Amplify Energy (AMPY) 10-Q 9 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 05, 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	Sep. 30, 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		25,302,262
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
CURRENT ASSETS:
Cash and cash equivalents	$ 6,213	$ 68,498
Accounts receivable:
Oil and gas sales	29,472	32,455
Joint interest billing	3,178	3,297
Other	449	166
Commodity derivative contracts		762
Other current assets	1,813	1,510
Total current assets	41,125	106,688
Oil and gas properties, on the basis of full-cost accounting
Proved properties	803,841	765,308
Unproved properties not being amortized	4,505	7,065
Other property and equipment	6,369	6,508
Less accumulated depreciation, depletion, amortization and impairment	(251,432)	(204,419)
Net property and equipment	563,283	574,462
OTHER NONCURRENT ASSETS	5,591	6,978
TOTAL	609,999	688,128
CURRENT LIABILITIES:
Accounts payable	14,322	11,547
Accrued liabilities	36,703	42,842
Commodity derivative contracts	13,210	3,433
Total current liabilities	64,235	57,822
LONG-TERM LIABILITIES:
Asset retirement obligations	7,816	15,506
Commodity derivative contracts	4,361	562
Long-term debt	28,059	128,059
Other long-term liabilities	569	592
Total long-term liabilities	40,805	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 September 30, 2018 and December 31, 2017
Warrants, 6,625,554 warrants outstanding at September 30, 2018 and December 31, 2017	37,329	37,329
Common stock, $0.01 par value, 250,000,000 shares authorized; 25,386,104 shares issued and 25,256,957 shares outstanding at September 30, 2018; 25,272,969 shares issued and 25,173,346 shares outstanding at December 31, 2017	254	253
Treasury stock	(2,081)	(1,603)
Additional paid-in-capital	530,627	524,755
Retained deficit	(61,170)	(75,147)
Total stockholders' equity	504,959	485,587
TOTAL	$ 609,999	$ 688,128

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 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	25,386,104	25,272,969
Common stock, shares outstanding	25,256,957	25,173,346

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
REVENUES:
Gains (losses) on commodity derivative contracts-net	$ (6,583)	$ (3,591)	$ (21,870)	$ 8,767
Revenues, Total	47,765	49,715	138,994	175,409
EXPENSES:
Lease operating and workover	11,861	15,653	43,621	48,064
Gathering and transportation (Note 3)	54	3,699	178	11,027
Gathering And Transportation Cost	54	3,699	178	11,027
Severance and other taxes	3,360	2,352	8,998	6,168
Asset retirement accretion	147	274	694	833
Depreciation, depletion, and amortization	15,485	15,170	47,182	46,471
General and administrative	4,688	7,255	19,735	23,102
Advisory Fees			850
Total expenses	35,595	44,403	121,258	135,665
OPERATING INCOME	12,170	5,312	17,736	39,744
OTHER EXPENSE:
Interest income	4		28
Interest expense-net of amounts capitalized	(658)	(1,649)	(3,787)	(3,854)
Total other expense	(654)	(1,649)	(3,759)	(3,854)
INCOME BEFORE TAXES	11,516	3,663	13,977	35,890
Income tax expense			0
NET INCOME	11,516	3,663	13,977	35,890
Participating securities-non-vested restricted stock	(351)	(82)	(400)	(932)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 11,165	$ 3,581	$ 13,577	$ 34,958
Basic and diluted net income per share attributable to common shareholders	$ 0.44	$ 0.14	$ 0.54	$ 1.39
Basic and diluted weighted-average number of common shares outstanding (Note 12)	25,332	25,116	25,321	25,074
Revenue from contracts with customers
REVENUES:
Revenues, Total	$ 54,348	$ 53,306	$ 160,864	$ 166,642
Oil
REVENUES:
Revenues, Total	33,218	27,190	99,834	85,497
Natural gas liquid
REVENUES:
Revenues, Total	12,720	10,656	35,651	31,580
Natural gas
REVENUES:
Revenues, Total	7,026	13,970	22,145	46,321
Other
REVENUES:
Revenues, Total	$ 1,384	$ 1,490	$ 3,234	$ 3,244

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS 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	1			8,518		8,519
Acquisition of treasury stock			$ (626)			(626)
Net income					35,890	35,890
Balance at Sep. 30, 2017	251	37,329	(626)	522,823	45,820	605,597
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			5,872		5,873
Acquisition of treasury stock			(478)			(478)
Net income					13,977	13,977
Balance at Sep. 30, 2018	$ 254	$ 37,329	$ (2,081)	$ 530,627	$ (61,170)	$ 504,959

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 13,977	$ 35,890
Adjustments to reconcile net income to net cash provided by operating activities:
(Gains) losses on commodity derivative contracts-net	21,870	(8,767)
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments	(7,532)	6,149
Asset retirement accretion	694	833
Depreciation, depletion, and amortization	47,182	46,471
Share-based compensation, net of amounts capitalized to oil and gas properties	4,330	7,102
Amortization of deferred financing costs	324	277
Change in operating assets and liabilities:
Accounts receivable - oil and gas sales	3,028	4,929
Accounts receivable - JIB and other	(322)	2,641
Other current and noncurrent assets	(529)	(98)
Accounts payable	833	1,392
Accrued liabilities	(2,260)	(7,381)
Other	(25)	(121)
Net cash provided by operating activities	81,570	89,317
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(98,164)	(92,841)
Proceeds from the sale of oil and gas properties	54,432	2,885
Proceeds from the sale of oil and gas equipment	355	1,350
Net cash used in investing activities	(43,377)	(88,606)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of revolving credit facility	(100,000)
Deferred financing costs		(375)
Repurchase of restricted stock for tax withholdings	(478)	(626)
Net cash used in financing activities	(100,478)	(1,001)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(62,285)	(290)
Cash and cash equivalents, beginning of period	68,498	76,838
Cash and cash equivalents, end of period	6,213	76,548
SUPPLEMENTAL INFORMATION:
Non-cash transactions - investments in property and equipment accrued - not paid	16,261	19,865
Cash paid for interest, net of capitalized interest of $0.3 million and $2.1 million, respectively	$ 3,555	$ 3,708

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Capitalized interest	$ 0.3	$ 2.1

