SilverBow Resources (SBOW) 10-Q 9 May 19 2019 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	May 01, 2019
Document and Entity Information [Abstract]
Entity Registrant Name	SILVERBOW RESOURCES, INC.
Entity Central Index Key	0000351817
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Document Period End Date	Mar. 31, 2019
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Entity Filer Category	Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Common Stock, Shares Outstanding		11,743,159

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Current Assets:
Cash and cash equivalents	$ 876	$ 2,465
Accounts receivable, net	31,342	46,472
Fair value of commodity derivatives	8,346	15,261
Other current assets	3,110	2,126
Total Current Assets	43,674	66,324
Property and Equipment:
Property and Equipment, full cost method	1,074,453	986,100
Less - Accumulated depreciation, depletion, and amortization	(306,609)	(284,804)
Net Furniture, Fixtures and other equipment	767,844	701,296
Right of Use Assets	2,024	0
Fair value of long-term commodity derivatives	4,024	4,333
Other Long-Term Assets	5,231	5,567
Total Assets	822,797	777,520
Current Liabilities:
Accounts payable and accrued liabilities	31,978	48,921
Fair value of commodity derivatives	4,570	2,824
Accrued capital costs	46,992	38,073
Accrued interest	1,413	1,513
Current lease liability	860	0
Undistributed oil and gas revenues	11,719	14,681
Total Current Liabilities	97,532	106,012
Long-Term Debt	424,207	387,988
Non-current Lease Liability	1,171	0
Deferred Tax Liabilities	1,148	1,014
Asset Retirement Obligation	4,073	3,956
Fair value of long-term commodity derivatives	2,197	3,723
Stockholders' Equity:
Preferred Stock, Value, Outstanding	0	0
Common stock, $0.01 par value	118	118
Additional paid-in capital	288,130	286,281
Treasury stock held, at cost	(2,130)	(1,870)
Retained earnings (Accumulated deficit)	6,351	(9,702)
Total Stockholders' Equity (Deficit)	292,469	274,827
Total Liabilities and Stockholders' Equity	$ 822,797	$ 777,520

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Capitalized Costs, unproved property balance	$ 64,797	$ 56,715
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	11,819,235	11,757,972
Common stock, shares outstanding	11,742,288	11,692,101
Treasury stock shares held, at cost	76,947	65,871

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Income Statement [Abstract]
Oil and gas sales	$ 72,064	$ 52,752
Costs and Expenses [Abstract]
General and administrative, net	6,276	5,576
Depreciation, depletion, and amortization	21,805	13,131
Accretion of asset retirement obligation	83	159
Lease operating costs	4,531	4,961
Workovers	646	0
Transportation and gas processing	6,406	5,025
Severance and other taxes	3,316	3,031
Operating Expenses	43,063	31,883
Operating Income (Loss)	29,001	20,869
Net gain (loss) on commodity derivatives	(4,022)	(6,355)
Interest expense, net	(8,759)	(5,890)
Other Nonoperating Income (Expense)	65	(158)
Income (Loss) Before Income Taxes	16,285	8,466
Provision (Benefit) for Income Taxes	232	0
Net Income (Loss)	$ 16,053	$ 8,466
Per Share Amounts-
Earnings Per Share, Basic	$ 1.37	$ 0.73
Earnings Per Share, Diluted	$ 1.36	$ 0.72
Weighted Average Shares Outstanding - Basic	11,708	11,602
Weighted Average Shares Outstanding - Diluted	11,788	11,727

Condensed Consolidated Statem_2

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, 2017	$ 193,458	$ 116	$ 279,111	$ (1,452)	$ (84,317)
Shares issued from option exercise	708	0	708	0	0
Purchase of treasury shares	(290)	0	0	(290)	0
Issuance of restricted stock	0	1	(1)	0	0
Amortization of share-based compensation	1,485	0	1,485	0	0
Net Income (Loss)	8,466	0	0	0	8,466
Ending Balance at Mar. 31, 2018	203,827	117	281,303	(1,742)	(75,851)
Beginning Balance at Dec. 31, 2018	274,827	118	286,281	(1,870)	(9,702)
Purchase of treasury shares	(260)	0	0	(260)	0
Issuance of restricted stock	0	0	0	0	0
Amortization of share-based compensation	1,849	0	1,849	0	0
Net Income (Loss)	16,053	0	0	0	16,053
Ending Balance at Mar. 31, 2019	$ 292,469	$ 118	$ 288,130	$ (2,130)	$ 6,351

