SilverBow Resources (SBOW) 10-Q 8 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Aug. 01, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	SILVERBOW RESOURCES, INC.
Entity Central Index Key	351,817
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Document Period End Date	Jun. 30, 2018
Amendment Flag	false
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		11,667,165

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 6,611	$ 7,806
Accounts receivable, net	22,057	27,263
Fair value of commodity derivatives	1,775	5,148
Other current assets	3,090	2,352
Total Current Assets	33,533	42,569
Property and Equipment:
Property and Equipment	796,052	712,166
Less - Accumulated depreciation, depletion, and amortization	(242,997)	(216,769)
Net Furniture, Fixtures and other equipment	553,055	495,397
Fair value of long-term commodity derivatives	3,332	2,553
Other Long-Term Assets	7,076	10,751
Total Assets	596,996	551,270
Current Liabilities:
Accounts payable and accrued liabilities	35,350	44,437
Fair value of commodity derivatives	11,742	5,075
Accrued capital costs	41,821	10,883
Accrued interest	2,597	2,106
Undistributed oil and gas revenues	10,953	12,996
Total Current Liabilities	102,463	75,497
Long-Term Debt	274,577	265,325
Deferred Tax Liabilities	328	0
Asset Retirement Obligation	4,258	8,678
Fair value of long-term commodity derivatives	5,427	2,758
Other Long-Term Liabilities	2,500	5,554
Stockholders' Equity:
Preferred Stock, Value, Outstanding	0	0
Common stock, $0.01 par value	117	116
Additional paid-in capital	282,726	279,111
Treasury stock held, at cost	(1,870)	(1,452)
Retained earnings (Accumulated deficit)	(73,530)	(84,317)
Total Stockholders' Equity (Deficit)	207,443	193,458
Total Liabilities and Stockholders' Equity	$ 596,996	$ 551,270

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Capitalized Costs, unproved property balance	$ 53,865	$ 50,377
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value per share (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares issued	11,733,036	11,621,385
Common stock, shares outstanding	11,667,165	11,570,621
Treasury stock shares held, at cost	65,871	50,764

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues:
Oil and gas sales	$ 51,347	$ 45,782	$ 104,099	$ 88,194
Costs and Expenses:
General and administrative, net	5,794	6,811	11,370	16,645
Depreciation, depletion, and amortization	13,096	10,828	26,228	20,543
Accretion of asset retirement obligation	84	576	243	1,140
Lease operating costs	3,760	4,776	8,721	10,549
Transportation and gas processing	5,421	4,761	10,446	9,146
Severance and other taxes	2,662	2,280	5,692	3,898
Operating Expenses	30,817	30,032	62,700	61,921
Operating Income (Loss)	20,530	15,750	41,399	26,273
Net gain (loss) on commodity derivatives	(10,752)	5,132	(17,107)	16,068
Interest expense, net	(6,585)	(4,642)	(12,474)	(8,249)
Other Nonoperating Income (Expense)	(546)	1	(703)	(141)
Income (Loss) Before Income Taxes	2,647	16,241	11,115	33,951
Provision (Benefit) for Income Taxes	328	0	328	0
Net Income (Loss)	$ 2,319	$ 16,241	$ 10,787	$ 33,951
Per Share Amounts-
Earnings Per Share, Basic	$ 0.20	$ 1.41	$ 0.93	$ 2.99
Earnings Per Share, Diluted	$ 0.20	$ 1.41	$ 0.92	$ 2.97
Weighted Average Shares Outstanding - Basic	11,655	11,487	11,629	11,360
Weighted Average Shares Outstanding - Diluted	11,757	11,554	11,742	11,445

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Treasury Stock	Retained Earnings (Accumulated Deficit)
Beginning Balance at Dec. 31, 2016	$ 76,055	$ 101	$ 232,917	$ (675)	$ (156,288)
Purchase of treasury shares	(777)	0	0	(777)	0
Issuance of common stock	39,180	14	39,166	0	0
Issuance of restricted stock	0	1	(1)	0	0
Amortization of share-based compensation	7,029	0	7,029	0	0
Net Income (Loss)	71,971	0	0	0	71,971
Ending Balance at Dec. 31, 2017	193,458	116	279,111	(1,452)	(84,317)
Shares issued from option exercise	708	0	708	0	0
Purchase of treasury shares	(418)	0	0	418	0
Issuance of restricted stock	0	1	(1)	0	0
Amortization of share-based compensation	2,908	0	2,908	0	0
Net Income (Loss)	10,787	0	0	0	10,787
Ending Balance at Jun. 30, 2018	$ 207,443	$ 117	$ 282,726	$ (1,870)	$ (73,530)

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) - shares	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]
Stock issued for benefit plans	0	0
Options exercised	29,199	0
Purchase of treasury stock (shares)	15,107	28,279
Employee stock purchase plan	0	0
Issuance of restricted stock (shares)	82,452	141,818
Issuance of common stock (shares)	0	1,403,508

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016
Cash Flows from Operating Activities:
Net Income (Loss)	$ 2,319	$ 16,241	$ 10,787	$ 33,951	$ 71,971
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion, and amortization	13,096	10,828	26,228	20,543
Accretion of asset retirement obligation	84	576	243	1,140	2,322
Deferred income taxes			(328)	0
Stock-based compensation expenses			2,675	3,136
Loss (gain) on derivatives			17,107	(16,068)
Cash settlements on derivatives			(1,935)	(2,586)
Settlements of asset retirement obligations			(144)	(1,894)
Debt issuance cost write-down			0	2,401
Other Noncash Income (Expense)			3,374	482
(Increase) decrease in accounts receivable and other current assets			2,332	(1,486)
Increase (decrease) in accounts payable and accrued liabilities			(8,439)	4,437
Increase (decrease) in accrued interest			491	(90)
Net Cash Provided by (Used in) Operating Activities			53,047	43,966
Cash Flows from Investing Activities:
Additions to property and equipment			(84,097)	(85,655)
Proceeds from the sale of property and equipment			26,924	460
Payments on property sale obligations			(6,042)	0
Transfer of company funds from restricted cash			0	15
Net Cash Provided by (Used in) Investing Activities			(63,215)	(85,210)
Cash Flows from Financing Activities:
Proceeds from bank borrowings			122,300	300,000
Payments of bank borrowings			(113,300)	(287,000)
Net proceeds from issuances of common stock			708	39,244
Purchase of treasury shares			(418)	(618)
Payments of debt issuance costs			(317)	(4,073)
Net Cash Provided by (Used in) Financing Activities			8,973	47,553
Net increase (decrease) in Cash, Cash Equivalents and Restricted Cash			(1,195)	6,309
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 6,831	$ 6,806	6,831	6,806	$ 8,026	$ 497
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized			10,926	8,847
Changes in capital accounts payable and capital accruals			35,299	5,356
Increase (decrease) in other long-term liabilities for capital expenditures			$ (2,500)	$ 0

General Information

General Information	6 Months Ended
	Jun. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General Information	(1) General Information SilverBow Resources, Inc. (“SilverBow,” the “Company,” or “we”) is a growth oriented independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas. Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoirs in the region. We leverage this competitive understanding to assemble high quality drilling inventory while continuously enhancing our operations to maximize returns on capital invested. The condensed consolidated financial statements included herein are unaudited and have been prepared by the Company and reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017 as filed with the Securities and Exchange Commission on March 1, 2018.