Organization and Business

Organization and Business	9 Months Ended
	Sep. 30, 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. 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 currently conducts oil and gas operations and owns and operates oil and natural gas properties in Oklahoma. The Company operates nearly all 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	9 Months Ended
	Sep. 30, 2018
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies	2. Summary of Significant Accounting Policies Basis of Presentation These unaudited interim condensed consolidated financial statements 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, these financial statements 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 interim 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 interim condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the unaudited interim 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 interim 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 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 June 2018, the FASB issued Accounting Standards Update 2018-07, “ Compensation - Stock Compensation (Topic 718) - Improvements to Nonemployee Share-Based Payment Accounting ” (“ASU 2018-07”). ASU 2018-07 expands the scope of Topic 718 to include share-based payments issued to non-employees for goods and services. Consequently, the accounting for share-based payments to non-employees and employees will be substantially aligned. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company does not believe the adoption of ASU 2018-07 will have a material impact on its financial position, results of operations or cash flows. In July 2017, the FASB issued Accounting Standards Update 2017-11, “ Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815) ” (“ASU 2017-11”). ASU 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. Additionally, in July 2018, the FASB issued Accounting Standards Update 2018-11,"Leases (Topic 842):Targeted Improvements, which included the option to implement the standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings, as opposed to the modified retrospective transition method required when ASU 2016-02 was issued. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company has analyzed and categorized the majority of its contracts to determine if they meet the definition of a lease under ASU 2016-02. The Company’s ongoing efforts are concentrated on analyzing the remaining contracts, testing and implementing its tracking software for leases and determining the most appropriate transition method and resulting accounting impact to the Company. As a result, the Company has not quantified the impact of ASU 2016-02 and cannot reasonably quantify the impact of adoption at this time. The Company 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	9 Months Ended
	Sep. 30, 2018
Impact of ASC 606 Adoption
Impact of ASC 606 Adoption	3. Impact of ASC 606 Adoption On January 1, 2018, the Company adopted Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”) using the modified retrospective method of transition. ASC 606 supersedes previous revenue recognition requirements in Accounting Standards Codification 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 results is as follows for the periods presented (in thousands): Three Months Ended September 30, 2018 Under ASC 606 Under ASC 605 Decrease Oil sales $ 33,218 $ 33,237 $ (19) Natural gas liquid sales 12,720 12,733 (13) Natural gas sales 7,026 10,191 (3,165) Gathering and transportation 54 3,203 (3,149) Lease operating and workover expense 11,861 11,909 (48) Net income $ 11,516 $ 11,516 $ — Retained deficit $ (61,170) $ (61,170) $ — Nine Months Ended September 30, 2018 Under ASC 606 Under ASC 605 Decrease Oil sales $ 99,834 $ 99,879 $ (45) Natural gas liquid sales 35,651 35,709 (58) Natural gas sales 22,145 31,778 (9,633) Gathering and transportation 178 9,702 (9,524) Lease operating and workover expense 43,621 43,833 (212) Net income $ 13,977 $ 13,977 $ — Retained deficit $ (61,170) $ (61,170) $ — 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 collects 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 which 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 September 30, 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 and nine months ended September 30, 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	9 Months Ended
	Sep. 30, 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 interim condensed consolidated balance sheets are recorded at estimated fair value. At September 30, 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 interim condensed consolidated statements of operations. Fair Value Measurements at September 30, 2018 Quoted Prices Significant Other Significant in Active Markets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps $ — $ 69 $ — $ 69 Commodity derivative oil collars $ — $ 1,477 $ — $ 1,477 Commodity derivative gas collars $ — $ 431 $ — $ 431 Total assets $ — $ 1,977 $ — $ 1,977 Derivative Liabilities: Commodity derivative oil swaps $ — $ (7,110) $ — $ (7,110) Commodity derivative gas swaps $ — $ (361) $ — $ (361) Commodity derivative oil collars $ — $ (11,722) $ — $ (11,722) Commodity derivative gas collars $ — $ (355) $ — $ (355) Total liabilities $ — $ (19,548) $ — $ (19,548) Fair Value Measurements at December 31, 2017 Quoted Prices Significant Other Significant in Active Markets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps $ — $ 821 $ — $ 821 Commodity derivative oil collars $ — $ 952 $ — $ 952 Commodity derivative gas collars $ — $ 2,611 $ — $ 2,611 Total assets $ — $ 4,384 $ — $ 4,384 Derivative Liabilities: Commodity derivative oil swaps $ — $ (3,679) $ — $ (3,679) Commodity derivative gas swaps $ — $ — $ — $ — Commodity derivative oil collars $ — $ (2,605) $ — $ (2,605) Commodity derivative gas collars $ — $ (1,333) $ — $ (1,333) Total liabilities $ — $ (7,617) $ — $ (7,617)

Risk Management and Derivative

Risk Management and Derivative Instruments	9 Months Ended
	Sep. 30, 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 oil 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 September 30, 2018, the Company would not have experienced a loss. Commodity Derivative Contracts The Company has various oil and natural gas derivative contracts that extend through December 31, 2020, summarized as follows: NYMEX WTI Fixed Swaps Three-Way Collars Weighted Weighted Weighted Hedge Avg Hedge Avg Weighted Avg Position Strike Position Ceiling Avg Floor Sub-Floor (Bbls) Price (Bbls) Price Price Price Quarter Ended: September 30, 2018 175,720 $ 57.23 184,000 $ 59.93 $ 50.00 $ 40.00 December 31, 2018(1) 313,720 $ 58.59 46,000 $ 56.70 $ 50.00 $ 40.00 March 31, 2019(1) 171,000 $ 66.48 180,000 $ 63.14 $ 53.75 $ 43.75 June 30, 2019(1) 133,900 $ 64.86 182,000 $ 63.14 $ 53.75 $ 43.75 September 30, 2019(1) 46,000 $ 62.96 184,000 $ 63.14 $ 53.75 $ 43.75 December 31, 2019(1) 46,000 $ 61.43 184,000 $ 63.14 $ 53.75 $ 43.75 March 31, 2020(1) — $ — 91,000 $ 65.75 $ 50.00 $ 40.00 June 30, 2020(1) — $ — 91,000 $ 65.75 $ 50.00 $ 40.00 September 30, 2020(1) — $ — 92,000 $ 65.75 $ 50.00 $ 40.00 December 31, 2020(1) — $ — 92,000 $ 65.75 $ 50.00 $ 40.00 NYMEX HENRY HUB Fixed Swaps Three-Way Collars Weighted Weighted Weighted Hedge Weighted Hedge Avg Avg Avg Position Avg Strike Position Ceiling Floor Sub-Floor (MMBtu) Price (MMBtu) Price Price Price Quarter Ended: September 30, 2018 2,116,000 $ 2.84 1,380,000 $ 3.40 $ 3.00 $ 2.50 December 31, 2018(1) 2,055,000 $ 2.95 1,380,000 $ 3.40 $ 3.00 $ 2.50 March 31, 2019(1) 1,980,000 $ 3.01 1,350,000 $ 3.40 $ 3.00 $ 2.50 (1) Positions shown represent open commodity derivative contract positions as of September 30, 2018. 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 interim condensed consolidated balance sheets for the periods presented (in thousands): Type Balance Sheet Location (1) September 30, 2018 December 31, 2017 Gas swaps Derivative financial instruments - current assets $ — $ 821 Oil collars Derivative financial instruments - current assets — (760) Gas collars Derivative financial instruments - current assets — 701 Total derivative financial instruments — current assets $ — $ 762 Oil swaps Derivative financial instruments — current liabilities $ (6,753) $ (3,679) Gas swaps Derivative financial instruments - current liabilities (292) — Oil collars Derivative financial instruments - current liabilities (6,241) (370) Gas collars Derivative financial instruments - current liabilities 76 616 Total derivative financial instruments — current liabilities $ (13,210) $ (3,433) Oil swaps Derivative financial instruments — noncurrent liabilities $ (357) $ (523) Oil collars Derivative financial instruments — noncurrent liabilities (4,004) (39) Total derivative financial instruments — noncurrent liabilities $ (4,361) $ (562) Total derivative fair value at period end $ (17,571) $ (3,233) (1) The fair values of commodity derivative instruments reported in the Company’s unaudited interim 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 as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited interim condensed consolidated balance sheets for the periods presented (in thousands): September 30, 2018 Net Recognized Not Designated as Gross Recognized Gross Amounts Fair Value ASC 815 Hedges Balance Sheet Location Classification Assets/Liabilities Offset Assets/Liabilities Derivative Assets: Commodity contracts Derivative financial instruments — current $ 901 $ (901) $ — Commodity contracts Derivative financial instruments — noncurrent 1,076 (1,076) — $ 1,977 $ (1,977) $ — Derivative Liabilities: Commodity contracts Derivative financial instruments — current $ (14,111) $ 901 $ (13,210) Commodity contracts Derivative financial instruments — noncurrent (5,437) 1,076 (4,361) $ (19,548) $ 1,977 $ (17,571) December 31, 2017 Net Recognized Not Designated as Gross Recognized Gross Amounts Fair Value ASC 815 Hedges Balance Sheet Location Classification Assets/Liabilities Offset Assets/Liabilities Derivative Assets: Commodity contracts Derivative financial instruments - current $ 3,479 $ (2,717) $ 762 Commodity contracts Derivative financial instruments - noncurrent 905 (905) — $ 4,384 $ (3,622) $ 762 Derivative Liabilities: Commodity contracts Derivative financial instruments - current $ (6,150) $ 2,717 $ (3,433) Commodity contracts Derivative financial instruments - noncurrent (1,467) 905 (562) $ (7,617) $ 3,622 $ (3,995) 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 in gains (losses) on commodity derivative contracts—net within revenues in the unaudited interim condensed consolidated statements of operations. The following table presents net cash received or net cash paid for the settlement of commodity derivative contracts and unrealized net gains or unrealized net losses recorded by the Company related to the change in fair value of the derivative instruments in gains (losses) on commodity derivative contracts—net for the periods presented (in thousands): For the Three Months For the Nine Months Ended September 30, Ended September 30, 2018 2017 2018 2017 Net cash received (paid) for commodity derivative contracts $ (3,854) $ 2,909 $ (7,532) $ 6,149 Unrealized net gains (losses) (2,729) (6,500) (14,338) 2,618 Gains (losses) on commodity derivative contracts—net $ (6,583) $ (3,591) $ (21,870) $ 8,767 Net cash received (paid) for commodity derivative contracts, as presented in the table above, represent realized gains (losses) related to the Company’s derivative instruments. In addition to these 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 cash settlements that may occur during each reporting period, as well as the relationships between contractual prices and the associated forward curves.