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) - shares	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Statement of Stockholders' Equity [Abstract]
Options exercised	0	29,199
Purchase of treasury stock (shares)	11,076	10,458
Issuance of restricted stock (shares)	61,263	63,275

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017
Cash Flows from Operating Activities:
Net Income (Loss)	$ 16,053	$ 8,466
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion, and amortization	21,805	13,131
Accretion of asset retirement obligation	83	159	$ 419
Deferred income taxes	134	0
Stock-based compensation expenses	1,692	1,359
Loss (gain) on derivatives	4,022	6,355
Cash settlements on derivatives	1,077	977
Settlements of asset retirement obligations	(31)	(120)
Other Noncash Income (Expense)	564	129
(Increase) decrease in accounts receivable and other current assets	14,401	4,005
Increase (decrease) in accounts payable and accrued liabilities	(9,105)	(9,497)
Increase (decrease) in accrued interest	(100)	192
Net Cash Provided by (Used in) Operating Activities	50,595	25,156
Cash Flows from Investing Activities:
Additions to property and equipment	(86,555)	(33,753)
Proceeds from the sale of property and equipment	(91)	26,969
Payments on property sale obligations	(1,278)	(6,042)
Net Cash Provided by (Used in) Investing Activities	(87,924)	(12,826)
Cash Flows from Financing Activities:
Proceeds from bank borrowings	132,000	35,100
Payments of bank borrowings	(96,000)	(55,100)
Net proceeds from issuances of common stock	0	708
Purchase of treasury shares	(260)	(290)
Payments of debt issuance costs	0	(317)
Net Cash Provided by (Used in) Financing Activities	35,740	(19,899)
Net increase (decrease) in Cash, Cash Equivalents and Restricted Cash	(1,589)	(7,569)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	876	457	$ 2,465	$ 8,026
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized	8,303	5,170
Changes in capital accounts payable and capital accruals	1,487	12,177
Increase (decrease) in other long-term liabilities for capital expenditures	$ 0	$ (1,250)