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	(2) Summary of Significant Accounting Policies Basis of Presentation . The consolidated financial statements included herein have been prepared by SilverBow, and reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation. Principles of Consolidation . The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly-owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements. Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. There were no material subsequent events requiring additional disclosure in these condensed consolidated financial statements. Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: • the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows there-from, and the ceiling test impairment calculation, • estimates related to the collectability of accounts receivable and the credit worthiness of our customers, • estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, • estimates of future costs to develop and produce reserves, • accruals related to oil and gas sales, capital expenditures and lease operating expenses, • estimates in the calculation of share-based compensation expense, • estimates of our ownership in properties prior to final division of interest determination, • the estimated future cost and timing of asset retirement obligations, • estimates made in our income tax calculations, • estimates in the calculation of the fair value of commodity derivative assets and liabilities, • estimates in the assessment of current litigation claims against the Company, and • estimates in amounts due with respect to open state regulatory audits. While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known. We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended June 30, 2018 and 2017 , such internal costs capitalized totaled $1.0 million and $1.2 million , respectively. For the six months ended June 30, 2018 and 2017 , such internal costs capitalized totaled $2.4 million and $2.1 million , respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these condensed consolidated financial statements for further discussion on capitalized interest costs). The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): June 30, 2018 December 31, 2017 Property and Equipment Proved oil and gas properties $ 738,780 $ 658,519 Unproved oil and gas properties 53,865 50,377 Furniture, fixtures, and other equipment 3,407 3,270 Less – Accumulated depreciation, depletion, amortization & impairment (242,997 ) (216,769 ) Property and Equipment, Net $ 553,055 $ 495,397 No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties-including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties-by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred. Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized. Full-Cost Ceiling Test . At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% , and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There was no write-down for each of the three months ended June 30, 2018 and 2017 and the six months ended June 30, 2018 and 2017 . If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. Revenue Recognition . The Company adopted the new revenue recognition standard for revenue from contracts from customers (ASC 606) effective January 1, 2018. See Note 3 in these condensed consolidated financial statements for further details. Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both June 30, 2018 and December 31, 2017 , we had an allowance for doubtful accounts of less than $0.1 million . The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balance on the accompanying condensed consolidated balance sheets. At June 30, 2018 , our “Accounts receivable” balance included $17.4 million for oil and gas sales, $1.1 million due from joint interest owners, $0.8 million for severance tax credit receivables and $2.8 million for other receivables. At December 31, 2017 , our “Accounts receivable” balance included $20.1 million for oil and gas sales, $2.1 million due from joint interest owners, $2.1 million for severance tax credit receivables and $3.0 million for other receivables. Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the six months ended June 30, 2018 and 2017 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $1.1 million for the three months ended June 30, 2018 and 2017 and $2.2 million and $2.3 million for the six months ended June 30, 2018 and 2017 , respectively. Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At June 30, 2018 , we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. The Company was in a net deferred tax asset position at both June 30, 2018 and June 30, 2017 for United States federal income taxes. Management has determined that it is not more likely than not that the Company will realize future cash benefits from its remaining federal carryover items and, accordingly, has taken a full valuation allowance to offset its tax assets. Tax expense associated with federal income taxes was fully offset by adjustments to the valuation allowance. We recognized $0.3 million for deferred state income tax expense during the three and six months ended June 30, 2018 . We did no t recognize any deferred state income tax expense during the three and six months ended June 30, 2017 . On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Act”). The Act makes broad and complex changes to the U.S. tax code that includes, among other provisions, a permanent reduction of the U.S. federal corporate tax rate from 35% to 21% and a repeal of the alternative minimum tax regime, both effective January 1, 2018. Because of the Company’s net deferred tax asset and valuation allowance positions, these changes did not impact tax expense for the six months ended June 30, 2018 . The provisions of the Act, including its extensive transition rules, are complex and interpretive guidance continues to develop. The Company’s deferred tax balances and offsetting valuation allowance should be considered provisional. The final application of the Act to the Company’s tax computations may result in further adjustments. Changes could arise as regulatory and interpretive action continues to clarify aspects of the Act and as changes are made to estimates that the Company has utilized in calculating the transition impacts. The Company expects make any adjustments, if necessary, related to the impacts of this legislation by the end of 2018. Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): June 30, 2018 December 31, 2017 Trade accounts payable $ 16,015 $ 20,884 Accrued operating expenses 2,316 3,490 Accrued compensation costs 2,945 5,334 Asset retirement obligations – current portion 303 2,109 Accrued non-income based taxes 5,137 3,898 Accrued corporate and legal fees 3,120 2,784 Other payables 5,514 5,938 Total accounts payable and accrued liabilities $ 35,350 $ 44,437 Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted. Long-term Restricted Cash. Long-term restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations. As of each of June 30, 2018 and December 31, 2017 , these assets were approximately $0.2 million . These amounts are restricted as to their current use and will be released when we have satisfied all plugging and abandonment obligations in certain fields. These restricted cash balances are reported in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets. The following table is a reconciliation of the total cash and cash equivalents and restricted cash in the accompanying condensed consolidated statement of cash flows and their corresponding balance sheet presentation (in thousands): June 30, 2018 December 31, 2017 June 30, 2017 Cash and cash equivalents $ 6,611 $ 7,806 $ 6,627 Long-term restricted cash (1) 220 220 179 Total cash, cash equivalents and restricted cash $ 6,831 $ 8,026 $ 6,806 (1) Long-term restricted cash is included in “ Other Long-Term Assets ” on the accompanying condensed consolidated balance sheets. Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying condensed consolidated balance sheets. For the six months ended June 30, 2018 , we purchased 15,107 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. Fresh Start Accounting. Upon emergence from bankruptcy on April 22, 2016, the Company adopted Fresh Start Accounting. As a result of the application of fresh start accounting, as well as the effects of the implementation of the joint plan of reorganization (the “Plan”), the Consolidated Financial Statements on or after April 22, 2016, are not comparable with the Consolidated Financial Statements prior to that date. New Accounting Pronouncements. In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Updated (“ASU”) 2016-02, which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. At December 31, 2017 the Company’s total lease commitments were approximately $6.2 million . There have been no material changes to our previously disclosed lease commitment amounts. Of this total, $2.0 million is related to our corporate office sub-lease which has a remaining term of approximately three years. The remaining commitments are generally for equipment and vehicle leases, most of which are expiring during 2018. The Company did not enter into any significant additional lease obligations during the first six months of 2018 and is in the process of evaluating other contracts that may contain lease components that need to be recognized under this standard. Management plans to adopt ASU 2016-02 in the quarter ending March 31, 2019. Management continuously evaluates the economics of leasing versus purchase for operating equipment. The lease obligations that will be in place upon adoption of ASU 2016-02 may be significantly different than the current obligations. Accordingly, at this time we cannot estimate the amount that will be capitalized when this standard is adopted. In January 2017, the FASB issued ASU 2017-01, to assist entities in evaluating whether transactions should be accounted for as an acquisition or disposal of an asset or business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities are not a business. The guidance is effective for companies beginning January 1, 2018, with early adoption permitted. The Company has adopted this guidance as of January 1, 2018, and will apply it to any subsequent transactions.

Revenue Recognition Revenue Rec

Revenue Recognition Revenue Recognition (Notes)	6 Months Ended
	Jun. 30, 2018
Revenue Recognition [Abstract]
Revenue Recognition	(3) Revenue Recognition Effective January 1, 2018, we adopted ASC 606 - Revenue from Contracts with Customers using the modified retrospective method of adoption. ASC 606 supersedes previous revenue recognition requirements in ASC 605. The new standard includes a five-step revenue recognition model to follow to determine the timing and amounts to be recognized as revenues in an entity’s financial statements. We have modified our processes and controls to ensure our reported oil and gas sales revenue is determined in accordance with this standard. Adoption of this standard did not result in a different amount reported for oil and gas sales than what we would have reported under the previous standard. Accordingly, there was no cumulative effect adjustment required upon adoption. Virtually all of our revenue reported as oil and gas sales in our condensed consolidated statements of operations is derived from contracts. No other material revenue sources are attributable to Revenue from Contracts within the scope of ASC 606. Revenue from Contracts with Customers Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. The types of contracts vary between product streams as described below: Sales Contracts for Unprocessed Gas We deliver natural gas to midstream entities at field delivery meter stations, under either transportation or processing agreements. For unprocessed gas (delivered under transportation or gathering agreements), we retain title to the gas through the redelivery points into downstream pipelines. The purchasers take title and control at these redelivery points. Sales proceeds are determined using the gas delivered for each monthly period based on an agreed upon index. We record the monthly proceeds realized at the redelivery points as gas sales revenue, and record the fees paid to the mid-stream pipeline as transportation expense. Contracts for Processed Gas and NGLs NGLs are unique in that they remain in a gas state through normal field operations, and are typically part of the gas stream delivered to a gas processor. A gas processing facility is necessary to separate the NGLs from the gas. The most common NGL components are ethane, propane, butane, isobutane and pentane. Each of these NGL components has unique industrial and/or residential markets. Prices, which are typically quoted on a per gallon basis, can vary substantially between these products. Where our raw gas contains commercially recoverable NGL components, we enter into agreements with midstream gas processors under which the processor takes delivery at meter stations in the field and transports the gas to its processing facility. The processing facility extracts the recoverable NGLs and the remaining natural gas (“residue gas”) is delivered to a downstream pipeline, while the processor typically takes control of and purchases the NGLs at the plant tailgate. We either take delivery of (take in kind) the residue gas at the plant tailgate and sell it to third party purchasers, or we sell the residue gas to the processor. Sales to third parties are negotiated on a monthly, seasonal or term basis and are priced at applicable market indexes. When we sell to the processor, the sales price is determined using monthly index prices. When we sell the NGLs to the processor, each NGL component has a separate index price. The processor’s statement segregates the individual component quantities and lists separate settlement amounts for each NGL component. The processor charges service or processing fees that are fixed in the processing agreement. We aggregate the revenue for all components and record NGL revenues as a single product. Based on an analysis of the terms of our existing contracts, we determined that under substantially all of our processing agreements, we retain control of both the gas and NGLs through the processing facilities. As a result, the processor is both a service provider and a customer of the NGLs (and residue gas not sold to other parties) with the sales occurring at the plant outlet. Accordingly, we record gas and NGL sales at the value realized at the plant tailgate and record the processor’s fees as transportation and processing expense. Contracts for Oil sales Under our oil sales contracts, we sell oil production at field delivery points at agreed-upon index pricing, adjusted for location differentials and product quality. Oil is priced on a per barrel basis. Oil is picked up by our purchasers’ trucks at our tank batteries. Control transfers when it is loaded on the purchasers’ trucks. We record oil revenue at the price received at the pick-up points. Contract balances Under our contracts we either invoice our customers on a monthly basis or receive monthly settlement statements from the purchasers. Invoices and settlement statements cover the products delivered during the calendar month. The performance obligation is deemed fully satisfied for each unit of product at the time control is transferred to the purchaser. Payment of each monthly settlement is unconditional. Accordingly, our product sales contracts do not give rise to any contract assets or liabilities connected to future performance obligations under ASC 606. Receivables for oil and gas sales are included in Accounts Receivable, net in the condensed consolidated balance sheets. See Note 2 above. Settlements for performance obligations We record revenue for the production delivered to the purchasers during each monthly accounting period. Settlements typically occur 30 - 60 days after the end of the delivery month. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals. Adjustments to prior period estimates were not material for the periods presented in our condensed consolidated statements of operations. Transaction price allocated to remaining performance obligations Our contract terms vary, with many being greater than one-year. The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14, applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Product prices under our long-term contracts (with delivery obligations greater than one month) are tied to indexes reflective of market value at the time of delivery. Production imbalances Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances which is no longer available under ASC 606. To comply with the new standard, natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers. We do not have any material imbalances, so this change had no impact on our reported revenues. Oil and Gas sales by product The following table provides information regarding our oil and gas sales, by product, reported on the Statements of Operations for the three months ended June 30, 2018 and 2017 and the six months ended June 30, 2018 and 2017 (in thousands): Three Months Ended June 30, 2018 Three Months Ended June 30, 2017 Six Months Ended June 30, 2018 Six Months Ended June 30, 2017 Oil, natural gas and NGLs sales: Oil $ 9,638 $ 6,527 $ 21,078 $ 13,728 Natural gas 36,369 35,043 72,136 66,106 NGLs 5,339 4,215 10,900 8,363 Other — (3 ) (14 ) (3 ) Total $ 51,347 $ 45,782 $ 104,099 $ 88,194