Property and Equipment

Property and Equipment	9 Months Ended
	Sep. 30, 2018
Property and Equipment
Property and Equipment	6. Property and Equipment Property and equipment consisted of the following as of the dates presented (in thousands): September 30, 2018 December 31, 2017 Oil and gas properties, on the basis of full-cost accounting: Proved properties $ 803,841 $ 765,308 Unproved properties not being amortized 4,505 7,065 Other property and equipment 6,369 6,508 Less accumulated depreciation, depletion, amortization and impairment (251,432) (204,419) Net property and equipment $ 563,283 $ 574,462 Oil and Gas Properties The Company capitalizes internal costs directly related to exploration and development activities to oil and gas properties. During the three and nine months ended September 30, 2018 and 2017, the Company capitalized the following (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Internal costs capitalized to oil and gas properties (1) $ 821 $ 1,651 $ 2,638 $ 4,656 (1) Inclusive of $0.3 million and $0.8 million of qualifying share-based compensation expense for the three months ended September 30, 2018 and 2017, respectively. For the nine months ended September 30, 2018 and 2017, inclusive of $0.8 million and $2.0 million, respectively, of qualifying share-based compensation expense. 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 nine months ended September 30, 2018 and 2017, the Company disposed of certain oil and gas equipment for cash proceeds of $0.4 million and $1.4 million, respectively, which were reflected as reductions of oil and gas properties with no gain or loss recognized. In addition, during the nine months ended September 30, 2018, the Company disposed of its Anadarko Basin assets, which is discussed further below. 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 interim condensed consolidated statements of operations. While the Company did not record any impairments of oil and gas properties during the three or nine months ended September 30, 2018 or 2017, the Company recorded impairments of oil and gas properties during the year ended December 31, 2017, the period January 1, 2016 through October 20, 2016 and the year ended December 31, 2015. 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 DD&A, estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value. The following table presents depletion expense related to oil and gas properties for the periods presented: Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended September, 30, September, 30, September 30, September 30, 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) (per Boe) (in thousands) (per Boe) Depletion expense $ 14,913 $ 14,575 $ 9.01 $ 7.42 $ 45,433 $ 44,695 $ 8.81 $ 7.29 Depreciation on other property and equipment 572 595 0.35 0.30 1,749 1,776 0.34 0.29 Depreciation, depletion, and amortization $ 15,485 $ 15,170 $ 9.36 $ 7.72 $ 47,182 $ 46,471 $ 9.15 $ 7.58 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 or nine months ended September 30, 2018 or 2017. Unproved property was $4.5 million and $7.1 million at September 30, 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. Sale of Anadarko Basin Assets On May 31, 2018, the Company closed on the sale of its Anadarko Basin assets for $58.0 million in cash ($54.4 million, net of closing adjustments), subject to standard post-closing adjustments. The net proceeds were reflected as a reduction of oil and natural gas properties, with no gain or loss recognized as the sale did not result in a significant alteration of the full cost pool. The Company used $50.0 million of the net proceeds from the sale of the Anadarko Basin assets to pay down a portion of outstanding borrowings under the Company’s reserves-based revolving credit facility (“RBL”) and retained the remainder for general corporate purposes.

Accrued Liabilities

Accrued Liabilities	9 Months Ended
	Sep. 30, 2018
Accrued Liabilities
Accrued Liabilities	7. Accrued Liabilities The following table presents the components of accrued liabilities as of the dates presented (in thousands): September 30, 2018 December 31, 2017 Accrued oil and gas capital expenditures $ 6,235 $ 9,081 Accrued revenue and royalty distributions 16,846 18,701 Accrued lease operating and workover expense 3,549 5,150 Accrued interest 215 108 Accrued taxes 2,639 2,758 Compensation and benefit related accruals 3,324 4,520 Other 3,895 2,524 Accrued liabilities $ 36,703 $ 42,842

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 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): Nine Months Ended September 30, 2018 2017 Asset retirement obligations — beginning of period $ 15,506 $ 14,200 Liabilities incurred 316 259 Revisions — — Liabilities settled (1) (107) Liabilities eliminated through asset sales (8,699) (1,146) Current period accretion expense 694 833 Asset retirement obligations — end of period $ 7,816 $ 14,039