General Information

General Information	3 Months Ended
	Mar. 31, 2019
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, 2018 as filed with the Securities and Exchange Commission on February 28, 2019.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2019
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. On April 12, 2019, as part of our regularly scheduled borrowing base redetermination, we reaffirmed the borrowing base of our Credit Facility at $410 million . See Note 6 of these condensed consolidated financial statements for further details on our Credit Facility. There were no other 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, • estimates in amounts due with respect to open state regulatory audits, and • estimates on future lease obligations. 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 March 31, 2019 and 2018 , such internal costs capitalized totaled $1.6 million and $1.4 million , respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these notes to 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): March 31, 2019 December 31, 2018 Property and Equipment Proved oil and gas properties $ 1,005,988 $ 925,865 Unproved oil and gas properties 64,797 56,715 Furniture, fixtures and other equipment 3,668 3,520 Less – Accumulated depreciation, depletion, amortization & impairment (306,609 ) (284,804 ) Property and Equipment, Net $ 767,844 $ 701,296 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 March 31, 2019 and 2018 . 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. 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 March 31, 2019 and December 31, 2018 , 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 March 31, 2019 , our “Accounts receivable” balance included $21.4 million for oil and gas sales, $4.5 million due from joint interest owners, $3.5 million for severance tax credit receivables and $1.9 million for other receivables. At December 31, 2018 , our “Accounts receivable” balance included $36.9 million for oil and gas sales, $5.6 million due from joint interest owners, $2.4 million for severance tax credit receivables and $1.6 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 three months ended March 31, 2019 and 2018 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $1.3 million and $1.1 million for the three months ended March 31, 2019 and 2018 , 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 March 31, 2019 , 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 March 31, 2019 and December 31, 2018 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 $0.2 million for state income tax expense during the three months ended March 31, 2019 . We did no t recognize any state income tax expense during the three months ended March 31, 2018 . Revenue Recognition . 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. To comply with the new standard, natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers. The following table provides information regarding our oil and gas sales, by product, reported on the Statements of Operations for the three months ended March 31, 2019 and 2018 (in thousands): Three Months Ended March 31, 2019 Three Months Ended March 31, 2018 Oil, natural gas and NGLs sales: Oil $ 14,607 $ 11,439 Natural gas 51,304 35,753 NGLs 6,154 5,560 Total $ 72,064 $ 52,752 Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): March 31, 2019 December 31, 2018 Trade accounts payable $ 20,728 $ 32,683 Accrued operating expenses 3,258 3,549 Accrued compensation costs 2,066 4,785 Asset retirement obligations – current portion 284 302 Accrued non-income based taxes 2,533 3,583 Accrued corporate and legal fees 335 534 Other payables 2,774 3,485 Total accounts payable and accrued liabilities $ 31,978 $ 48,921 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. 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 three months ended March 31, 2019 , we purchased 11,076 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. New Accounting Pronouncements. In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“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 was effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted this standard on January 1, 2019, using the modified retrospective transition approach. The Company has elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements upon adoption. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheet and additionally we have elected to not account for lease and non-lease components separately. As a result of adoption, the Company's 2019 opening balances for right-of-use assets and lease liabilities was $2.2 million , attributable to operating leases. The balance could increase during the year if the Company enters into new lease agreements. Adoption of this guidance did not result in a cumulative adjustment to retained earnings. See Note 3 for more information.

Leases Leases (Notes)

Leases Leases (Notes)	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Lessee, Operating Leases [Text Block]	(3) Leases SilverBow Resources has contractual agreements for its corporate office lease, vehicle fleet, drilling rigs, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a Right of Use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of March 31, 2019 all of the Company’s leases were operating leases. The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the Condensed Consolidated Balance Sheet. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term. Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows (in thousands): March 31, 2019 Lease Costs included in the Condensed Consolidated Balance Sheets Property, plant and equipment acquisitions - short-term leases $ 3,983 Property, plant and equipment acquisitions - operating leases 8 Total lease costs in property, plant and equipment additions $ 3,991 Three Months Ended March 31, 2019 Lease Costs included in the Condensed Consolidated Statement of Operations Lease operating costs - short-term leases $ 1,335 Lease operating costs - operating leases 54 General and administrative, net - operating leases 156 Total lease cost expensed $ 1,545 Lease term and the discount rate related to the Company's leases are as follows: Three Months Ended March 31, 2019 Weighted-average remaining lease term (in years) 4.2 Weighted-average discount rate 5.1 % As of March 31, 2019 , the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): March 31, 2019 2019 (remaining after March 31, 2019) $ 648 2020 841 2021 358 2022 36 2023 38 Thereafter 363 Total undiscounted lease payments $ 2,284 Present value adjustment (253 ) Net operating lease liabilities $ 2,031 Supplement cash flow information related to leases was as follows (in thousands): Three Months Ended March 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 203 Investing cash flows from operating leases $ 8