Share-Based Compensation

Share-Based Compensation	6 Months Ended
	Jun. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation	(4) Share-Based Compensation Share-Based Compensation Plans Upon the Company's emergence from bankruptcy on April 22, 2016, the Company's previous share-based compensation plans were canceled and the new 2016 Equity Incentive Plan was approved in accordance with the joint plan of reorganization. Under the previous share-based compensation plan, the outstanding restricted stock awards and restricted stock unit awards for most employees vested on an accelerated basis while awards issued to certain officers of the Company and the Board of Directors were canceled in April 2016 For awards granted after emergence from bankruptcy, the Company does not estimate the forfeiture rate during the initial calculation of compensation cost but rather has elected to account for forfeitures in compensation cost when they occur. The Company computes a deferred tax benefit for restricted stock awards, unit awards and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock units, the Company's actual tax deduction is based on the value of the units at the time of vesting. The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.3 million and $1.6 million for the three months ended June 30, 2018 and 2017 , respectively, and $2.7 million and $3.1 million for the six months ended June 30, 2018 and 2017 , respectively. Capitalized share-based compensation was $0.1 million for each of the three months ended June 30, 2018 and 2017 , and $0.2 million for each of the six months ended June 30, 2018 and 2017 . We view stock option awards and restricted stock unit awards with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards. Stock Option Awards The compensation cost related to stock option awards is based on the grant date fair value and is typically expensed over the vesting period (generally one to five years). We use the Black-Scholes-Merton option pricing model to estimate the fair value of stock option awards. At June 30, 2018 , we had $3.9 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the six months ended June 30, 2018 : Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 508,730 $ 26.82 Options granted — $ — Options forfeited (21,319 ) $ 29.96 Options expired (8,356 ) $ 26.96 Options exercised (29,199 ) $ 24.27 Options outstanding, end of period 449,856 $ 26.98 Options exercisable, end of period 141,347 $ 25.84 O ur outstanding stock option awards at June 30, 2018 had $1.2 million of aggregate intrinsic value. At June 30, 2018 , the weighted average remaining contract life of stock option awards outstanding was 6.6 years and exercisable was 3.6 years. The total intrinsic value of stock option awards exercisable for the six months ended June 30, 2018 was $0.5 million . Restricted Stock Units The 2016 equity incentive compensation plan allows for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. The compensation cost related to these awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one to five years ). As of June 30, 2018 , we had unrecognized compensation expense of $7.3 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 2.6 years. The following table provides information regarding restricted stock unit award activity for the six months ended June 30, 2018 : Shares Grant Date Price Restricted stock units outstanding, beginning of period 346,740 $ 26.99 Restricted stock units granted 91,906 $ 27.89 Restricted stock units forfeited (21,011 ) $ 26.59 Restricted stock units vested (81,754 ) $ 25.04 Restricted stock units outstanding, end of period 335,881 $ 27.74 Performance-Based Stock Units On February 20, 2018, the Company granted 30,700 performance-based stock units for which the number of shares earned is based on the Total Shareholder Return ("TSR") of the Company's common stock relative to the TSR of its selected peers ("Peer Group") during the performance period from January 1, 2018 to December 31, 2020 ("Performance Period"). The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the date of valuation was $41.66 per unit or 150.61% as a percentage of stock price with a remaining performance period of 2.7 years. The compensation expense for these awards is based on the per unit grant date valuation using a Monte-Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. As of June 30, 2018 , we had unrecognized compensation expense of $1.1 million related to our performance-based stock units, which is expected to be recognized over a period of three years. No shares vested during the six months ended June 30, 2018 .

Earnings Per Share

Earnings Per Share	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Earnings Per Share	(5) Earnings Per Share Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. Diluted earnings per share ("Diluted EPS") assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and restricted stock grants that would potentially dilute Basic EPS in the future were also antidilutive for the three months ended June 30, 2018 and 2017 and the six months ended June 30, 2018 and 2017 are discussed below. The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): Three Months Ended June 30, 2018 Three Months Ended June 30, 2017 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 2,319 11,655 $ 0.20 $ 16,241 11,487 $ 1.41 Dilutive Securities: Restricted Stock Awards — — Restricted Stock Unit Awards 16 59 Stock Option Awards 86 8 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 2,319 11,757 $ 0.20 $ 16,241 11,554 $ 1.41 Six Months Ended June 30, 2018 Six Months Ended June 30, 2017 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 10,787 11,629 $ 0.93 $ 33,951 11,360 $ 2.99 Dilutive Securities: Restricted Stock Awards — — Restricted Stock Unit Awards 17 73 Stock Option Awards 96 12 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 10,787 11,742 $ 0.92 $ 33,951 11,445 $ 2.97 Approximately 0.4 million stock options to purchase shares were not included in the computation of Diluted EPS for each of the three months ended June 30, 2018 and 2017 and the six months ended June 30, 2018 and 2017 because these stock options were antidilutive. Less than 0.1 million and approximately 0.1 million shares of restricted stock units that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended June 30, 2018 and 2017 because they were antidilutive. There were less than 0.1 million and approximately 0.1 million antidilutive shares of restricted stock units for the six months ended June 30, 2018 and 2017 . Less than 0.1 million shares of performance-based restricted stock units were not included in the computation of Diluted EPS for the three and six months ended June 30, 2018 because they were antidilutive. Approximately 4.3 million warrants to purchase common stock were not included in the computation of Diluted EPS for the three months ended June 30, 2018 and 2017 and for the six months ended June 30, 2018 and 2017 because these warrants were antidilutive.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Long-Term Debt	(6) Long-Term Debt The Company's long-term debt consisted of the following (in thousands): June 30, 2018 December 31, 2017 Credit Facility Borrowings (1) $ 82,000 $ 73,000 Second Lien Notes due 2024 200,000 200,000 282,000 273,000 Unamortized discount on Second Lien Notes due 2024 (1,889 ) (1,992 ) Unamortized debt issuance cost on Second Lien Notes due 2024 (5,534 ) (5,683 ) Long-Term Debt, net $ 274,577 $ 265,325 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of each of June 30, 2018 and December 31, 2017 , we had $4.9 million and $5.5 million , respectively, in unamortized debt issuance costs on our Credit Facility borrowings. Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $82.0 million and $73.0 million as of each of June 30, 2018 and December 31, 2017 , respectively. On April 19, 2017, the Company entered into a First Amended and Restated Senior Secured Revolving Credit Agreement among the Company, as borrower, JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended, including the Third Amendment dated April 20, 2018 (the “Third Amendment to Credit Agreement”) to the First Amended and Restated Senior Secured Credit Agreement (as amended, the “Credit Agreement” and such facility, the “Credit Facility”). The Third Amendment to Credit Agreement reaffirmed the borrowing base at $330 million , decreased the applicable margin used to calculate the interest rate under the Credit Agreement by 50 basis points and carved out certain permitted basis differential swaps from the calculation of the maximum hedging covenant in the Credit Agreement. The Credit Facility matures April 19, 2022, and provides for a maximum credit amount of $600 million . The borrowing base is regularly redetermined on or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders in their discretion in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million , which reduce the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. Interest under the Credit Facility accrues at the Company’s option either at an Alternative Base Rate plus the applicable margin (“ABR Loans”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”). As of April 20, 2018, the applicable margin ranges from 1.25% to 2.25% for ABR Loans and 2.25% to 3.25% for Eurodollar Loans. The Alternate Base Rate and LIBOR Rates are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.50% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and certain of its subsidiaries, including a first priority lien on properties attributed with at least 85% of estimated proved reserves of the Company and its subsidiaries. The Credit Agreement contains the following financial covenants: • a ratio of total debt to EBITDA, as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed 4.0 to 1.0 as of the last day of each fiscal quarter; and • a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.0 to 1.0 as of the last day of each fiscal quarter. As of June 30, 2018 , the Company was in compliance with all financial covenants under the Credit Agreement. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodities pricing, our hedge positions and our ability to raise capital to drill wells to replaced produced reserves. Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable. Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was $1.6 million and $4.8 million for the three months ended June 30, 2018 and 2017 , respectively, and $3.1 million and $8.5 million for the six months ended June 30, 2018 and 2017 , respectively. The amount of commitment fee amortization included in interest expense, net was $0.3 million and $0.1 million for the three months ended June 30, 2018 and 2017 , respectively, and $0.6 million and $0.2 million for the six months ended June 30, 2018 and 2017 , respectively. We capitalized interest on our unproved properties in the amount $0.3 million and $0.2 million for the three months ended June 30, 2018 and 2017 , respectively, and $0.7 million and $0.4 million for the six months ended June 30, 2018 and 2017 , respectively. Senior Secured Second Lien Notes . On December 15, 2017, the Company entered into a note purchase agreement for Senior Secured Second Lien Notes (the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent (the “Second Lien Agent”), and certain holders that are a party thereto, and issued notes in an initial principal amount of $200 million , with a $2.0 million discount, for net proceeds of $198.0 million . The Company has the ability, subject to the satisfaction of certain conditions (including compliance with the Asset Coverage Ratio described below and the agreement of the holders to purchase such additional notes), to issue additional notes in a principal amount not to exceed $100 million . The Second Lien matures on December 15, 2024. On April 20, 2018 the Company entered into a First Amendment (the “First Amendment to the Second Lien”) which carves out certain permitted basis differential swaps from the calculation of the maximum hedging covenant in the Note Purchase Agreement. Interest on the Second Lien is payable quarterly and accrues at LIBOR plus 7.5% ; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus 6.5% as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the Second Lien. To the extent that a payment, insolvency or, at the holders’ election, another default exists and is continuing, all amounts outstanding under the Second Lien will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility. The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes, subject to the following repayment fees: during years one and two, a customary “make-whole” amount (which is equal to the present value of the remaining interest payments through the twenty-four month anniversary of the issuance of the Second Lien, discounted at a rate equal to the Treasury Rate plus 50 basis points) plus 2.0% of the principal amount of the notes repaid; during year three, 2.0% of the principal amount of the Second Lien being prepaid; during year four, 1.0% of the principal amount of the Second Lien being prepaid; and thereafter, no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote. The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and certain of its subsidiaries, including a mortgage lien on oil and gas properties attributed with at least 85% of estimated PV-9 of proved reserves of the Company and its subsidiaries and 85% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the Administrative Agent of the Credit Facility. The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiaries and in the denominator the total net indebtedness of the Company and its restricted subsidiaries, of not less than 1.25 to 1.0 as of each date of determination (the “Asset Coverage Ratio Requirement”). PV-10 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. The Second Lien also contains a financial covenant measuring the ratio of total net debt to EBITDA, as defined in the Second Lien purchase agreement, for the most recently completed four fiscal quarters, not to exceed 4.5 to 1.0 as of the last day of each fiscal quarter. As of June 30, 2018 , the Company was in compliance with all financial covenants under the Second Lien. The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien Facility to be immediately due and payable. As of June 30, 2018 , total net amounts recorded for the Second Lien were $192.6 million , net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $5.2 million and $10.0 million for the three and six months ended June 30, 2018 . Debt Issuance Costs . Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings.