Debt

Debt	9 Months Ended
	Sep. 30, 2018
Debt
Debt	9. Debt Reserves-Based Revolving Credit Facility At September 30, 2018 and December 31, 2017, the Company maintained an RBL with a borrowing base of $170.0 million . During the nine months ended September 30, 2018, the Company paid down $100.0 million of its RBL utilizing $50.0 million of available cash on hand and $50.0 million of the net proceeds from the sale of its Anadarko Basin assets. At September 30, 2018 and December 31, 2017, the Company had $28.1 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 September 30, 2018, the Company had $140.0 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 September 30, 2018, the weighted-average interest rate was 6.7%, excluding amortization expense of deferred financing costs and commitment fees. Unamortized debt issuance costs of $0.9 million and $1.2 million associated with the RBL are included in other noncurrent assets on the unaudited interim condensed consolidated balance sheets at September 30, 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 September 30, 2018. On October 24, 2018, the Company’s borrowing base was redetermined at the existing amount of $170.0 million. The Company believes the carrying amount of the RBL at September 30, 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	9 Months Ended
	Sep. 30, 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 nine months ended September 30, 2018: Common Treasury Stock Stock(1) Share count as of December 31, 2017 25,272,969 (99,623) Common stock issued 113,135 — Acquisition of treasury stock — (29,524) Share count as of September 30, 2018 25,386,104 (129,147) (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 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 September 30, 2018, 2,066,380 Award Shares remain available for issuance under the terms of the 2016 LTIP. Restricted Stock Units At September 30, 2018, the Company had 476,776 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 nine months ended September 30, 2018, 271,968 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 nine months ended September 30, 2018: Weighted-Average Grant Date Restricted Stock Fair Value Non-vested shares outstanding at December 31, 2017 324,984 $ 18.84 Granted 271,968 $ 14.24 Vested(1) (105,009) $ 19.63 Forfeited (15,167) $ 15.76 Non-vested shares outstanding at September 30, 2018 476,776 $ 16.14 (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 nine months ended September 30, 2018. Unrecognized expense as of September 30, 2018, for all outstanding restricted stock units under the 2016 LTIP Plan was $2.9 million and will be recognized over a weighted-average period of 0.9 years. On October 21, 2018, 67,414 restricted stock units vested before consideration of minimum statutory tax withholding requirements. Stock Options At September 30, 2018, the Company had 137,516 non-vested options outstanding pursuant to the 2016 LTIP. Stock option awards currently outstanding under 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 nine months ended September 30, 2018. The following table summarizes the Company’s 2016 LTIP non-vested stock option activity for the nine months ended September 30, 2018: Weighted- Average Remaining Range of Weighted-Average Contractual Options Exercise Prices Exercise Price Term (Years) Stock options outstanding at December 31, 2017 245,845 $ 19.66 8.2 Granted — $ — $ — — Vested(1) (102,759) $ 19.08-19.66 $ 19.66 8.7 Forfeited (5,570) $ $ 19.66 0.1 Stock options outstanding at September 30, 2018 137,516 $ 19.66 8.2 Vested and exercisable at end of period(1)(2) 71,532 $ 19.08-20.97 $ 19.67 8.2 (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 nine months ended September 30, 2018. Per the 2016 LTIP Plan, these vested options had to be exercised within 180 days of employees termination or they would expire and be returned to the Plan for future reissuance. All options expired on July 31, 2018 thereby reducing the total options vested and exercisable at September 30, 2018. (2) Vested and exercisable options at September 30, 2018, had no aggregate intrinsic value. Unrecognized expense as of September 30, 2018, for all outstanding stock options under the 2016 LTIP Plan was $0.3 million and will be recognized over a weighted-average period of 0.6 years. On October 21, 2018, 67,414 stock options vested before consideration of minimum statutory tax withholding requirements. Non-Employee Director Restricted Stock Units Containing a Market Condition On November 23, 2016, the Company issued 76,296 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 Accounting Standards Codification 718 — Stock Compensation (“ASC 718”) as the awards allow for the withholding of taxes at the discretion of the non-employee director. At September 30, 2018, the Company recorded a $0.1 million liability included within accrued liabilities on the unaudited interim condensed consolidated balance sheets related to the restricted stock units containing a market condition. The fair value of the restricted stock units containing a market condition was $1.36 per unit at September 30, 2018. As of September 30, 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 135,778 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 (i) 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 (ii) 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 and $0.3 million for the three and nine months ended September 30, 2018. As of September 30, 2018, unrecognized stock-based compensation related to CEO RSUs containing a market condition was $1.0 million and will be recognized over a weighted-average period of 2.1 years. Performance Stock Units Issued to Certain Members of Executive Management Containing a Market Condition On March 1, 2018, the Company issued 96,305 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. 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 (i) accelerate all or a portion of the award, (ii) cancel all of the award and pay cash, stock or combination equal to the change in control price, (iii) provide for the assumption or substitution or continuation by the successor company, (iv) certify to the extent to which the vesting conditions had been achieved prior to the conclusion of the performance period or (v) 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. 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 and $0.3 million for the three and nine months ended September 30, 2018. As of September 30, 2018, unrecognized stock-based compensation related to executive management’s restricted stock units containing a market condition was $1.0 million and will be recognized over a weighted-average period of 2.3 years.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 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 several months. Therefore, for the nine months ended September 30, 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 nine months ended September 30, 2018, the Company has estimated deductions of $25.5 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 September 30, 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 transitional guidance has been issued related to IRC Section 162(m). The Company has begun to analyze this guidance and has reviewed the terms of the Company's compensation plans and agreements to assess its impact on awards granted prior to November 2, 2017, subject to the grandfather provisions. Thus, the Company has not adjusted certain tax items previously reported on its financial statements that may be impacted by IRC Section 162(m). The Company expects to complete its analysis within the measurement period in accordance with SAB 118. Management does not expect the future revision of its estimate for IRC Section 162(m) items due to the completion of this analysis to have a material impact on the financial statements because any revision would be offset by a valuation allowance. For the nine months ended September 30, 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 nine months ended September 30, 2018, the Company’s valuation allowance decreased by $3.6 million from December 31, 2017, bringing the total valuation allowance to $116.5 million at September 30, 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	9 Months Ended
	Sep. 30, 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 September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands, except per (in thousands, except per share amounts) share amounts) Net Income: Net income $ 11,516 $ 3,663 $ 13,977 $ 35,890 Participating securities—non-vested restricted stock (351) (82) (400) (932) Basic and diluted income $ 11,165 $ 3,581 $ 13,577 $ 34,958 Common Shares: Common shares outstanding — basic (1) 25,332 25,116 25,321 25,074 Dilutive effect of potential common shares — — — — Common shares outstanding — diluted 25,332 25,116 25,321 25,074 Net Income Per Share: Basic $ 0.44 $ 0.14 $ 0.54 $ 1.39 Diluted $ 0.44 $ 0.14 $ 0.54 $ 1.39 Antidilutive stock options (2) 209 424 209 526 Antidilutive warrants (3) 6,626 6,626 6,626 6,626 (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 September 30, 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, 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 income 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	9 Months Ended
	Sep. 30, 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 consolidated balance sheets at December 31, 2017, to EcoStim that was paid during the nine months ended September 30, 2018. For the three and nine months ended September 30, 2017, the Company paid approximately $5.9 million and $7.3 million, respectively, to EcoStim Energy Solutions, Inc. for services provided.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 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, seismicity claims, 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 September 30, 2018 and December 31, 2017, the Company’s total accrual for all loss contingencies was $1.1 million.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2018
Summary of Significant Accounting Policies
Basis of Presentation	Basis of Presentation These unaudited interim condensed consolidated financial statements 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, these financial statements 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 interim 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 interim condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the unaudited interim 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 interim 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 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 June 2018, the FASB issued Accounting Standards Update 2018-07, “ Compensation - Stock Compensation (Topic 718) - Improvements to Nonemployee Share-Based Payment Accounting ” (“ASU 2018-07”). ASU 2018-07 expands the scope of Topic 718 to include share-based payments issued to non-employees for goods and services. Consequently, the accounting for share-based payments to non-employees and employees will be substantially aligned. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company does not believe the adoption of ASU 2018-07 will have a material impact on its financial position, results of operations or cash flows. In July 2017, the FASB issued Accounting Standards Update 2017-11, “ Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815) ” (“ASU 2017-11”). ASU 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. Additionally, in July 2018, the FASB issued Accounting Standards Update 2018-11,"Leases (Topic 842):Targeted Improvements, which included the option to implement the standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings, as opposed to the modified retrospective transition method required when ASU 2016-02 was issued. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company has analyzed and categorized the majority of its contracts to determine if they meet the definition of a lease under ASU 2016-02. The Company’s ongoing efforts are concentrated on analyzing the remaining contracts, testing and implementing its tracking software for leases and determining the most appropriate transition method and resulting accounting impact to the Company. As a result, the Company has not quantified the impact of ASU 2016-02 and cannot reasonably quantify the impact of adoption at this time. The Company 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)	9 Months Ended
	Sep. 30, 2018
Impact of ASC 606 Adoption
Impact of adoption on the Company's results	The impact of adoption on the Company’s results is as follows for the periods presented (in thousands): Three Months Ended September 30, 2018 Under ASC 606 Under ASC 605 Decrease Oil sales $ 33,218 $ 33,237 $ (19) Natural gas liquid sales 12,720 12,733 (13) Natural gas sales 7,026 10,191 (3,165) Gathering and transportation 54 3,203 (3,149) Lease operating and workover expense 11,861 11,909 (48) Net income $ 11,516 $ 11,516 $ — Retained deficit $ (61,170) $ (61,170) $ — Nine Months Ended September 30, 2018 Under ASC 606 Under ASC 605 Decrease Oil sales $ 99,834 $ 99,879 $ (45) Natural gas liquid sales 35,651 35,709 (58) Natural gas sales 22,145 31,778 (9,633) Gathering and transportation 178 9,702 (9,524) Lease operating and workover expense 43,621 43,833 (212) Net income $ 13,977 $ 13,977 $ — Retained deficit $ (61,170) $ (61,170) $ —

Fair Value Measurements of Fi_2

Fair Value Measurements of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value Measurements of Financial Instruments
Schedule of derivative instruments measured at fair value	Fair Value Measurements at September 30, 2018 Quoted Prices Significant Other Significant in Active Markets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps $ — $ 69 $ — $ 69 Commodity derivative oil collars $ — $ 1,477 $ — $ 1,477 Commodity derivative gas collars $ — $ 431 $ — $ 431 Total assets $ — $ 1,977 $ — $ 1,977 Derivative Liabilities: Commodity derivative oil swaps $ — $ (7,110) $ — $ (7,110) Commodity derivative gas swaps $ — $ (361) $ — $ (361) Commodity derivative oil collars $ — $ (11,722) $ — $ (11,722) Commodity derivative gas collars $ — $ (355) $ — $ (355) Total liabilities $ — $ (19,548) $ — $ (19,548) Fair Value Measurements at December 31, 2017 Quoted Prices Significant Other Significant in Active Markets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (in thousands) Derivative Assets: Commodity derivative oil swaps $ — $ — $ — $ — Commodity derivative gas swaps $ — $ 821 $ — $ 821 Commodity derivative oil collars $ — $ 952 $ — $ 952 Commodity derivative gas collars $ — $ 2,611 $ — $ 2,611 Total assets $ — $ 4,384 $ — $ 4,384 Derivative Liabilities: Commodity derivative oil swaps $ — $ (3,679) $ — $ (3,679) Commodity derivative gas swaps $ — $ — $ — $ — Commodity derivative oil collars $ — $ (2,605) $ — $ (2,605) Commodity derivative gas collars $ — $ (1,333) $ — $ (1,333) Total liabilities $ — $ (7,617) $ — $ (7,617)