Share-Based Compensation

Share-Based Compensation	3 Months Ended
	Mar. 31, 2019
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation	(4) Share-Based Compensation Share-Based Compensation Plans In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016. Under the Plans, 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 $1.7 million and $1.4 million for the three months ended March 31, 2019 and 2018 , respectively. Capitalized share-based compensation was $0.2 million and $0.1 million for each of the three months ended March 31, 2019 and 2018 , respectively. 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 option pricing model to estimate the fair value of stock option awards. At March 31, 2019 , we had $5.6 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the three months ended March 31, 2019 : Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 644,575 $ 28.28 Options granted — $ — Options forfeited (4,197 ) $ 26.96 Options expired — $ — Options exercised — $ — Options outstanding, end of period 640,378 $ 28.29 Options exercisable, end of period 195,178 $ 28.87 O ur outstanding stock option awards at March 31, 2019 had $0.1 million of aggregate intrinsic value. At March 31, 2019 , the weighted average remaining contract life of stock option awards outstanding was 6.9 years and exercisable was 3.5 years. The total intrinsic value of stock option awards exercisable had no value for the three months ended March 31, 2019 . Restricted Stock Units The 2016 Plan and Inducement Plan allow 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 March 31, 2019 , we had unrecognized compensation expense of $6.4 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 2.4 years. The following table provides information regarding restricted stock unit award activity for the three months ended March 31, 2019 : Shares Grant Date Price Restricted stock units outstanding, beginning of period 340,678 $ 27.64 Restricted stock units granted 62,650 $ 22.34 Restricted stock units forfeited (8,044 ) $ 27.47 Restricted stock units vested (61,263 ) $ 27.07 Restricted stock units outstanding, end of period 334,021 $ 26.76 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 grant date was $41.66 per unit or 150.6% of stock price. The remaining performance period as of March 31, 2019 is 1.9 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 March 31, 2019 , we had unrecognized compensation expense of $0.8 million related to our performance-based stock units based on the assumption of 100% target payout. No shares vested during the three months ended March 31, 2019 .

Earnings Per Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2019
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 March 31, 2019 and 2018 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 March 31, 2019 Three Months Ended March 31, 2018 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 16,053 11,708 $ 1.37 $ 8,466 11,602 $ 0.73 Dilutive Securities: Restricted Stock Awards — — Restricted Stock Unit Awards 80 18 Stock Option Awards — 107 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 16,053 11,788 $ 1.36 $ 8,466 11,727 $ 0.72 Approximately 0.6 million and 0.4 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended March 31, 2019 and 2018 , respectively, 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 March 31, 2019 and 2018 , respectively, because they were antidilutive. Less than 0.1 million shares of performance-based restricted stock units were not included in the computation of Diluted EPS for the three months ended March 31, 2019 and 2018 because they were antidilutive. Approximately 4.3 million warrants to purchase common stock were not included in the computation of Diluted EPS for both the three months ended March 31, 2019 and 2018 because these warrants were antidilutive.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2019
Debt Disclosure [Abstract]
Long-Term Debt	(6) Long-Term Debt The Company's long-term debt consisted of the following (in thousands): March 31, 2019 December 31, 2018 Credit Facility Borrowings (1) $ 231,000 $ 195,000 Second Lien Notes due 2024 200,000 200,000 431,000 395,000 Unamortized discount on Second Lien Notes due 2024 (1,726 ) (1,782 ) Unamortized debt issuance cost on Second Lien Notes due 2024 (5,067 ) (5,230 ) Long-Term Debt, net $ 424,207 $ 387,988 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of March 31, 2019 and December 31, 2018 , we had $4.1 million and $4.5 million , respectively, in unamortized debt issuance costs on our Credit Facility borrowings. Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $231.0 million and $195.0 million as of March 31, 2019 and December 31, 2018 , 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 Fourth Amendment effective November 6, 2018 (the “Fourth Amendment to Credit Agreement”) to the First Amended and Restated Senior Secured Credit Agreement (as so amended, the “Credit Agreement” and such facility, the “Credit Facility”). The Fourth Amendment to Credit Agreement increased the borrowing base from $330 million to $410 million and decreased the applicable margins used to calculate the interest rate under the Credit Agreement by 25 basis points. The Credit Facility matures April 19, 2022, and provides for a maximum credit amount of $600 million and a current borrowing base of $410 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”). Since November 6, 2018, the applicable margin ranged from 1.00% to 2.00% for ABR Loans and 2.00% to 3.00% 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 March 31, 2019 , 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 replace 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 $3.5 million and $1.5 million for the three months ended March 31, 2019 and 2018 , respectively. We capitalized interest on our unproved properties in the amount of $0.1 million and $0.4 million for the three months ended March 31, 2019 and 2018 , respectively. Senior Secured Second Lien Notes . On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement”, and such second lien facility 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. 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 Note 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 March 31, 2019 , 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 to be immediately due and payable. As of March 31, 2019 , total net amounts recorded for the Second Lien were $193.2 million , net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $5.3 million and $4.7 million for the three months ended March 31, 2019 and 2018 , respectively. 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	3 Months Ended
	Mar. 31, 2019
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 , with 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. Of the $16.3 million original obligation, $1.3 million was paid during the three months ended March 31, 2019 . The remaining obligation under this contract is $6.2 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of March 31, 2019 . There were no material acquisitions or dispositions of developed properties during the three months ended March 31, 2019 .

