on Commodity Derivative Contracts
Net cash received (paid) for commodity derivative contracts	$ 160	$ (811)
Gains (losses) on commodity derivative contracts - net	(3,939)	4,865
Not designated as Hedging Instrument
Gains (losses) on Commodity Derivative Contracts
Net cash received (paid) for commodity derivative contracts	(160)	811
Unrealized net gains (losses)	(3,779)	4,054
Gains (losses) on commodity derivative contracts - net	$ (3,939)	$ 4,865

Property and Equipment (Details

Property and Equipment (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)$ / Boe	Mar. 31, 2017USD ($)$ / Boe	Dec. 31, 2017USD ($)
Oil and gas properties, on the basis of full-cost accounting
Proved properties	$ 798,593		$ 765,308
Unproved properties not being amortized	7,142		7,065
Other property and equipment	6,502		6,508
Less accumulated depreciation, depletion, amortization and impairment	(219,590)		(204,419)
Net property and equipment	592,647		$ 574,462
Other information
Proceeds from the sale of oil and gas equipment		$ 1,350
Depreciation, depletion, and amortization	15,213	15,342
Oil and Gas
Other information
Internal costs capitalized to oil and gas properties	895	3,017
Capitalized qualifying share-based compensation expense	200	700
Depletion expense	14,623	14,753
Depreciation on other property and equipment	$ 590	$ 589
Depletion expense (per Boe) | $ / Boe	8.45	6.96
Depreciation on other property and equipment (per Boe) | $ / Boe	0.34	0.28
Depreciation, depletion, and amortization (per Boe) | $ / Boe	8.79	7.24
Depreciation, depletion, and amortization	$ 15,213	$ 15,342
Impairment of unproved properties	0
Oil and Gas | Anadarko Disposition | Disposed of by sale
Other information
Proceeds from the sale of oil and gas equipment	58,000
Net proceeds from the sale of oil and gas equipment	$ 1,400
Other Property and Equipment | Minimum
Other information
Estimated useful lives	2 years
Other Property and Equipment | Maximum
Other information
Estimated useful lives	10 years

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Accrued Liabilities
Accrued oil and gas capital expenditures	$ 13,853	$ 9,081
Accrued revenue and royalty distributions	17,195	18,701
Accrued lease operating and workover expense	5,340	5,150
Accrued interest	42	108
Accrued taxes	2,483	2,758
Compensation and benefit related accruals	2,351	4,520
Other	4,269	2,524
Accrued liabilities	$ 45,533	$ 42,842

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Changes in asset retirement obligations
Asset retirement obligations at beginning of period	$ 15,506	$ 14,200
Liabilities incurred	113	90
Liabilities settled	(1)	(30)
Liabilities eliminated through asset sales	(62)
Current period accretion expense	297	276
Asset retirement obligations at end of period	$ 15,853	$ 14,536

Debt - Exit Facility (Details)

Debt - Exit Facility (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Apr. 19, 2018USD ($)
Debt
Repayment of revolving credit facility	$ 50,000
RBL
Debt
Maximum borrowing capacity	170,000	$ 170,000	$ 170,000
Repayment of revolving credit facility	50,000
Proceeds from revolving credit facility	78,100	128,100
Availability under the facility	$ 90,000
Weighted-average interest rate (as a percent)	6.90%
Unamortized debt issuance costs	$ 1,100	1,200
Commitment fee (as a percent)	0.50
LIBOR Loans | RBL
Debt
Interest rate added to base rate (as a percent)	4.50%
LIBOR floor rate	1.00%
Minimum
Debt
EBITDA to interest expense coverage ratio	2.50
Maximum
Debt
Total net indebtedness to EBITDA	4
Senior Revolving Credit Facility, due 2018 | RBL
Debt
Outstanding letters of credit amount	$ 1,900	$ 1,900

Equity and Share-Based Compen41

Equity and Share-Based Compensation - Common Shares (Details)	3 Months Ended
	Mar. 31, 2018shares
Common Stock
Changes in number of shares outstanding
Share count at the beginning of the period (in shares)	25,272,969
Issuance of successor common stock (in shares)	110,885
Share count at the end of the period (in shares)	25,383,854
Treasury Stock
Changes in number of shares outstanding
Treasury Stock, Shares, Beginning Balance	(99,623)
Acquisition of treasury stock (in shares)	(28,746)
Treasury Stock, Shares, Ending Balance	(128,369)