Risk Management and Derivativ_2

Risk Management and Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2018
Risk Management and Derivative Instruments
Schedule of commodity derivative contracts	NYMEX WTI Fixed Swaps Three-Way Collars Weighted Weighted Weighted Hedge Avg Hedge Avg Weighted Avg Position Strike Position Ceiling Avg Floor Sub-Floor (Bbls) Price (Bbls) Price Price Price Quarter Ended: September 30, 2018 175,720 $ 57.23 184,000 $ 59.93 $ 50.00 $ 40.00 December 31, 2018(1) 313,720 $ 58.59 46,000 $ 56.70 $ 50.00 $ 40.00 March 31, 2019(1) 171,000 $ 66.48 180,000 $ 63.14 $ 53.75 $ 43.75 June 30, 2019(1) 133,900 $ 64.86 182,000 $ 63.14 $ 53.75 $ 43.75 September 30, 2019(1) 46,000 $ 62.96 184,000 $ 63.14 $ 53.75 $ 43.75 December 31, 2019(1) 46,000 $ 61.43 184,000 $ 63.14 $ 53.75 $ 43.75 March 31, 2020(1) — $ — 91,000 $ 65.75 $ 50.00 $ 40.00 June 30, 2020(1) — $ — 91,000 $ 65.75 $ 50.00 $ 40.00 September 30, 2020(1) — $ — 92,000 $ 65.75 $ 50.00 $ 40.00 December 31, 2020(1) — $ — 92,000 $ 65.75 $ 50.00 $ 40.00 NYMEX HENRY HUB Fixed Swaps Three-Way Collars Weighted Weighted Weighted Hedge Weighted Hedge Avg Avg Avg Position Avg Strike Position Ceiling Floor Sub-Floor (MMBtu) Price (MMBtu) Price Price Price Quarter Ended: September 30, 2018 2,116,000 $ 2.84 1,380,000 $ 3.40 $ 3.00 $ 2.50 December 31, 2018(1) 2,055,000 $ 2.95 1,380,000 $ 3.40 $ 3.00 $ 2.50 March 31, 2019(1) 1,980,000 $ 3.01 1,350,000 $ 3.40 $ 3.00 $ 2.50 (1) Positions shown represent open commodity derivative contract positions as of September 30, 2018.
Summary of net fair values of commodity derivative instruments by the appropriate balance sheet classification in the Company's unaudited interim condensed consolidated balance sheets	The following table summarizes the net fair values of commodity derivative instruments by the appropriate balance sheet classification in the Company’s unaudited interim condensed consolidated balance sheets for the periods presented (in thousands): Type Balance Sheet Location (1) September 30, 2018 December 31, 2017 Gas swaps Derivative financial instruments - current assets $ — $ 821 Oil collars Derivative financial instruments - current assets — (760) Gas collars Derivative financial instruments - current assets — 701 Total derivative financial instruments — current assets $ — $ 762 Oil swaps Derivative financial instruments — current liabilities $ (6,753) $ (3,679) Gas swaps Derivative financial instruments - current liabilities (292) — Oil collars Derivative financial instruments - current liabilities (6,241) (370) Gas collars Derivative financial instruments - current liabilities 76 616 Total derivative financial instruments — current liabilities $ (13,210) $ (3,433) Oil swaps Derivative financial instruments — noncurrent liabilities $ (357) $ (523) Oil collars Derivative financial instruments — noncurrent liabilities (4,004) (39) Total derivative financial instruments — noncurrent liabilities $ (4,361) $ (562) Total derivative fair value at period end $ (17,571) $ (3,233) (1) The fair values of commodity derivative instruments reported in the Company’s unaudited interim 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 as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited interim condensed consolidated balance sheets for the periods presented (in thousands): September 30, 2018 Net Recognized Not Designated as Gross Recognized Gross Amounts Fair Value ASC 815 Hedges Balance Sheet Location Classification Assets/Liabilities Offset Assets/Liabilities Derivative Assets: Commodity contracts Derivative financial instruments — current $ 901 $ (901) $ — Commodity contracts Derivative financial instruments — noncurrent 1,076 (1,076) — $ 1,977 $ (1,977) $ — Derivative Liabilities: Commodity contracts Derivative financial instruments — current $ (14,111) $ 901 $ (13,210) Commodity contracts Derivative financial instruments — noncurrent (5,437) 1,076 (4,361) $ (19,548) $ 1,977 $ (17,571) December 31, 2017 Net Recognized Not Designated as Gross Recognized Gross Amounts Fair Value ASC 815 Hedges Balance Sheet Location Classification Assets/Liabilities Offset Assets/Liabilities Derivative Assets: Commodity contracts Derivative financial instruments - current $ 3,479 $ (2,717) $ 762 Commodity contracts Derivative financial instruments - noncurrent 905 (905) — $ 4,384 $ (3,622) $ 762 Derivative Liabilities: Commodity contracts Derivative financial instruments - current $ (6,150) $ 2,717 $ (3,433) Commodity contracts Derivative financial instruments - noncurrent (1,467) 905 (562) $ (7,617) $ 3,622 $ (3,995)
Schedule of net cash received for commodity derivative contracts and unrealized net gains or unrealized net losses related to the change in fair value of derivative instruments in gains (losses) on commodity derivative contracts - net for the periods	The following table presents net cash received or net cash paid for the settlement of commodity derivative contracts and unrealized net gains or unrealized net losses recorded by the Company related to the change in fair value of the derivative instruments in gains (losses) on commodity derivative contracts—net for the periods presented (in thousands): For the Three Months For the Nine Months Ended September 30, Ended September 30, 2018 2017 2018 2017 Net cash received (paid) for commodity derivative contracts $ (3,854) $ 2,909 $ (7,532) $ 6,149 Unrealized net gains (losses) (2,729) (6,500) (14,338) 2,618 Gains (losses) on commodity derivative contracts—net $ (6,583) $ (3,591) $ (21,870) $ 8,767

Property and Equipment (Tables)

Property and Equipment (Tables)	9 Months Ended
	Sep. 30, 2018
Property and Equipment
Schedule of property and equipment	September 30, 2018 December 31, 2017 Oil and gas properties, on the basis of full-cost accounting: Proved properties $ 803,841 $ 765,308 Unproved properties not being amortized 4,505 7,065 Other property and equipment 6,369 6,508 Less accumulated depreciation, depletion, amortization and impairment (251,432) (204,419) Net property and equipment $ 563,283 $ 574,462
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 and nine months ended September 30, 2018 and 2017, the Company capitalized the following (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Internal costs capitalized to oil and gas properties (1) $ 821 $ 1,651 $ 2,638 $ 4,656 (1) Inclusive of $0.3 million and $0.8 million of qualifying share-based compensation expense for the three months ended September 30, 2018 and 2017, respectively. For the nine months ended September 30, 2018 and 2017, inclusive of $0.8 million and $2.0 million, respectively, of qualifying share-based compensation expense.
Schedule of depletion expense related to oil and gas properties	Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended September, 30, September, 30, September 30, September 30, 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) (per Boe) (in thousands) (per Boe) Depletion expense $ 14,913 $ 14,575 $ 9.01 $ 7.42 $ 45,433 $ 44,695 $ 8.81 $ 7.29 Depreciation on other property and equipment 572 595 0.35 0.30 1,749 1,776 0.34 0.29 Depreciation, depletion, and amortization $ 15,485 $ 15,170 $ 9.36 $ 7.72 $ 47,182 $ 46,471 $ 9.15 $ 7.58