Price-Risk Management Price-Ris

Price-Risk Management Price-Risk Management (Notes)	3 Months Ended
	Mar. 31, 2019
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, primarily through the purchase of commodity price swaps and collars as well as basis swaps. During the three months ended March 31, 2019 and 2018 , the Company recorded losses of $4.0 million and $6.4 million , respectively, on its commodity derivatives. The Company collected cash payments of $1.1 million and $1.0 million for settled derivative contracts during the three months ended March 31, 2019 and 2018 , respectively. At March 31, 2019 , there were $1.0 million receivables for settled derivatives while at December 31, 2018 we had $0.7 million in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in April 2019 and January 2019, respectively. At March 31, 2019 and December 31, 2018 , we also had $0.2 million and $2.2 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 April 2019 and January 2019, respectively. The fair values of our swap contracts are computed using observable market data while our collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. At March 31, 2019 , there was $8.3 million and $4.0 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $4.6 million and $2.2 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2018 , there was $15.3 million and $4.3 million in current and long-term unsettled derivative assets, respectively, and $2.8 million and $3.7 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 $5.6 million net fair value asset at March 31, 2019 and a $13.0 million net fair value asset at December 31, 2018 . For further discussion, related to the fair value of the Company's derivatives, refer to Note 9 of these notes to condensed consolidated financial statements. The following tables summarize the weighted average prices as well as future production volumes for our future derivative contracts in place as of March 31, 2019 : Oil Derivative Swaps (NYMEX WTI Settlements) Total Volumes (Bbls) Weighted Average Price 2019 Contracts 2Q19 157,450 $ 57.30 3Q19 176,500 $ 57.98 4Q19 172,500 $ 58.07 2020 Contracts 1Q20 149,300 $ 57.32 2Q20 100,350 $ 56.38 3Q20 97,200 $ 56.49 4Q20 72,000 $ 52.29 2021 Contracts 1Q21 56,175 $ 55.23 Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) Total Volumes Weighted Average Price Weighted Average Collar Floor Weighted Average Collar Call Price 2019 Contracts 2Q19 12,130,000 $ 2.80 3Q19 12,680,000 $ 2.81 4Q19 11,486,000 $ 2.89 2020 Contracts 1Q20 6,280,000 $ 2.87 2Q20 3,688,000 $ 2.76 3Q20 3,585,000 $ 2.76 4Q20 3,362,000 $ 2.77 Collar Contracts 2019 Contracts 2Q19 300,000 $ 2.90 $ 3.15 2021 Contracts 1Q21 4,354,800 $ 2.50 $ 3.52 NGL Contracts Total Volumes (Bbls) Weighted Average Price 2019 Contracts 2Q19 180,000 $ 27.93 3Q19 180,000 $ 27.93 4Q19 180,000 $ 27.93 Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs NYMEX Settlements) Total Volumes Weighted Average Price 2019 Contracts 2Q19 14,477,500 $ 0.05 3Q19 14,625,000 $ 0.04 4Q19 14,625,000 $ (0.02 ) 2020 Contracts 1Q20 11,739,000 $ (0.03 ) 2Q20 11,739,000 $ (0.04 ) 3Q20 11,868,000 $ (0.03 ) 4Q20 11,868,000 $ (0.04 ) 2021 Contracts 1Q21 7,200,000 $ (0.003 ) 2Q21 7,280,000 $ (0.003 ) 3Q21 7,360,000 $ (0.003 ) 4Q21 7,360,000 $ (0.003 ) Oil Basis Contracts (Argus Cushing (WTI) and LLS Settlements) Total Volumes (Bbls) Weighted Average Price 2019 Contracts 2Q19 45,000 $ 4.65 3Q19 45,000 $ 4.65 4Q19 45,000 $ 4.65