Acquisitions and Dispositions A

Acquisitions and Dispositions Acquisitions and Dispostions	6 Months Ended
	Jun. 30, 2018
Discontinued Operations and Disposal Groups [Abstract]
Acquisitions and Dispositions	(7) Acquisitions and Dispositions On March 1, 2018, the Company closed the sale of certain wells in its AWP Olmos field for proceeds, net of selling expenses, of $27.0 million . This transaction had an effective date of January 1, 2018. The buyer assumed approximately $6.3 million in asset retirement obligations. No gain or loss was recorded on the sale of this property. Effective December 22, 2017, the Company closed a Purchase and Sale contract to sell the Company's wellbores and facilities in Bay De Chene and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017. Of the $16.3 million original obligation, $6.0 million was paid during the six months ended June 30, 2018 . Additionally, we reclassified $2.5 million in other long-term liabilities related to this sale to current liabilities. The remaining obligation under this contract is $10.2 million and is carried in the accompanying condensed consolidated balance sheet as of June 30, 2018 . This balance is made up of $7.7 million of current liability, which is included in “Accrued capital costs,” and $2.5 million , which is included in “Other Long-Term Liabilities.” There were no acquisitions or dispositions of developed properties during the three and six months ended June 30, 2017 .

Price-Risk Management Price-Ris

Price-Risk Management Price-Risk Management (Notes)	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities	(8) Price-Risk Management Activities Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in "Net gain (loss) on commodity derivatives" on the accompanying condensed consolidated statements of operations. We have a price-risk management policy to use derivative instruments to protect against declines in oil and natural gas prices, mainly through the purchase of commodity price swaps and collars as well as basis swaps. During the three months ended June 30, 2018 and 2017 , the Company recorded losses of $10.8 million and gains of $5.1 million , respectively, on its commodity derivatives. During the six months ended June 30, 2018 and 2017 , the Company recorded losses of $17.1 million and gains of $16.1 million , respectively, on its commodity derivatives. The Company made net cash payments of $1.9 million and $2.6 million for settled derivative contracts during the six months ended June 30, 2018 and 2017 , respectively. At June 30, 2018 and December 31, 2017 , we had less than $0.1 million and $2.2 million , respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in July 2018 and January 2018, respectively. At June 30, 2018 and December 31, 2017 , we also had $1.6 million and $0.4 million , respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in "Accounts payable and accrued liabilities" and were subsequently paid in July 2018 and January 2018, respectively. The fair values of our derivatives are computed using commonly accepted industry-standard models and are periodically verified against quotes from brokers. At June 30, 2018 , there was $1.8 million and $3.3 million in current and long-term unsettled derivative assets and $11.7 million and $5.4 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2017 , there was $5.1 million and $2.6 million in current and long-term unsettled derivative assets and $5.1 million and $2.8 million in current and long-term unsettled derivative liabilities, respectively. The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying balance sheets. Under the right of set-off, there was a $12.1 million net fair value liability at June 30, 2018 and a $0.1 million net fair value liability at December 31, 2017 . For further discussion, related to the fair value of the Company's derivatives, refer to Note 9 of these condensed consolidated financial statements. The following tables summarize the weighted average prices as well as future production volumes for our unsettled derivative contracts in place as of June 30, 2018 : Oil Derivative Swaps (NYMEX WTI Settlements) Total Volumes (Bbls) Weighted Average Price 2018 Contracts 3Q18 130,400 $ 52.40 4Q18 122,800 $ 52.23 2019 Contracts 1Q19 107,700 $ 52.77 2Q19 103,200 $ 52.72 3Q19 99,000 $ 52.79 4Q19 95,000 $ 52.73 2020 Contracts 1Q20 81,300 $ 52.42 2Q20 77,850 $ 52.38 3Q20 74,700 $ 52.34 4Q20 72,000 $ 52.29 Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) Total Volumes Weighted Average Price 2018 Contracts 3Q18 7,666,000 $ 2.88 4Q18 12,121,000 $ 2.96 2019 Contracts 1Q19 7,516,000 $ 3.08 2Q19 6,060,000 $ 2.83 3Q19 5,550,000 $ 2.84 4Q19 5,966,000 $ 2.84 2020 Contracts 1Q20 5,370,000 $ 2.83 2Q20 3,688,000 $ 2.76 3Q20 3,585,000 $ 2.76 4Q20 3,362,000 $ 2.77 NGL Contracts Total Volumes (Bbls) Weighted Average Price 2018 Contracts 3Q18 112,200 $ 24.78 4Q18 148,200 $ 24.78 Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs NYMEX Settlements) Total Volumes Weighted Average Price 2018 Contracts 3Q18 7,595,000 $ (0.01 ) 4Q18 11,850,000 $ (0.07 ) 2019 Contracts 1Q19 11,310,000 $ (0.08 ) 2Q19 11,975,000 $ 0.04 3Q19 12,095,000 $ 0.03 4Q19 12,095,000 $ (0.04 ) 2020 Contracts 1Q20 1,820,000 $ (0.10 ) 2Q20 1,820,000 $ (0.09 ) 3Q20 1,840,000 $ (0.07 ) 4Q20 1,840,000 $ (0.11 ) Oil Basis Contracts Total Volumes (Bbls) Weighted Average Price 2018 Contracts 3Q18 80,000 $ 4.13 4Q18 120,000 $ 4.13

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	(9) Fair Value Measurements Fair Value on a Recurring Basis . Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, Credit Facility and Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below). The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions): Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets. Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources. Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets. T he following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of June 30, 2018 and December 31, 2017 , and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these condensed consolidated financial statements. Fair Value Measurements at (in millions) Total Quoted Prices in Significant Other Significant June 30, 2018 Assets Natural Gas Derivatives $ 4.5 $ — $ 4.5 $ — Natural Gas Basis Derivatives $ 0.6 $ — $ 0.6 $ — Liabilities Natural Gas Derivatives $ 1.7 $ — $ 1.7 $ — Natural Gas Basis Derivatives $ 2.0 $ — $ 2.0 $ — Oil Derivatives $ 12.0 $ — $ 12.0 $ — Oil Basis Derivatives $ 0.2 $ — $ 0.2 $ — NGL Derivatives $ 1.3 $ — $ 1.3 $ — December 31, 2017 Assets Natural Gas Derivatives $ 7.2 $ — $ 7.2 $ — Natural Gas Basis Derivatives $ 0.3 $ — $ 0.3 $ — NGL Derivatives $ 0.1 $ — $ 0.1 $ — Liabilities Natural Gas Derivatives $ 1.3 $ — $ 1.3 $ — Natural Gas Basis Derivatives $ 0.3 $ — $ 0.3 $ — Oil Derivatives $ 5.2 $ — $ 5.2 $ — Oil Basis Derivatives $ 0.1 $ — $ 0.1 $ — NGL Derivatives $ 0.9 $ — $ 0.9 $ — Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Fair value of commodity derivatives” and “Fair value of long-term commodity derivatives,” respectively.

Asset Retirement Obligations As

Asset Retirement Obligations Asset Retirement Obligations (Notes)	6 Months Ended
	Jun. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	(10) Asset Retirement Obligations Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values. The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2017 and the six months ended June 30, 2018 (in thousands): Asset Retirement Obligations as of December 31, 2016 $ 32,256 Accretion expense 2,322 Liabilities incurred for new wells and facilities construction 253 Reductions due to sold wells and facilities (21,466 ) Reductions due to plugged wells and facilities (2,366 ) Revisions in estimates (212 ) Asset Retirement Obligations as of December 31, 2017 (1) $ 10,787 Accretion expense 243 Liabilities incurred for new wells and facilities construction 26 Reductions due to sold wells and facilities (6,265 ) Reductions due to plugged wells and facilities (145 ) Revisions in estimates (85 ) Asset Retirement Obligations as of June 30, 2018 (2) $ 4,561 (1) Includes approximately $2.1 million of current asset retirement obligations included in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets. (2) Includes approximately $0.3 million of current asset retirement obligations included in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies	6 Months Ended
	Jun. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(11) Commitments and Contingencies In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