Equity and Share-Based Compen42

Equity and Share-Based Compensation - Emergence from Bankruptcy and 2016 Long Term Incentive Plan (Details) - 2016 LTIP - shares	Mar. 31, 2018	Oct. 21, 2016
Share-Based Compensation
Number of shares available for future issuance		3,513,950
Number of shares authorized	1,763,238

Equity and Share-Based Compen43

Equity and Share-Based Compensation - Restricted Stock Units (Details) - Restricted Stock Units $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)$ / sharesshares
Restricted Stock
Non-vested shares outstanding at the beginning of the period (in shares)	324,984
Granted (in shares)	269,468
Vested (in shares)	(102,759)
Non-vested shares outstanding at the end of the period (in shares)	491,693
Weighted Average Grant Date Fair Value
Non-vested shares outstanding at the beginning of the period (in dollars per share) | $ / shares	$ 18.84
Granted (in dollars per share) | $ / shares	14.25
Vested (in dollars per share) | $ / shares	19.66
Non-vested shares outstanding at the end of the period (in dollars per share) | $ / shares	$ 16.16
Additional information
Accelerated vesting due to change reduction in workforce (in shares)	102,092
2016 LTIP
Additional information
Unrecognized expense for share-based compensation | $	$ 5.5
Weighted-average period for over which unrecognized expense will be recognized	1 year 4 months 24 days
2016 LTIP | Employees
Share-Based Compensation
Vesting period	3 years
Awards vesting on the six-month anniversary of the Effective Date | 2016 LTIP | Employees
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant	33.33%
Awards vesting on the twelve-month anniversary of the Effective Date | 2016 LTIP | Employees
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant	33.33%
Awards vesting on the thirty six-month anniversary of the Effective Date | 2016 LTIP | Employees
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant	33.33%

Equity and Share-Based Compen44

Equity and Share-Based Compensation - Stock Options (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 01, 2017	Mar. 31, 2018	Dec. 31, 2017
Maximum
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant	120.00%
2016 LTIP | Stock Options
Share-Based Compensation
Vesting period		3 years
Expiration period (in years)		10 years
Options
Stock options outstanding at beginning of period (in shares)		245,845
Vested (in shares)		(102,759)
Stock options outstanding at end of period (in shares)		143,086	245,845
Vested and exercisable at end of period (in shares)		356,437
Weighted Average Exercise Price
Stock options outstanding at beginning of period (in dollars per share)		$ 19.66
Weighted average vested price of vested options (in dollars per share)		19.66
Stock options outstanding at end of period (in dollars per share)		19.66	$ 19.66
Vested and exercisable at end of period (in dollars per share)		$ 19.66
Weighted Average Remaining Contractual Term (Years)
Vested (in years)		4 months 24 days
Stock options outstanding at end of period (in years)		8 years 7 months 6 days	8 years 7 months 6 days
Vested and exercisable at end of period (in years)		6 years 8 months 12 days
Vested and exercisable options, aggregate intrinsic value		$ 0
Additional information
Vested (in shares)		102,759
Accelerated vesting due to change reduction in workforce (in shares)		102,092
Unrecognized expense for share-based compensation		$ 600
Weighted-average period for over which unrecognized expense will be recognized		1 year 1 month 6 days
Shares available for issuance		0
2016 LTIP | Minimum | Stock Options
Weighted Average Exercise Price
Weighted average vested price of vested options (in dollars per share)		$ 19.08
Vested and exercisable at end of period (in dollars per share)		19.08
2016 LTIP | Maximum | Stock Options
Weighted Average Exercise Price
Weighted average vested price of vested options (in dollars per share)		19.66
Vested and exercisable at end of period (in dollars per share)		$ 20.97
Awards vesting on the six-month anniversary of the Effective Date | 2016 LTIP | Stock Options
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant		16.67%
Awards vesting on the twelve-month anniversary of the Effective Date | 2016 LTIP | Stock Options
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant		16.67%
Awards vesting on the twenty four-month anniversary of the Effective Date | 2016 LTIP | Stock Options
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant		33.33%
Awards vesting on the thirty six-month anniversary of the Effective Date | 2016 LTIP | Stock Options
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant		33.33%

Equity and Share-Based Compen45

Equity and Share-Based Compensation - Non-Employee Director Restricted Stock Units Containing a Market Condition (Details) - Restricted Stock Units with Market Condition - USD ($) $ / shares in Units, $ in Millions	Nov. 23, 2016	Mar. 31, 2018
Non-employee directors
Share-Based Compensation
Trailing average share price period based on common stock (in days)	60 days
Assumptions used to estimate fair value of restricted stock unit awards with market condition
Market Price Hurdle (in dollars per share)	$ 30
Calculated fair value per stock option (in dollars per share)		$ 6.90
Unrecognized expense for share-based compensation		$ 0
Non-employee directors | Accrued liabilities
Assumptions used to estimate fair value of restricted stock unit awards with market condition
Liability related to market condition awards		$ 0.5
Executive officer
Assumptions used to estimate fair value of restricted stock unit awards with market condition
Calculated fair value per stock option (in dollars per share)		$ 13.34
Unrecognized expense for share-based compensation		$ 1.2