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2019
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, Credit Facility and Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable 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 March 31, 2019 and December 31, 2018 , 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 notes to condensed consolidated financial statements. Fair Value Measurements at (in millions) Total Quoted Prices in Significant Other Significant March 31, 2019 Assets Natural Gas Derivatives $ 3.2 $ — $ 3.2 $ — Natural Gas Basis Derivatives $ 4.3 $ — $ 4.3 $ — Oil Derivatives $ 1.8 $ — $ 1.8 $ — NGL Derivatives $ 3.1 $ — $ 3.1 $ — Liabilities Natural Gas Derivatives $ 1.8 $ — $ 1.8 $ — Natural Gas Basis Derivatives $ 0.8 $ — $ 0.8 $ — Oil Derivatives $ 4.1 $ — $ 4.1 $ — Oil Basis Derivatives $ 0.1 $ — $ 0.1 $ — December 31, 2018 Assets Natural Gas Derivatives $ 7.5 $ — $ 7.5 $ — Natural Gas Basis Derivatives $ 0.4 $ — $ 0.4 $ — Oil Derivatives $ 6.9 $ — $ 6.9 $ — NGL Derivatives $ 4.7 $ — $ 4.7 $ — Liabilities Natural Gas Derivatives $ 1.0 $ — $ 1.0 $ — Natural Gas Basis Derivatives $ 5.3 $ — $ 5.3 $ — NGL Derivatives $ 0.2 $ — $ 0.2 $ — 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)	3 Months Ended
	Mar. 31, 2019
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, 2018 and the three months ended March 31, 2019 (in thousands): Asset Retirement Obligations as of December 31, 2017 $ 10,787 Accretion expense 419 Liabilities incurred for new wells and facilities construction 93 Reductions due to sold wells and facilities (6,298 ) Reductions due to plugged wells and facilities (180 ) Revisions in estimates (562 ) Asset Retirement Obligations as of December 31, 2018 $ 4,259 Accretion expense 83 Liabilities incurred for new wells and facilities construction 39 Reductions due to sold wells and facilities — Reductions due to plugged wells and facilities (30 ) Revisions in estimates 6 Asset Retirement Obligations as of March 31, 2019 $ 4,357 At both March 31, 2019 and December 31, 2018 , approximately $0.3 million of our asset retirement obligations were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets. The 2018 reductions due to sold wells and facilities are primarily attributable to the disposition of our assets from our AWP Olmos field.

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies	3 Months Ended
	Mar. 31, 2019
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. There have been no material changes to the Company's contractual obligations described in our Form 10-K. Future minimum rental commitments under non-cancelable leases in effect at December 31, 2018 are as follows (in thousands): December 31, 2018 2019 $ 4,470 2020 838 2021 332 Thereafter — Total undiscounted lease payments $ 5,640 The table above was prepared under the guidance of Topic 840. As discussed in Note 3 above, the Company adopted the guidance of Topic 842 effective January 1, 2019.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2019
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, • estimates in amounts due with respect to open state regulatory audits, and • estimates on future lease obligations. 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 March 31, 2019 and 2018 , such internal costs capitalized totaled $1.6 million and $1.4 million , respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these notes to 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): March 31, 2019 December 31, 2018 Property and Equipment Proved oil and gas properties $ 1,005,988 $ 925,865 Unproved oil and gas properties 64,797 56,715 Furniture, fixtures and other equipment 3,668 3,520 Less – Accumulated depreciation, depletion, amortization & impairment (306,609 ) (284,804 ) Property and Equipment, Net $ 767,844 $ 701,296 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 March 31, 2019 and December 31, 2018 , 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 March 31, 2019 , 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 March 31, 2019 and December 31, 2018 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 $0.2 million for state income tax expense during the three months ended March 31, 2019 . We did no t recognize any state income tax expense during the three months ended March 31, 2018 .
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition . 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. To comply with the new standard, natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers.
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): March 31, 2019 December 31, 2018 Trade accounts payable $ 20,728 $ 32,683 Accrued operating expenses 3,258 3,549 Accrued compensation costs 2,066 4,785 Asset retirement obligations – current portion 284 302 Accrued non-income based taxes 2,533 3,583 Accrued corporate and legal fees 335 534 Other payables 2,774 3,485 Total accounts payable and accrued liabilities $ 31,978 $ 48,921
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]	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.
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 Update (“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 was effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted this standard on January 1, 2019, using the modified retrospective transition approach. The Company has elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements upon adoption. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheet and additionally we have elected to not account for lease and non-lease components separately. As a result of adoption, the Company's 2019 opening balances for right-of-use assets and lease liabilities was $2.2 million , attributable to operating leases. The balance could increase during the year if the Company enters into new lease agreements. Adoption of this guidance did not result in a cumulative adjustment to retained earnings. See Note 3 for more information.