Summary of Significant Accoun19

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation . The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly-owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements.
Use of Estimates	Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: • the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows there-from, and the ceiling test impairment calculation, • estimates related to the collectability of accounts receivable and the credit worthiness of our customers, • estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, • estimates of future costs to develop and produce reserves, • accruals related to oil and gas sales, capital expenditures and lease operating expenses, • estimates in the calculation of share-based compensation expense, • estimates of our ownership in properties prior to final division of interest determination, • the estimated future cost and timing of asset retirement obligations, • estimates made in our income tax calculations, • estimates in the calculation of the fair value of commodity derivative assets and liabilities, • estimates in the assessment of current litigation claims against the Company, and • estimates in amounts due with respect to open state regulatory audits. While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known. We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.
Property and Equipment	Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended June 30, 2018 and 2017 , such internal costs capitalized totaled $1.0 million and $1.2 million , respectively. For the six months ended June 30, 2018 and 2017 , such internal costs capitalized totaled $2.4 million and $2.1 million , respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these condensed consolidated financial statements for further discussion on capitalized interest costs). The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): June 30, 2018 December 31, 2017 Property and Equipment Proved oil and gas properties $ 738,780 $ 658,519 Unproved oil and gas properties 53,865 50,377 Furniture, fixtures, and other equipment 3,407 3,270 Less – Accumulated depreciation, depletion, amortization & impairment (242,997 ) (216,769 ) Property and Equipment, Net $ 553,055 $ 495,397 No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties-including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties-by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred. Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.
Full-Cost Ceiling Test	Full-Cost Ceiling Test . At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% , and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Accounts Receivable, Net	Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both June 30, 2018 and December 31, 2017 , we had an allowance for doubtful accounts of less than $0.1 million . The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balance on the accompanying condensed consolidated balance sheets.
Supervision Fees	Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations.
Income Taxes	Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At June 30, 2018 , we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. The Company was in a net deferred tax asset position at both June 30, 2018 and June 30, 2017 for United States federal income taxes. Management has determined that it is not more likely than not that the Company will realize future cash benefits from its remaining federal carryover items and, accordingly, has taken a full valuation allowance to offset its tax assets. Tax expense associated with federal income taxes was fully offset by adjustments to the valuation allowance. We recognized $0.3 million for deferred state income tax expense during the three and six months ended June 30, 2018 . We did no t recognize any deferred state income tax expense during the three and six months ended June 30, 2017 . On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Act”). The Act makes broad and complex changes to the U.S. tax code that includes, among other provisions, a permanent reduction of the U.S. federal corporate tax rate from 35% to 21% and a repeal of the alternative minimum tax regime, both effective January 1, 2018. Because of the Company’s net deferred tax asset and valuation allowance positions, these changes did not impact tax expense for the six months ended June 30, 2018 . The provisions of the Act, including its extensive transition rules, are complex and interpretive guidance continues to develop. The Company’s deferred tax balances and offsetting valuation allowance should be considered provisional. The final application of the Act to the Company’s tax computations may result in further adjustments. Changes could arise as regulatory and interpretive action continues to clarify aspects of the Act and as changes are made to estimates that the Company has utilized in calculating the transition impacts. The Company expects make any adjustments, if necessary, related to the impacts of this legislation by the end of 2018.
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): June 30, 2018 December 31, 2017 Trade accounts payable $ 16,015 $ 20,884 Accrued operating expenses 2,316 3,490 Accrued compensation costs 2,945 5,334 Asset retirement obligations – current portion 303 2,109 Accrued non-income based taxes 5,137 3,898 Accrued corporate and legal fees 3,120 2,784 Other payables 5,514 5,938 Total accounts payable and accrued liabilities $ 35,350 $ 44,437
Cash and Cash Equivalents and Restricted Cash	Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted. Long-term Restricted Cash. Long-term restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations. As of each of June 30, 2018 and December 31, 2017 , these assets were approximately $0.2 million . These amounts are restricted as to their current use and will be released when we have satisfied all plugging and abandonment obligations in certain fields. These restricted cash balances are reported in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets.
Treasury Stock	Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying condensed consolidated balance sheets.
New Accounting Pronouncements	New Accounting Pronouncements. In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Updated (“ASU”) 2016-02, which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. At December 31, 2017 the Company’s total lease commitments were approximately $6.2 million . There have been no material changes to our previously disclosed lease commitment amounts. Of this total, $2.0 million is related to our corporate office sub-lease which has a remaining term of approximately three years. The remaining commitments are generally for equipment and vehicle leases, most of which are expiring during 2018. The Company did not enter into any significant additional lease obligations during the first six months of 2018 and is in the process of evaluating other contracts that may contain lease components that need to be recognized under this standard. Management plans to adopt ASU 2016-02 in the quarter ending March 31, 2019. Management continuously evaluates the economics of leasing versus purchase for operating equipment. The lease obligations that will be in place upon adoption of ASU 2016-02 may be significantly different than the current obligations. Accordingly, at this time we cannot estimate the amount that will be capitalized when this standard is adopted. In January 2017, the FASB issued ASU 2017-01, to assist entities in evaluating whether transactions should be accounted for as an acquisition or disposal of an asset or business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities are not a business. The guidance is effective for companies beginning January 1, 2018, with early adoption permitted. The Company has adopted this guidance as of January 1, 2018, and will apply it to any subsequent transactions.

Revenue Recognition Revenue R20

Revenue Recognition Revenue Recognition (Policies)	6 Months Ended
	Jun. 30, 2018
Revenue Recognition [Abstract]
Revenue Recognition, Policy	Effective January 1, 2018, we adopted ASC 606 - Revenue from Contracts with Customers using the modified retrospective method of adoption. ASC 606 supersedes previous revenue recognition requirements in ASC 605. The new standard includes a five-step revenue recognition model to follow to determine the timing and amounts to be recognized as revenues in an entity’s financial statements. We have modified our processes and controls to ensure our reported oil and gas sales revenue is determined in accordance with this standard. Adoption of this standard did not result in a different amount reported for oil and gas sales than what we would have reported under the previous standard. Accordingly, there was no cumulative effect adjustment required upon adoption. Virtually all of our revenue reported as oil and gas sales in our condensed consolidated statements of operations is derived from contracts. No other material revenue sources are attributable to Revenue from Contracts within the scope of ASC 606. Revenue from Contracts with Customers Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. The types of contracts vary between product streams as described below: Sales Contracts for Unprocessed Gas We deliver natural gas to midstream entities at field delivery meter stations, under either transportation or processing agreements. For unprocessed gas (delivered under transportation or gathering agreements), we retain title to the gas through the redelivery points into downstream pipelines. The purchasers take title and control at these redelivery points. Sales proceeds are determined using the gas delivered for each monthly period based on an agreed upon index. We record the monthly proceeds realized at the redelivery points as gas sales revenue, and record the fees paid to the mid-stream pipeline as transportation expense. Contracts for Processed Gas and NGLs NGLs are unique in that they remain in a gas state through normal field operations, and are typically part of the gas stream delivered to a gas processor. A gas processing facility is necessary to separate the NGLs from the gas. The most common NGL components are ethane, propane, butane, isobutane and pentane. Each of these NGL components has unique industrial and/or residential markets. Prices, which are typically quoted on a per gallon basis, can vary substantially between these products. Where our raw gas contains commercially recoverable NGL components, we enter into agreements with midstream gas processors under which the processor takes delivery at meter stations in the field and transports the gas to its processing facility. The processing facility extracts the recoverable NGLs and the remaining natural gas (“residue gas”) is delivered to a downstream pipeline, while the processor typically takes control of and purchases the NGLs at the plant tailgate. We either take delivery of (take in kind) the residue gas at the plant tailgate and sell it to third party purchasers, or we sell the residue gas to the processor. Sales to third parties are negotiated on a monthly, seasonal or term basis and are priced at applicable market indexes. When we sell to the processor, the sales price is determined using monthly index prices. When we sell the NGLs to the processor, each NGL component has a separate index price. The processor’s statement segregates the individual component quantities and lists separate settlement amounts for each NGL component. The processor charges service or processing fees that are fixed in the processing agreement. We aggregate the revenue for all components and record NGL revenues as a single product. Based on an analysis of the terms of our existing contracts, we determined that under substantially all of our processing agreements, we retain control of both the gas and NGLs through the processing facilities. As a result, the processor is both a service provider and a customer of the NGLs (and residue gas not sold to other parties) with the sales occurring at the plant outlet. Accordingly, we record gas and NGL sales at the value realized at the plant tailgate and record the processor’s fees as transportation and processing expense. Contracts for Oil sales Under our oil sales contracts, we sell oil production at field delivery points at agreed-upon index pricing, adjusted for location differentials and product quality. Oil is priced on a per barrel basis. Oil is picked up by our purchasers’ trucks at our tank batteries. Control transfers when it is loaded on the purchasers’ trucks. We record oil revenue at the price received at the pick-up points. Contract balances Under our contracts we either invoice our customers on a monthly basis or receive monthly settlement statements from the purchasers. Invoices and settlement statements cover the products delivered during the calendar month. The performance obligation is deemed fully satisfied for each unit of product at the time control is transferred to the purchaser. Payment of each monthly settlement is unconditional. Accordingly, our product sales contracts do not give rise to any contract assets or liabilities connected to future performance obligations under ASC 606. Receivables for oil and gas sales are included in Accounts Receivable, net in the condensed consolidated balance sheets. See Note 2 above. Settlements for performance obligations We record revenue for the production delivered to the purchasers during each monthly accounting period. Settlements typically occur 30 - 60 days after the end of the delivery month. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals. Adjustments to prior period estimates were not material for the periods presented in our condensed consolidated statements of operations. Transaction price allocated to remaining performance obligations Our contract terms vary, with many being greater than one-year. The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14, applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Product prices under our long-term contracts (with delivery obligations greater than one month) are tied to indexes reflective of market value at the time of delivery. Production imbalances Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances which is no longer available under ASC 606. To comply with the new standard, natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers. We do not have any material imbalances, so this change had no impact on our reported revenues.

Share-Based Compensation Share-

Share-Based Compensation Share-Based Compensation (Policies)	6 Months Ended
	Jun. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-based Compensation, Option and Incentive Plans Policy	Share-Based Compensation Share-Based Compensation Plans Upon the Company's emergence from bankruptcy on April 22, 2016, the Company's previous share-based compensation plans were canceled and the new 2016 Equity Incentive Plan was approved in accordance with the joint plan of reorganization. Under the previous share-based compensation plan, the outstanding restricted stock awards and restricted stock unit awards for most employees vested on an accelerated basis while awards issued to certain officers of the Company and the Board of Directors were canceled in April 2016 For awards granted after emergence from bankruptcy, the Company does not estimate the forfeiture rate during the initial calculation of compensation cost but rather has elected to account for forfeitures in compensation cost when they occur. The Company computes a deferred tax benefit for restricted stock awards, unit awards and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock units, the Company's actual tax deduction is based on the value of the units at the time of vesting.

Earnings Per Share Earnings Per

Earnings Per Share Earnings Per Share (Policies)	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Earnings Per Share, Policy	Earnings Per Share Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. Diluted earnings per share ("Diluted EPS") assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and restricted stock grants that would potentially dilute Basic EPS in the future were also antidilutive for the three months ended June 30, 2018 and 2017 and the six months ended June 30, 2018 and 2017 are discussed below.

Long-Term Debt Long-Term Debt (

Long-Term Debt Long-Term Debt (Policies)	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Debt Issuance Costs, Policy	Debt Issuance Costs . Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings.