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	9 Months Ended
	Sep. 30, 2018
Accrued Liabilities
Schedule of the components of accrued liabilities	September 30, 2018 December 31, 2017 Accrued oil and gas capital expenditures $ 6,235 $ 9,081 Accrued revenue and royalty distributions 16,846 18,701 Accrued lease operating and workover expense 3,549 5,150 Accrued interest 215 108 Accrued taxes 2,639 2,758 Compensation and benefit related accruals 3,324 4,520 Other 3,895 2,524 Accrued liabilities $ 36,703 $ 42,842

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 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): Nine Months Ended September 30, 2018 2017 Asset retirement obligations — beginning of period $ 15,506 $ 14,200 Liabilities incurred 316 259 Revisions — — Liabilities settled (1) (107) Liabilities eliminated through asset sales (8,699) (1,146) Current period accretion expense 694 833 Asset retirement obligations — end of period $ 7,816 $ 14,039

Equity and Share-Based Compen_2

Equity and Share-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2018
Equity and Share-Based Compensation
Summary of changes in the number of shares of common stock and treasury stock	Common Treasury Stock Stock(1) Share count as of December 31, 2017 25,272,969 (99,623) Common stock issued 113,135 — Acquisition of treasury stock — (29,524) Share count as of September 30, 2018 25,386,104 (129,147) (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	Weighted-Average Grant Date Restricted Stock Fair Value Non-vested shares outstanding at December 31, 2017 324,984 $ 18.84 Granted 271,968 $ 14.24 Vested(1) (105,009) $ 19.63 Forfeited (15,167) $ 15.76 Non-vested shares outstanding at September 30, 2018 476,776 $ 16.14 (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 nine months ended September 30, 2018.
Summary of non-vested stock option activity	Weighted- Average Remaining Range of Weighted-Average Contractual Options Exercise Prices Exercise Price Term (Years) Stock options outstanding at December 31, 2017 245,845 $ 19.66 8.2 Granted — $ — $ — — Vested(1) (102,759) $ 19.08-19.66 $ 19.66 8.7 Forfeited (5,570) $ $ 19.66 0.1 Stock options outstanding at September 30, 2018 137,516 $ 19.66 8.2 Vested and exercisable at end of period(1)(2) 71,532 $ 19.08-20.97 $ 19.67 8.2 (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 nine months ended September 30, 2018. Per the 2016 LTIP Plan, these vested options had to be exercised within 180 days of employees termination or they would expire and be returned to the Plan for future reissuance. All options expired on July 31, 2018 thereby reducing the total options vested and exercisable at September 30, 2018. (2) Vested and exercisable options at September 30, 2018, had no aggregate intrinsic value.

Income Per Share (Tables)

Income Per Share (Tables)	9 Months Ended
	Sep. 30, 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 September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands, except per (in thousands, except per share amounts) share amounts) Net Income: Net income $ 11,516 $ 3,663 $ 13,977 $ 35,890 Participating securities—non-vested restricted stock (351) (82) (400) (932) Basic and diluted income $ 11,165 $ 3,581 $ 13,577 $ 34,958 Common Shares: Common shares outstanding — basic (1) 25,332 25,116 25,321 25,074 Dilutive effect of potential common shares — — — — Common shares outstanding — diluted 25,332 25,116 25,321 25,074 Net Income Per Share: Basic $ 0.44 $ 0.14 $ 0.54 $ 1.39 Diluted $ 0.44 $ 0.14 $ 0.54 $ 1.39 Antidilutive stock options (2) 209 424 209 526 Antidilutive warrants (3) 6,626 6,626 6,626 6,626 (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 September 30, 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, 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 income 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)	9 Months Ended
	Sep. 30, 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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Impact of ASC 606 Adoption
Revenues	$ 47,765	$ 49,715	$ 138,994	$ 175,409
Gathering and transportation	54	3,699	178	11,027
Lease operating and workover expense	11,861	15,653	43,621	48,064
Net income	11,516	3,663	13,977	35,890
Retained deficit	(61,170)		(61,170)		$ (75,147)
Oil
Impact of ASC 606 Adoption
Revenues	33,218	27,190	99,834	85,497
Natural gas liquid
Impact of ASC 606 Adoption
Revenues	12,720	10,656	35,651	31,580
Natural gas
Impact of ASC 606 Adoption
Revenues	7,026	$ 13,970	22,145	$ 46,321
ASU 2014-09 | Under ASC 605
Impact of ASC 606 Adoption
Gathering and transportation	3,203		9,702
Lease operating and workover expense	11,909		43,833
Net income	11,516		13,977
Retained deficit	(61,170)		(61,170)
ASU 2014-09 | Increase/(Decrease)
Impact of ASC 606 Adoption
Gathering and transportation	(3,149)		(9,524)
Lease operating and workover expense	(48)		(212)
ASU 2014-09 | Oil | Under ASC 605
Impact of ASC 606 Adoption
Revenues	33,237		99,879
ASU 2014-09 | Oil | Increase/(Decrease)
Impact of ASC 606 Adoption
Revenues	(19)		(45)
ASU 2014-09 | Natural gas liquid | Under ASC 605
Impact of ASC 606 Adoption
Revenues	12,733		35,709
ASU 2014-09 | Natural gas liquid | Increase/(Decrease)
Impact of ASC 606 Adoption
Revenues	(13)		(58)
ASU 2014-09 | Natural gas | Under ASC 605
Impact of ASC 606 Adoption
Revenues	10,191		31,778
ASU 2014-09 | Natural gas | Increase/(Decrease)
Impact of ASC 606 Adoption
Revenues	$ (3,165)		$ (9,633)

Impact of ASC 606 Adoption - Im

Impact of ASC 606 Adoption - Imbalances (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Extractive Industries [Abstract]
Production balance asset (liability)	$ 0	$ 0

Fair Value Measurements of Fi_3

Fair Value Measurements of Financial Instruments (Details) $ in Thousands	Sep. 30, 2018USD ($)Counterparty	Dec. 31, 2017USD ($)
Fair Value Measurements of Financial Instruments
Number of bank counterparties for company's commodity derivative contracts | Counterparty	4
Recurring | Total | Commodity Derivatives
Derivative Assets:
Total assets	$ 1,977	$ 4,384
Derivative Liabilities:
Total liabilities	(19,548)	(7,617)
Recurring | Total | Commodity Derivatives | Swaps | Oil
Derivative Liabilities:
Total liabilities	(7,110)	(3,679)
Recurring | Total | Commodity Derivatives | Swaps | Natural gas
Derivative Assets:
Total assets	69	821
Derivative Liabilities:
Total liabilities	(361)
Recurring | Total | Commodity Derivatives | Collars | Oil
Derivative Assets:
Total assets	1,477	952
Derivative Liabilities:
Total liabilities	(11,722)	(2,605)
Recurring | Total | Commodity Derivatives | Collars | Natural gas
Derivative Assets:
Total assets	431	2,611
Derivative Liabilities:
Total liabilities	(355)	(1,333)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives
Derivative Assets:
Total assets	1,977	4,384
Derivative Liabilities:
Total liabilities	(19,548)	(7,617)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Swaps | Oil
Derivative Liabilities:
Total liabilities	(7,110)	(3,679)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Swaps | Natural gas
Derivative Assets:
Total assets	69	821
Derivative Liabilities:
Total liabilities	(361)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Collars | Oil
Derivative Assets:
Total assets	1,477	952
Derivative Liabilities:
Total liabilities	(11,722)	(2,605)
Recurring | Significant Other Observable Inputs (Level 2) | Commodity Derivatives | Collars | Natural gas
Derivative Assets:
Total assets	431	2,611
Derivative Liabilities:
Total liabilities	$ (355)	$ (1,333)