Equity and Share-Based Compen46

Equity and Share-Based Compensation - Chief Executive Officer Restricted Stock Units Containing a Market Condition (Details) - USD ($) $ / shares in Units, $ in Millions	Nov. 01, 2017	Mar. 31, 2018
Maximum
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)	120.00%
Restricted Stock Units with Market Condition | Chief Executive Officer
Share-Based Compensation
RSUs granted based on actual TSR (as a percentage)	50.00%
RSUs granted based on relative TSR (as a percentage)	50.00%
Assumptions used to estimate fair value of restricted stock unit awards with market condition
Unrecognized expense for share-based compensation		$ 1.3
Weighted-average period for over which unrecognized expense will be recognized		2 years 7 months 6 days
Restricted Stock Units with Market Condition | Executive officer
Assumptions used to estimate fair value of restricted stock unit awards with market condition
Risk-free interest rate (as a percent)		2.34%
Expected volatility rate, minimum (as a percent)		40.00%
Expected volatility rate, maximum (as a percent)		127.20%
Calculated fair value per stock option (in dollars per share)		$ 13.34
Service period (in years)		3 years
Unrecognized expense for share-based compensation		$ 1.2
Weighted-average period for over which unrecognized expense will be recognized		2 years 9 months 18 days
Restricted Stock
Granted (in shares)		96,305
Non-vested shares outstanding at the end of the period (in shares)		96,305
Weighted Average Grant Date Fair Value
Granted (in dollars per share)		$ 13.34
Non-vested shares outstanding at the end of the period (in dollars per share)		$ 13.34
First 50% of RSUs granted based on actual TSR | Chief Executive Officer
Share-Based Compensation
Days considered for calculation of average stock price	20 days
Remaining 50% of RSUs granted based on relative TSR | Executive officer | Top 35% or better Relative TSR to Peer Group
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)		150.00%
Remaining 50% of RSUs granted based on relative TSR | Executive officer | Top 50% or better Relative TSR to Peer Group
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)		100.00%
Remaining 50% of RSUs granted based on relative TSR | Executive officer | Top 60% or better Relative TSR to Peer Group
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)		50.00%
Remaining 50% of RSUs granted based on relative TSR | Executive officer | Less than 60% of Relative TSR to Peer Group
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)		0.00%
General and administrative expense | Restricted Stock Units with Market Condition | Chief Executive Officer
Assumptions used to estimate fair value of restricted stock unit awards with market condition
Share-based compensation costs recognized		$ 0.1
General and administrative expense | Restricted Stock Units with Market Condition | Executive officer
Assumptions used to estimate fair value of restricted stock unit awards with market condition
Share-based compensation costs recognized		$ 0.1

Income Taxes (Details)

Income Taxes (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Income Taxes
Estimated deduction associated with cost of qualified asset	$ 9
Valuation allowance	119
Increase in valuation allowance	(1.1)
Current
Total current	0
Deferred
Total income tax provision (benefit)	$ 0
Reconciliation of income tax expense
Statutory rate	21.00%

Income Per Share (Details)

Income Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Income Per Share
Net income	$ 4,004	$ 18,485
Participating securities-non-vested restricted stock	(99)	(546)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 3,905	$ 17,939
Common shares outstanding - basic	25,299	25,012
Common shares outstanding - diluted	25,299	25,012
Basic (in dollars per share)	$ 0.15	$ 0.72
Diluted (in dollars per share)	$ 0.15	$ 0.72
Shares of common stock to be issued by required Plan	9,407	17,533
Directors shares for calculation of earnings per share			57,856
Stock Options
Income Per Share
Antidilutive securities (in shares)	500	627
Warrants
Income Per Share
Antidilutive securities (in shares)	6,626	6,626

Related Party Transactions (Det

Related Party Transactions (Details) - EcoStim - Well stimulation and completion services - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Related Party Transactions
Amount paid to related party		$ 0
Accounts payable
Related Party Transactions
Amount paid to related party	$ 2.1

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Commitments and Contingencies
Loss Contingency Accrual	$ 1.1	$ 1.1