Price-Risk Management Price-R24

Price-Risk Management Price-Risk Management (Policies)	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities, Policy	Price-Risk Management Activities Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in "Net gain (loss) on commodity derivatives" on the accompanying condensed consolidated statements of operations. We have a price-risk management policy to use derivative instruments to protect against declines in oil and natural gas prices, mainly through the purchase of commodity price swaps and collars as well as basis swaps.

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Disclosures (Policies)	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments, Policy	Fair Value Measurements Fair Value on a Recurring Basis . Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, Credit Facility and Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below). The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions): Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets. Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources. Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets.

Asset Retirement Obligations 26

Asset Retirement Obligations Asset Retirement Obligations (Policies)	6 Months Ended
	Jun. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations, Policy	Asset Retirement Obligations Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values.

Commitments and Contingencies27

Commitments and Contingencies Commitments and Contingencies (Policies)	6 Months Ended
	Jun. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies, Policy	Commitments and Contingencies In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Property and Equipment	The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): June 30, 2018 December 31, 2017 Property and Equipment Proved oil and gas properties $ 738,780 $ 658,519 Unproved oil and gas properties 53,865 50,377 Furniture, fixtures, and other equipment 3,407 3,270 Less – Accumulated depreciation, depletion, amortization & impairment (242,997 ) (216,769 ) Property and Equipment, Net $ 553,055 $ 495,397
Accounts Payable and Accrued Liabilities	The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): June 30, 2018 December 31, 2017 Trade accounts payable $ 16,015 $ 20,884 Accrued operating expenses 2,316 3,490 Accrued compensation costs 2,945 5,334 Asset retirement obligations – current portion 303 2,109 Accrued non-income based taxes 5,137 3,898 Accrued corporate and legal fees 3,120 2,784 Other payables 5,514 5,938 Total accounts payable and accrued liabilities $ 35,350 $ 44,437
Cash, Cash Equivalents and Restricted Cash	The following table is a reconciliation of the total cash and cash equivalents and restricted cash in the accompanying condensed consolidated statement of cash flows and their corresponding balance sheet presentation (in thousands): June 30, 2018 December 31, 2017 June 30, 2017 Cash and cash equivalents $ 6,611 $ 7,806 $ 6,627 Long-term restricted cash (1) 220 220 179 Total cash, cash equivalents and restricted cash $ 6,831 $ 8,026 $ 6,806 (1) Long-term restricted cash is included in “ Other Long-Term Assets ” on the accompanying condensed consolidated balance sheets.

Revenue Recognition Revenue R29

Revenue Recognition Revenue Recognition (Tables)	6 Months Ended
	Jun. 30, 2018
Revenue Recognition [Abstract]
Oil and gas sales, by product [Table Text Block]	The following table provides information regarding our oil and gas sales, by product, reported on the Statements of Operations for the three months ended June 30, 2018 and 2017 and the six months ended June 30, 2018 and 2017 (in thousands): Three Months Ended June 30, 2018 Three Months Ended June 30, 2017 Six Months Ended June 30, 2018 Six Months Ended June 30, 2017 Oil, natural gas and NGLs sales: Oil $ 9,638 $ 6,527 $ 21,078 $ 13,728 Natural gas 36,369 35,043 72,136 66,106 NGLs 5,339 4,215 10,900 8,363 Other — (3 ) (14 ) (3 ) Total $ 51,347 $ 45,782 $ 104,099 $ 88,194

Share-Based Compensation (Table

Share-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock option activity	The following table provides information regarding stock option award activity for the six months ended June 30, 2018 : Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 508,730 $ 26.82 Options granted — $ — Options forfeited (21,319 ) $ 29.96 Options expired (8,356 ) $ 26.96 Options exercised (29,199 ) $ 24.27 Options outstanding, end of period 449,856 $ 26.98 Options exercisable, end of period 141,347 $ 25.84
Restricted stock activity	The following table provides information regarding restricted stock unit award activity for the six months ended June 30, 2018 : Shares Grant Date Price Restricted stock units outstanding, beginning of period 346,740 $ 26.99 Restricted stock units granted 91,906 $ 27.89 Restricted stock units forfeited (21,011 ) $ 26.59 Restricted stock units vested (81,754 ) $ 25.04 Restricted stock units outstanding, end of period 335,881 $ 27.74

Earnings Per Share (Tables)

Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS	The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): Three Months Ended June 30, 2018 Three Months Ended June 30, 2017 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 2,319 11,655 $ 0.20 $ 16,241 11,487 $ 1.41 Dilutive Securities: Restricted Stock Awards — — Restricted Stock Unit Awards 16 59 Stock Option Awards 86 8 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 2,319 11,757 $ 0.20 $ 16,241 11,554 $ 1.41 Six Months Ended June 30, 2018 Six Months Ended June 30, 2017 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 10,787 11,629 $ 0.93 $ 33,951 11,360 $ 2.99 Dilutive Securities: Restricted Stock Awards — — Restricted Stock Unit Awards 17 73 Stock Option Awards 96 12 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 10,787 11,742 $ 0.92 $ 33,951 11,445 $ 2.97

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	The Company's long-term debt consisted of the following (in thousands): June 30, 2018 December 31, 2017 Credit Facility Borrowings (1) $ 82,000 $ 73,000 Second Lien Notes due 2024 200,000 200,000 282,000 273,000 Unamortized discount on Second Lien Notes due 2024 (1,889 ) (1,992 ) Unamortized debt issuance cost on Second Lien Notes due 2024 (5,534 ) (5,683 ) Long-Term Debt, net $ 274,577 $ 265,325 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of each of June 30, 2018 and December 31, 2017 , we had $4.9 million and $5.5 million , respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

Price-Risk Management Price-R33

Price-Risk Management Price-Risk Management (Tables)	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments [Table Text Block]	The following tables summarize the weighted average prices as well as future production volumes for our unsettled derivative contracts in place as of June 30, 2018 : Oil Derivative Swaps (NYMEX WTI Settlements) Total Volumes (Bbls) Weighted Average Price 2018 Contracts 3Q18 130,400 $ 52.40 4Q18 122,800 $ 52.23 2019 Contracts 1Q19 107,700 $ 52.77 2Q19 103,200 $ 52.72 3Q19 99,000 $ 52.79 4Q19 95,000 $ 52.73 2020 Contracts 1Q20 81,300 $ 52.42 2Q20 77,850 $ 52.38 3Q20 74,700 $ 52.34 4Q20 72,000 $ 52.29 Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) Total Volumes Weighted Average Price 2018 Contracts 3Q18 7,666,000 $ 2.88 4Q18 12,121,000 $ 2.96 2019 Contracts 1Q19 7,516,000 $ 3.08 2Q19 6,060,000 $ 2.83 3Q19 5,550,000 $ 2.84 4Q19 5,966,000 $ 2.84 2020 Contracts 1Q20 5,370,000 $ 2.83 2Q20 3,688,000 $ 2.76 3Q20 3,585,000 $ 2.76 4Q20 3,362,000 $ 2.77 NGL Contracts Total Volumes (Bbls) Weighted Average Price 2018 Contracts 3Q18 112,200 $ 24.78 4Q18 148,200 $ 24.78 Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs NYMEX Settlements) Total Volumes Weighted Average Price 2018 Contracts 3Q18 7,595,000 $ (0.01 ) 4Q18 11,850,000 $ (0.07 ) 2019 Contracts 1Q19 11,310,000 $ (0.08 ) 2Q19 11,975,000 $ 0.04 3Q19 12,095,000 $ 0.03 4Q19 12,095,000 $ (0.04 ) 2020 Contracts 1Q20 1,820,000 $ (0.10 ) 2Q20 1,820,000 $ (0.09 ) 3Q20 1,840,000 $ (0.07 ) 4Q20 1,840,000 $ (0.11 ) Oil Basis Contracts Total Volumes (Bbls) Weighted Average Price 2018 Contracts 3Q18 80,000 $ 4.13 4Q18 120,000 $ 4.13

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	T he following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of June 30, 2018 and December 31, 2017 , and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these condensed consolidated financial statements. Fair Value Measurements at (in millions) Total Quoted Prices in Significant Other Significant June 30, 2018 Assets Natural Gas Derivatives $ 4.5 $ — $ 4.5 $ — Natural Gas Basis Derivatives $ 0.6 $ — $ 0.6 $ — Liabilities Natural Gas Derivatives $ 1.7 $ — $ 1.7 $ — Natural Gas Basis Derivatives $ 2.0 $ — $ 2.0 $ — Oil Derivatives $ 12.0 $ — $ 12.0 $ — Oil Basis Derivatives $ 0.2 $ — $ 0.2 $ — NGL Derivatives $ 1.3 $ — $ 1.3 $ — December 31, 2017 Assets Natural Gas Derivatives $ 7.2 $ — $ 7.2 $ — Natural Gas Basis Derivatives $ 0.3 $ — $ 0.3 $ — NGL Derivatives $ 0.1 $ — $ 0.1 $ — Liabilities Natural Gas Derivatives $ 1.3 $ — $ 1.3 $ — Natural Gas Basis Derivatives $ 0.3 $ — $ 0.3 $ — Oil Derivatives $ 5.2 $ — $ 5.2 $ — Oil Basis Derivatives $ 0.1 $ — $ 0.1 $ — NGL Derivatives $ 0.9 $ — $ 0.9 $ —

Asset Retirement Obligations 35

Asset Retirement Obligations Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Roll-forward of our asset retirement obligations	The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2017 and the six months ended June 30, 2018 (in thousands): Asset Retirement Obligations as of December 31, 2016 $ 32,256 Accretion expense 2,322 Liabilities incurred for new wells and facilities construction 253 Reductions due to sold wells and facilities (21,466 ) Reductions due to plugged wells and facilities (2,366 ) Revisions in estimates (212 ) Asset Retirement Obligations as of December 31, 2017 (1) $ 10,787 Accretion expense 243 Liabilities incurred for new wells and facilities construction 26 Reductions due to sold wells and facilities (6,265 ) Reductions due to plugged wells and facilities (145 ) Revisions in estimates (85 ) Asset Retirement Obligations as of June 30, 2018 (2) $ 4,561 (1) Includes approximately $2.1 million of current asset retirement obligations included in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets. (2) Includes approximately $0.3 million of current asset retirement obligations included in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.