Risk Management and Derivativ_3

Risk Management and Derivative Instruments- Hedging (Details) - Designated as Hedging Instrument - NYMEX	9 Months Ended
	Sep. 30, 2018MMBTU$ / bbl$ / MMBTUbbl
WTI | Swap Contract Quarter Ended September 30, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	175,720
Swap weighted average strike price	57.23
WTI | Swap Contract Quarter Ended December 31, 2018
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	313,720
Swap weighted average strike price	58.59
WTI | Swap Contract Quarter Ended March 31, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	171,000
Swap weighted average strike price	66.48
WTI | Swap Contract Quarter Ended June 30, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	133,900
Swap weighted average strike price	64.86
WTI | Swap Contract Quarter Ended September 30, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	46,000
Swap weighted average strike price	62.96
WTI | Swap Contract Quarter Ended December 31, 2019
Risk Management and Derivative Instruments
Hedge position (Bbls) | bbl	46,000
Swap weighted average strike price	61.43
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 September 30, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	2,116,000
Swap weighted average strike price | $ / MMBTU	2.84
HENRY HUB | Swap Contract Quarter Ended December 31, 2018
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	2,055,000
Swap weighted average strike price | $ / MMBTU	2.95
HENRY HUB | Swap Contract Quarter Ended March 31, 2019
Risk Management and Derivative Instruments
Hedge position (MMBtu) | MMBTU	1,980,000
Swap weighted average strike price | $ / MMBTU	3.01
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 Derivativ_4

Risk Management and Derivative Instruments- Balance Sheet Presentation (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Total derivative financial instruments - current liabilities	$ (13,210)	$ (3,433)
Total derivative financial instruments - noncurrent liabilities	(4,361)	(562)
Commodity Derivatives | Not designated as Hedging Instrument
Total derivative financial instruments - current assets		762
Total derivative financial instruments - current liabilities	(13,210)	(3,433)
Total derivative financial instruments - noncurrent liabilities	(4,361)	(562)
Total derivative fair value at period end	(17,571)	(3,233)
Derivative assets:
Gross Recognized Assets	1,977	4,384
Gross Amounts Offset, Assets	(1,977)	(3,622)
Net Recognized Fair Value Assets		762
Derivative liabilities:
Gross Recognized Liabilities	(19,548)	(7,617)
Gross Amounts Offset, Liabilities	1,977	3,622
Net Recognized Fair Value Liabilities	(17,571)	(3,995)
Current Assets | Commodity Derivatives | Not designated as Hedging Instrument
Derivative assets:
Gross Recognized Assets	901	3,479
Gross Amounts Offset, Assets	(901)	(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	1,076	905
Gross Amounts Offset, Assets	(1,076)	(905)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument
Derivative liabilities:
Gross Recognized Liabilities	(14,111)	(6,150)
Gross Amounts Offset, Liabilities	901	2,717
Net Recognized Fair Value Liabilities	(13,210)	(3,433)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Leasehold interest swap | Oil
Total derivative financial instruments - current liabilities	(6,753)	(3,679)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Leasehold interest swap | Natural gas
Total derivative financial instruments - current liabilities	(292)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Oil
Total derivative financial instruments - current liabilities	(6,241)	(370)
Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Natural gas
Total derivative financial instruments - current liabilities	76	616
Non-Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument
Derivative liabilities:
Gross Recognized Liabilities	(5,437)	(1,467)
Gross Amounts Offset, Liabilities	1,076	905
Net Recognized Fair Value Liabilities	(4,361)	(562)
Non-Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Leasehold interest swap | Oil
Total derivative financial instruments - noncurrent liabilities	(357)	(523)
Non-Current Liabilities | Commodity Derivatives | Not designated as Hedging Instrument | Collars | Oil
Total derivative financial instruments - noncurrent liabilities	$ (4,004)	$ (39)

Risk Management and Derivativ_5

Risk Management and Derivative Instruments - Gain Loss (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Gains (losses) on Commodity Derivative Contracts
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments			$ (7,532)	$ 6,149
Gains (losses) on commodity derivative contracts - net	$ (6,583)	$ (3,591)	(21,870)	8,767
Not designated as Hedging Instrument
Gains (losses) on Commodity Derivative Contracts
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments	3,854	(2,909)	7,532	(6,149)
Unrealized net gains (losses)	(2,729)	(6,500)	(14,338)	2,618
Gains (losses) on commodity derivative contracts - net	$ (6,583)	$ (3,591)	$ (21,870)	$ 8,767

Property and Equipment (Details

Property and Equipment (Details) $ in Thousands	May 31, 2018USD ($)	Sep. 30, 2018USD ($)$ / Boe	Sep. 30, 2017USD ($)$ / Boe	Sep. 30, 2018USD ($)$ / Boe	Sep. 30, 2017USD ($)$ / Boe	Dec. 31, 2017USD ($)
Oil and gas properties, on the basis of full-cost accounting
Proved properties		$ 803,841		$ 803,841		$ 765,308
Unproved properties not being amortized		4,505		4,505		7,065
Other property and equipment		6,369		6,369		6,508
Less accumulated depreciation, depletion, amortization and impairment		(251,432)		(251,432)		(204,419)
Net property and equipment		563,283		563,283		$ 574,462
Other information
Depreciation, depletion, and amortization		15,485	$ 15,170	47,182	$ 46,471
Reserve-Based Revolving Credit Facility
Other information
Repayment of debt				50,000
Discontinued Operations Disposed Of by Sale
Other information
Gain or loss recognized on disposal of oil and gas equipment	$ 0
Proceeds from the sale of oil and gas equipment	58,000
Net proceeds from the sale of oil and gas equipment	$ 54,400
Oil and Gas
Other information
Internal costs capitalized to oil and gas properties		821	1,651	2,638	4,656
Capitalized qualifying share-based compensation expense		300	800	800	2,000
Depletion expense		14,913	14,575	45,433	44,695
Depreciation on other property and equipment		$ 572	$ 595	$ 1,749	$ 1,776
Depletion expense (per Boe) | $ / Boe		9.01	7.42	8.81	7.29
Depreciation on other property and equipment (per Boe) | $ / Boe		0.35	0.30	0.34	0.29
Depreciation, depletion, and amortization (per Boe) | $ / Boe		9.36	7.72	9.15	7.58
Depreciation, depletion, and amortization		$ 15,485	$ 15,170	$ 47,182	$ 46,471
Impairment of unproved properties		$ 0	$ 0	0	0
Oil and Gas | Discontinued Operations Disposed Of by Sale
Other information
Gain or loss recognized on disposal of oil and gas equipment				0	0
Net proceeds from the sale of oil and gas equipment				$ 400	$ 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	Sep. 30, 2018	Dec. 31, 2017
Accrued Liabilities
Accrued oil and gas capital expenditures	$ 6,235	$ 9,081
Accrued revenue and royalty distributions	16,846	18,701
Accrued lease operating and workover expense	3,549	5,150
Accrued interest	215	108
Accrued taxes	2,639	2,758
Compensation and benefit related accruals	3,324	4,520
Other	3,895	2,524
Accrued liabilities	$ 36,703	$ 42,842

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Changes in asset retirement obligations
Asset retirement obligations at beginning of period			$ 15,506	$ 14,200
Liabilities incurred			316	259
Liabilities settled			(1)	(107)
Liabilities eliminated through asset sales			(8,699)	(1,146)
Current period accretion expense	$ 147	$ 274	694	833
Asset retirement obligations at end of period	$ 7,816	$ 14,039	$ 7,816	$ 14,039

Debt (Details)

Debt (Details) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2018USD ($)	Dec. 31, 2017USD ($)	Oct. 24, 2018USD ($)
Debt
Repayment of credit facility	$ 100,000
Reserve-Based Revolving Credit Facility
Debt
Maximum borrowing capacity	170,000	$ 170,000	$ 170,000
Repayment of credit facility	100,000
Repayment from available cash	50,000
Repayment of debt	50,000
Amount drawn from credit facility	28,100	128,100
Availability under the facility	$ 140,000
Weighted-average interest rate (as a percent)	6.70%
Unamortized debt issuance costs	$ 900	1,200
Commitment fee (as a percent)	0.50
Letter of Credit
Debt
Outstanding letters of credit amount	$ 1,900	$ 1,900
LIBOR Loans | Reserve-Based Revolving Credit Facility
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