Summary of Significant Accoun36

Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016
Property and Equipment
Proved oil and gas properties	$ 738,780	$ 658,519
Unproved oil and gas properties	53,865	50,377
Furniture, fixtures, and other equipment	3,407	3,270
Less - Accumulated depreciation, depletion, and amortization	(242,997)	(216,769)
Net Furniture, Fixtures and other equipment	553,055	495,397
Accounts Payable and Accrued Liabilities
Trade accounts payable	16,015	20,884
Accrued operating expenses	2,316	3,490
Accrued compensation costs	2,945	5,334
Asset retirement obligation - current portion	303	2,109
Accrued non-income based taxes	5,137	3,898
Accrued corporate and legal fees	3,120	2,784
Other payables	5,514	5,938
Total accounts payable and accrued liabilities	35,350	44,437
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	6,611	7,806	$ 6,627
Long-term restricted cash	220	220	179
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 6,831	$ 8,026	$ 6,806	$ 497

Summary of Significant Accoun37

Summary of Significant Accounting Policies (Details Textual) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2018USD ($)shares	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)shares	Dec. 22, 2017	Dec. 31, 2016USD ($)
Summary of Significant Accounting Policies
Total capitalized internal costs	$ 1,000	$ 1,200	$ 2,400	$ 2,100
Proved oil and gas properties	738,780		738,780		$ 658,519
Unproved oil and gas properties	53,865		53,865		50,377
Furniture, fixtures, and other equipment	3,407		3,407		3,270
Less - Accumulated depreciation, depletion, and amortization	(242,997)		(242,997)		(216,769)
Property and Equipment, Net	553,055		$ 553,055		495,397
Discount rate for estimated future net revenues from proved properties			10.00%
Write-down of oil and gas properties	0	0	$ 0	0
Allowance for doubtful accounts receivable, current	100		100		100
Accounts receivable, gross	17,400		17,400		20,100
Accounts receivable related to joint interest owners	1,100		1,100		2,100
Severance tax receivable	800		800		2,100
Other receivables	2,800		$ 2,800		3,000
Percentage of working interest in wells			100.00%
Total amount of supervision fees charged to wells	1,100	1,100	$ 2,200	2,300
Income Tax Expense (Benefit)	328	0	328	0
Previous Federal Corporate Tax Rate						0.35
New Federal Corporate Tax Rate						0.21
Trade accounts payable	16,015		16,015		20,884
Accrued operating expenses	2,316		2,316		3,490
Accrued payroll costs	2,945		2,945		5,334
Asset retirement obligation - current portion	303		303		2,109
Accrued non-income based taxes	5,137		5,137		3,898
Accrued corporate and legal fees	3,120		3,120		2,784
Other payables	5,514		5,514		5,938
Accounts payable and accrued liabilities	35,350		35,350		44,437
Cash and cash equivalents	6,611	6,627	6,611	6,627	7,806
Restricted Cash	220	179	220	179	220
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 6,831	$ 6,806	$ 6,831	$ 6,806	$ 8,026		$ 497
Purchase of treasury stock (shares) | shares			15,107		28,279
Other Commitment					$ 6,200
Lessee, Operating Lease, Term of Contract					3 years
Office Lease [Member]
Summary of Significant Accounting Policies
Other Commitment					$ 2,000
Minimum [Member]
Summary of Significant Accounting Policies
Estimated useful lives of property			2 years
Maximum [Member]
Summary of Significant Accounting Policies
Estimated useful lives of property			20 years

Revenue Recognition Revenue R38

Revenue Recognition Revenue Recognition (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Oil and gas sales	$ 51,347	$ 45,782	$ 104,099	$ 88,194
Oil sales [Member]
Disaggregation of Revenue [Line Items]
Oil, natural gas and NGL sales	9,638	6,527	21,078	13,728
Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Oil, natural gas and NGL sales	36,369	35,043	72,136	66,106
NGL sales [Member]
Disaggregation of Revenue [Line Items]
Oil, natural gas and NGL sales	5,339	4,215	10,900	8,363
Other sales [Member]
Disaggregation of Revenue [Line Items]
Oil, natural gas and NGL sales	$ 0	$ (3)	$ (14)	$ (3)

Share-Based Compensation (Detai

Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands	Jun. 30, 2018	Feb. 20, 2018	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Share-based Compensation (Details Textual)
Stock-based compensation expenses					$ 2,675	$ 3,136
Share-based compensation (capitalized)			$ 100	$ 100	200	200
Employee Stock Option [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 3,900		3,900		3,900
Stock option award outstanding aggregate intrinsic value	$ 1,200		$ 1,200		1,200
Remaining contract life of outstanding stock options.	6 years 7 months
Remaining contract life of exercisable stock option	3 years 7 months
Stock option award exercisable aggregate intrinsic value					$ 500
Stock Option Activity
Options outstanding, beginning of period, shares	449,856		449,856		449,856		508,730
Options outstanding, beginning of period, weighted average price	$ 26.98		$ 26.98		$ 26.98		$ 26.82
Options granted, shares					0
Options granted, weighted average price					$ 0
Options forfeited, shares					(21,319)
Options forfeited, weighted average share price					$ 29.96
Options canceled, shares					(8,356)
Options canceled, weighted average price					$ 26.96
Options exercised, shares					(29,199)
Options exercised, weighted average price					$ 24.27
Options exercisable, end of period, shares	141,347		141,347		141,347
Options exercisable, end of period, weighted average price	$ 25.84		$ 25.84		$ 25.84
Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 7,300		$ 7,300		$ 7,300
Unrecognized compensation expense weighted-average period					2 years 7 months
Restricted stock activity
Restricted shares outstanding, beginning of period, shares					346,740
Restricted shares outstanding, beginning of period, weighted average price					$ 26.99
Restricted shares granted, shares					91,906
Restricted shares granted, weighted average price					$ 27.89
Restricted shares forfeited, shares					(21,011)
Restricted shares forfeited, weighted average price					$ 26.59
Restricted shares vested, shares					(81,754)
Restricted shares vested, weighted average price					$ 25.04
Restricted shares outstanding, end of period, shares	335,881		335,881		335,881
Restricted shares outstanding, end of period, weighted average price	$ 27.74		$ 27.74		$ 27.74
Performance-based stock unit [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 1,100		$ 1,100		$ 1,100
Unrecognized compensation expense weighted-average period	2 years 8 months
Restricted stock activity
Restricted shares granted, shares		30,700
Restricted shares granted, weighted average price		$ 41.66
Restricted shares vested, shares					0
Percent of payout for performance based stock units		150.61%
Minimum [Member] | Employee Stock Option [Member]
Share-based Compensation (Details Textual)
Stock option award vesting period					1 year
Minimum [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term					1 year
Minimum [Member] | Performance-based stock unit [Member]
Restricted stock activity
Percent of payout for performance based stock units		0.00%
Maximum [Member] | Employee Stock Option [Member]
Share-based Compensation (Details Textual)
Stock option award vesting period					5 years
Maximum [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term					5 years
Maximum [Member] | Performance-based stock unit [Member]
Share-based Compensation (Details Textual)
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term					3 years
Restricted stock activity
Percent of payout for performance based stock units		200.00%
General and Administrative Expense [Member]
Share-based Compensation (Details Textual)
Stock-based compensation expenses			$ 1,300	$ 1,600	$ 2,700	$ 3,100

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Basic EPS:
Net Income (Loss)	$ 2,319	$ 16,241	$ 10,787	$ 33,951	$ 71,971
Income, share amounts	11,655	11,487	11,629	11,360
Earnings Per Share, Basic	$ 0.20	$ 1.41	$ 0.93	$ 2.99
Dilutive Securities:
Dilutive RSAs	0	0	0	0
Dilutive RSUs	16	59	17	73
Dilutive Stock Options	86	8	96	12
Diluted EPS:
Net Income (Loss) Available to Common Stockholders, Diluted	$ 2,319	$ 16,241	$ 10,787	$ 33,951
Weighted Average Number of Shares Outstanding, Diluted	11,757	11,554	11,742	11,445
Earnings Per Share, Diluted	$ 0.20	$ 1.41	$ 0.92	$ 2.97
Warrant [Member]
Earnings Per Share (Textual)
Antidilutive shares excluded from EPS, shares	4,300	4,300	4,300	4,300
Stock Options [Member]
Earnings Per Share (Textual)
Antidilutive shares excluded from EPS, shares	400	400	400	400
Restricted Stock Units (RSUs) [Member]
Earnings Per Share (Textual)
Antidilutive shares excluded from EPS, shares	100	100	100	100
Performance Shares [Member]
Earnings Per Share (Textual)
Antidilutive shares excluded from EPS, shares	100		100