Equity and Share-Based Compen_3

Equity and Share-Based Compensation - Common Shares (Details)	9 Months Ended
	Sep. 30, 2018shares
Common Stock
Changes in number of shares outstanding
Share count at the beginning of the period (in shares)	25,272,969
Common stock issued (in shares)	113,135
Share count at the end of the period (in shares)	25,386,104
Treasury Stock
Changes in number of shares outstanding
Treasury Stock, Shares, Beginning Balance	(99,623)
Acquisition of treasury stock (in shares)	(29,524)
Treasury Stock, Shares, Ending Balance	(129,147)

Equity and Share-Based Compen_4

Equity and Share-Based Compensation - Long Term Incentive Plan (Details) - 2016 LTIP - shares	Sep. 30, 2018	Oct. 21, 2016
Share-Based Compensation
Number of shares authorized	2,066,380
Number of shares available for future issuance		3,513,950

Equity and Share-Based Compen_5

Equity and Share-Based Compensation - Restricted Stock Units (Details) - Restricted Stock Units - USD ($) $ / shares in Units, $ in Millions	Oct. 21, 2018	Sep. 30, 2018
Restricted Stock
Non-vested shares outstanding at the beginning of the period (in shares)		324,984
Granted (in shares)		271,968
Vested (in shares)	(67,414)	(105,009)
Forfeited (in shares)		(15,167)
Non-vested shares outstanding at the end of the period (in shares)		476,776
Weighted Average Grant Date Fair Value
Non-vested shares outstanding at the beginning of the period (in dollars per share)		$ 18.84
Granted (in dollars per share)		14.24
Vested (in dollars per share)		19.63
Forfeited (in dollars per share)		15.76
Non-vested shares outstanding at the end of the period (in dollars per share)		$ 16.14
Additional information
Accelerated vesting due to change reduction in workforce (in shares)		102,092
2016 LTIP
Share-Based Compensation
Vesting period		3 years
Additional information
Unrecognized expense for share-based compensation		$ 2.9
Weighted-average period for over which unrecognized expense will be recognized		10 months 24 days
Awards vesting on the six-month anniversary of the Effective Date | 2016 LTIP
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
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
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant		33.33%

Equity and Share-Based Compen_6

Equity and Share-Based Compensation - Stock Options (Details) - 2016 LTIP - Stock Options - USD ($) $ / shares in Units, $ in Thousands	Oct. 21, 2018	Sep. 30, 2018	Dec. 31, 2017
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)	(67,414)
Stock options outstanding at end of period (in shares)		137,516	245,845
Weighted Average Exercise Price
Stock options outstanding at beginning of period (in dollars per share)		$ 19.66
Stock options outstanding at end of period (in dollars per share)		$ 19.66	$ 19.66
Weighted Average Remaining Contractual Term (Years)
Stock options outstanding at end of period (in years)		8 years 2 months 12 days	8 years 2 months 12 days
Vested and exercisable options, aggregate intrinsic value		$ 0
Additional information
Accelerated vesting due to change reduction in workforce (in shares)		102,092
Unrecognized expense for share-based compensation		$ 300
Weighted-average period for over which unrecognized expense will be recognized		7 months 6 days
Options granted during the period		0
$19.08-$19.66
Options
Vested (in shares)		(102,759)
Exercise price (Lower limit)		$ 19.08
Exercise price (Upper limit)		19.66
Weighted Average Exercise Price
Weighted average vested price of vested options (in dollars per share)		$ 19.66
Weighted Average Remaining Contractual Term (Years)
Vested (in years)		8 years 8 months 12 days
$ 19.66
Options
Forfeited (in shares)		(5,570)
Weighted Average Exercise Price
Forfeited (in dollars per share)		$ 19.66
Weighted Average Remaining Contractual Term (Years)
Forfeited (in years)		1 month 6 days
$19.08 - $20.97
Options
Vested and exercisable at end of period (in shares)		71,532
Exercise price (Lower limit)		$ 19.08
Exercise price (Upper limit)		20.97
Weighted Average Exercise Price
Vested and exercisable at end of period (in dollars per share)		$ 19.67
Weighted Average Remaining Contractual Term (Years)
Vested and exercisable at end of period (in years)		8 years 2 months 12 days
Awards vesting on the six-month anniversary of the Effective Date
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
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
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
Share-Based Compensation
Percentage of awards vesting on each anniversary of the grant		33.33%

Equity and Share-Based Compen_7

Equity and Share-Based Compensation - Non-Employee Director Restricted Stock Units Containing a Market Condition (Details) - Performance stock units - Non-employee directors - USD ($) $ / shares in Units, $ in Millions	Nov. 23, 2016	Sep. 30, 2018
Share-Based Compensation
Granted (in shares)	76,296
Trailing average share price period based on common stock (in days)	60 days
Market Price Hurdle (in dollars per share)	$ 30
Calculated fair value per stock option (in dollars per share)		$ 1.36
Unrecognized expense for share-based compensation		$ 0
Accrued liabilities
Share-Based Compensation
Liability related to market condition awards		$ 0.1

Equity and Share-Based Compen_8

Equity and Share-Based Compensation - Chief Executive Officer Restricted Stock Units Containing a Market Condition (Details) - Performance stock units - USD ($) $ in Millions	Mar. 01, 2018	Nov. 01, 2017	Sep. 30, 2018	Sep. 30, 2018
Chief Executive Officer
Share-Based Compensation
Granted (in shares)		135,778
RSUs granted based on actual TSR (as a percentage)		50.00%
RSUs granted based on relative TSR (as a percentage)		50.00%
Days considered for calculation of average stock price		20 days
Assumptions used to estimate fair value of restricted stock unit awards with market condition
Service period (in years)		3 years
Share-based compensation costs recognized			$ 0.1	$ 0.3
Unrecognized expense for share-based compensation			1	$ 1
Weighted-average period for over which unrecognized expense will be recognized				2 years 1 month 6 days
Chief Executive Officer | Maximum
Share-Based Compensation
Percentage of vesting of RSUs granted (as a percentage)		120.00%
Executive officer
Share-Based Compensation
Granted (in shares)	96,305
Assumptions used to estimate fair value of restricted stock unit awards with market condition
Service period (in years)				3 years
Share-based compensation costs recognized			0.1	$ 0.3
Unrecognized expense for share-based compensation			$ 1	$ 1
Weighted-average period for over which unrecognized expense will be recognized				2 years 3 months 18 days

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	Jan. 01, 2018	Sep. 30, 2018
Income Taxes
Estimated deduction associated with cost of qualified asset		$ 25.5
Valuation allowance		116.5
Increase (decrease) in valuation allowance		(3.6)
Current
Current income tax		0
Deferred
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, $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Income Per Share
Net income	$ 11,516	$ 3,663	$ 13,977	$ 35,890
Participating securities-non-vested restricted stock	(351)	(82)	(400)	(932)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 11,165	$ 3,581	$ 13,577	$ 34,958
Common shares outstanding - basic	25,332,000	25,116,000	25,321,000	25,074,000
Common shares outstanding - diluted	25,332,000	25,116,000	25,321,000	25,074,000
Basic (in dollars per share)	$ 0.44	$ 0.14	$ 0.54	$ 1.39
Diluted (in dollars per share)	$ 0.44	$ 0.14	$ 0.54	$ 1.39
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)	209,000	424,000	209,000	526,000
Warrants
Income Per Share
Antidilutive securities (in shares)	6,626,000	6,626,000	6,626,000	6,626,000

Related Party Transactions (Det

Related Party Transactions (Details) - Affiliate of holder of outstanding common stock - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2017	Dec. 31, 2017
Related Party Transactions
Accounts payable, related party			$ 2.1
Amount paid to related party	$ 5.9	$ 7.3

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Commitments and Contingencies
Loss contingency accrual	$ 1.1	$ 1.1