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands	Dec. 15, 2017USD ($)	Apr. 19, 2017USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Apr. 20, 2018USD ($)	Dec. 31, 2017USD ($)
Bank Borrowings
Long-term Debt, excluding current maturities			$ 274,577		$ 274,577			$ 265,325
Gross interest expense including amortization of debt issuance costs			6,585	$ 4,642	12,474	$ 8,249
Commitment fees included in interest expense, net			300	100	600	200
Capitalized interest on our unproved properties			300	200	700	400
Second Lien [Abstract]
Long-term debt, gross			282,000		282,000			273,000
New Credit Facility [Member]
Bank Borrowings
Debt Issuance Costs, Net			4,900		4,900			5,500
Second Lien Notes [Member]
Bank Borrowings
Debt Issuance Costs, Net			5,534		5,534			5,683
Long-term Debt, excluding current maturities	$ 198,000		200,000		200,000			200,000
Debt instrument escalating basis spread on base rate	50
Gross interest expense including amortization of debt issuance costs			5,200		10,000
Second Lien [Abstract]
Long-term debt, gross	$ 200,000
Debt Instrument, Unamortized Discount	(2,000)		(1,889)		(1,889)			(1,992)
Additional notes issuable	$ 100,000
Additional interest in the event of default	0.020
Make whole premium during years 1 and 2	0.02
Make whole premium during year 3	0.02
Make whole premium during year 4	0.01
Second Lien, Required Security Interest on Proved Reserves	85.00%
Second Lien, Required Security Interest on Oil and Gas Properties	85.00%
Second Lien, Asset Coverage Ratio, Minimum	1.3
Second Lien, Covenant, Debt to EBITDA Ratio, Minimum	4.5
Long-term debt, net			192,600		192,600
Second Lien Notes [Member] | Alternative Base Interest Rate [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate	0.065
Second Lien Notes [Member] | London Interbank Offered Rate (LIBOR) [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate	0.075
Line of Credit [Member] | New Credit Facility [Member]
Bank Borrowings
Long-term Debt, excluding current maturities			82,000		82,000			$ 73,000
Line of Credit Facility, Current Borrowing Capacity							$ 330,000
Decrease in applicable margin to calculate interest							50
Line of Credit Facility, Maximum Borrowing Capacity		$ 600,000
Line of Credit, Letters of Credit Issuable		$ 25,000
Commitment fee basis points for the credit facility		0.50%
Line of Credit, Additional Interest Due to Payment Default		2.00%
Line of Credit, Required Security Interest on Oil and Gas Properties		85.00%
Line of Credit, Covenant, Debt to EBITDA Ratio, Minimum		4
Line of Credit, Covenant, Current Ratio, Minimum		1
Gross interest expense including amortization of debt issuance costs			$ 1,600	$ 4,800	$ 3,100	$ 8,500
Line of Credit [Member] | New Credit Facility [Member] | Minimum [Member] | Alternative Base Interest Rate [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate		0.0125
Debt Instrument Escalating Rates for Eurodollar Rate Loans		0.0225
Line of Credit [Member] | New Credit Facility [Member] | Maximum [Member] | Alternative Base Interest Rate [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate		0.0225
Debt Instrument Escalating Rates for Eurodollar Rate Loans		0.0325

Acquisitions and Dispositions42

Acquisitions and Dispositions Acquisitions and Dispositions (Details) - USD ($) $ in Thousands	Jan. 24, 2018	Jun. 30, 2018	Jun. 30, 2017	Dec. 22, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments for (Proceeds from) Other Investing Activities		$ 6,042	$ 0
AWP Olmos Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 27,000
Buyer's Assumption of ARO	$ 6,300
Bay De Chene [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase and sale contract				$ 16,300
Long-term liability reclassified to current		2,500
Cash to be released for purchase and sale contract		10,200
Other Current Liabilities [Member] | Bay De Chene [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase and sale contract		7,700
Other Noncurrent Liabilities [Member] | Bay De Chene [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase and sale contract		$ 2,500

Price-Risk Management Price-R43

Price-Risk Management Price-Risk Management (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018USD ($)MMBTU$ / MMBTU$ / Boebbl	Jun. 30, 2017USD ($)	Jun. 30, 2018USD ($)MMBTU$ / MMBTU$ / Boebbl	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Price Risk Derivatives, Net | $	$ (10,800)	$ 5,100	$ (17,100)	$ 16,100
Cash Received (Paid) On Settlements of Derivative Contracts | $			(1,935)	$ (2,586)
Receivables for Settled Derivatives | $	100		100		$ 2,200
Payables for Settled Derivatives | $	1,600		1,600		400
Derivative, Fair Value, Net | $	(12,100)		(12,100)		(100)
Other Current Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	1,800		1,800		5,100
Other Noncurrent Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	3,300		3,300		2,600
Other Current Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	11,700		11,700		5,100
Other Noncurrent Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	$ 5,400		$ 5,400		$ 2,800
Swap [Member] | Oil Derivative Swaps [Member] | Third Quarter 2018 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	130,400		130,400
Derivative, Swap Type, Fixed Price | $ / Boe	52.40		52.40
Swap [Member] | Oil Derivative Swaps [Member] | Fourth Quarter 2018 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	122,800		122,800
Derivative, Swap Type, Fixed Price | $ / Boe	52.23		52.23
Swap [Member] | Oil Derivative Swaps [Member] | First Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	107,700		107,700
Derivative, Swap Type, Fixed Price | $ / Boe	52.77		52.77
Swap [Member] | Oil Derivative Swaps [Member] | Second Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	103,200		103,200
Derivative, Swap Type, Fixed Price | $ / Boe	52.72		52.72
Swap [Member] | Oil Derivative Swaps [Member] | Third Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	99,000		99,000
Derivative, Swap Type, Fixed Price | $ / Boe	52.79		52.79
Swap [Member] | Oil Derivative Swaps [Member] | Fourth Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	95,000		95,000
Derivative, Swap Type, Fixed Price | $ / Boe	52.73		52.73
Swap [Member] | Oil Derivative Swaps [Member] | First Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	81,300		81,300
Derivative, Swap Type, Fixed Price | $ / Boe	52.42		52.42
Swap [Member] | Oil Derivative Swaps [Member] | Second Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	77,850		77,850
Derivative, Swap Type, Fixed Price | $ / Boe	52.38		52.38
Swap [Member] | Oil Derivative Swaps [Member] | Third Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	74,700		74,700
Derivative, Swap Type, Fixed Price | $ / Boe	52.34		52.34
Swap [Member] | Oil Derivative Swaps [Member] | Fourth Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	72,000		72,000
Derivative, Swap Type, Fixed Price | $ / Boe	52.29		52.29
Swap [Member] | Natural Gas Derivative Swaps [Member] | Third Quarter 2018 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Swap Type, Fixed Price	2.88		2.88
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	7,666,000		7,666,000
Swap [Member] | Natural Gas Derivative Swaps [Member] | Fourth Quarter 2018 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Swap Type, Fixed Price	2.96		2.96
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	12,121,000		12,121,000
Swap [Member] | Natural Gas Derivative Swaps [Member] | First Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Swap Type, Fixed Price	3.08		3.08
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	7,516,000		7,516,000
Swap [Member] | Natural Gas Derivative Swaps [Member] | Second Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Swap Type, Fixed Price	2.83		2.83
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	6,060,000		6,060,000
Swap [Member] | Natural Gas Derivative Swaps [Member] | Third Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Swap Type, Fixed Price	2.84		2.84
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	5,550,000		5,550,000
Swap [Member] | Natural Gas Derivative Swaps [Member] | Fourth Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Swap Type, Fixed Price	2.84		2.84
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	5,966,000		5,966,000
Swap [Member] | Natural Gas Derivative Swaps [Member] | First Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Swap Type, Fixed Price	2.83		2.83
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	5,370,000		5,370,000
Swap [Member] | Natural Gas Derivative Swaps [Member] | Second Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Swap Type, Fixed Price	2.76		2.76
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	3,688,000		3,688,000
Swap [Member] | Natural Gas Derivative Swaps [Member] | Third Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Swap Type, Fixed Price	2.76		2.76
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	3,585,000		3,585,000
Swap [Member] | Natural Gas Derivative Swaps [Member] | Fourth Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Swap Type, Fixed Price	2.77		2.77
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	3,362,000		3,362,000
Swap [Member] | Natural Gas Liquid Derivative [Member] | Third Quarter 2018 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Swap Type, Fixed Price	24.78		24.78
Future NGL Production Hedged in Bbls (Energy Item Type) | bbl	112,200		112,200
Swap [Member] | Natural Gas Liquid Derivative [Member] | Fourth Quarter 2018 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Swap Type, Fixed Price	24.78		24.78
Future NGL Production Hedged in Bbls (Energy Item Type) | bbl	148,200		148,200
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2018 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	7,595,000		7,595,000
Derivative, Basis Swap Type, Fixed Price	(0.01)		(0.01)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2018 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	11,850,000		11,850,000
Derivative, Basis Swap Type, Fixed Price	(0.07)		(0.07)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | First Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	11,310,000		11,310,000
Derivative, Basis Swap Type, Fixed Price	(0.08)		(0.08)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	11,975,000		11,975,000
Derivative, Basis Swap Type, Fixed Price	0.04		0.04
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	12,095,000		12,095,000
Derivative, Basis Swap Type, Fixed Price	0.03		0.03
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	12,095,000		12,095,000
Derivative, Basis Swap Type, Fixed Price	(0.04)		(0.04)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | First Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	1,820,000		1,820,000
Derivative, Basis Swap Type, Fixed Price	(0.10)		(0.10)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	1,820,000		1,820,000
Derivative, Basis Swap Type, Fixed Price	(0.09)		(0.09)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	1,840,000		1,840,000
Derivative, Basis Swap Type, Fixed Price	(0.07)		(0.07)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	1,840,000		1,840,000
Derivative, Basis Swap Type, Fixed Price	(0.11)		(0.11)
Basis Swap [Member] | Oil Basis Derivative [Member] | Third Quarter 2018 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	80,000		80,000
Derivative, Basis Swap Type, Fixed Price	4.13		4.13
Basis Swap [Member] | Oil Basis Derivative [Member] | Fourth Quarter 2018 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	120,000		120,000
Derivative, Basis Swap Type, Fixed Price	4.13		4.13

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 4.5	$ 7.2
Derivative Liability	1.7	1.3
Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0.6	0.3
Derivative Liability	2	0.3
Natural Gas Liquid Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0.1
Derivative Liability	1.3	0.9
Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	12	5.2
Oil Basis Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	0.2	0.1
Fair Value, Inputs, Level 1 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas Liquid Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Oil Basis Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	0	0
Fair Value, Inputs, Level 2 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	4.5	7.2
Derivative Liability	1.7	1.3
Fair Value, Inputs, Level 2 [Member] | Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0.6	0.3
Derivative Liability	2	0.3
Fair Value, Inputs, Level 2 [Member] | Natural Gas Liquid Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0.1
Derivative Liability	1.3	0.9
Fair Value, Inputs, Level 2 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	12	5.2
Fair Value, Inputs, Level 2 [Member] | Oil Basis Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	0.2	0.1
Fair Value, Inputs, Level 3 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas Liquid Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Oil Basis Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	$ 0	$ 0

Asset Retirement Obligations 45

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	$ 4,561		$ 4,561		$ 10,787	$ 32,256
Accretion expense	84	$ 576	243	$ 1,140	2,322
Liabilities incurred for new wells and facilities construction			26		253
Reductions due to sold wells and facilities			(6,265)		(21,466)
Reductions due to plugged wells and facilities			(145)		(2,366)
Revisions in estimates			(85)		(212)
Asset retirement obligation - current portion	$ 303		$ 303		$ 2,109