Leases Leases (Policies)

Leases Leases (Policies)	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Lessee, Leases [Policy Text Block]	Leases SilverBow Resources has contractual agreements for its corporate office lease, vehicle fleet, drilling rigs, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a Right of Use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of March 31, 2019 all of the Company’s leases were operating leases. The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the Condensed Consolidated Balance Sheet. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term.

Share-Based Compensation Share-

Share-Based Compensation Share-Based Compensation (Policies)	3 Months Ended
	Mar. 31, 2019
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-based Compensation, Option and Incentive Plans Policy	Share-Based Compensation Share-Based Compensation Plans In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016. Under the Plans, 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)	3 Months Ended
	Mar. 31, 2019
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 March 31, 2019 and 2018 are discussed below.

Long-Term Debt Long-Term Debt (

Long-Term Debt Long-Term Debt (Policies)	3 Months Ended
	Mar. 31, 2019
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-R_2

Price-Risk Management Price-Risk Management (Policies)	3 Months Ended
	Mar. 31, 2019
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, primarily 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)	3 Months Ended
	Mar. 31, 2019
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, Credit Facility and Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable 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 _2

Asset Retirement Obligations Asset Retirement Obligations (Policies)	3 Months Ended
	Mar. 31, 2019
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 Contingencies_2

Commitments and Contingencies Commitments and Contingencies (Policies)	3 Months Ended
	Mar. 31, 2019
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. There have been no material changes to the Company's contractual obligations described in our Form 10-K.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2019
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): March 31, 2019 December 31, 2018 Property and Equipment Proved oil and gas properties $ 1,005,988 $ 925,865 Unproved oil and gas properties 64,797 56,715 Furniture, fixtures and other equipment 3,668 3,520 Less – Accumulated depreciation, depletion, amortization & impairment (306,609 ) (284,804 ) Property and Equipment, Net $ 767,844 $ 701,296
Disaggregation of Revenue [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 March 31, 2019 and 2018 (in thousands): Three Months Ended March 31, 2019 Three Months Ended March 31, 2018 Oil, natural gas and NGLs sales: Oil $ 14,607 $ 11,439 Natural gas 51,304 35,753 NGLs 6,154 5,560 Total $ 72,064 $ 52,752
Accounts Payable and Accrued Liabilities	The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): March 31, 2019 December 31, 2018 Trade accounts payable $ 20,728 $ 32,683 Accrued operating expenses 3,258 3,549 Accrued compensation costs 2,066 4,785 Asset retirement obligations – current portion 284 302 Accrued non-income based taxes 2,533 3,583 Accrued corporate and legal fees 335 534 Other payables 2,774 3,485 Total accounts payable and accrued liabilities $ 31,978 $ 48,921

Leases Leases (Tables)

Leases Leases (Tables)	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Lease, Cost [Table Text Block]	Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows (in thousands): March 31, 2019 Lease Costs included in the Condensed Consolidated Balance Sheets Property, plant and equipment acquisitions - short-term leases $ 3,983 Property, plant and equipment acquisitions - operating leases 8 Total lease costs in property, plant and equipment additions $ 3,991 Three Months Ended March 31, 2019 Lease Costs included in the Condensed Consolidated Statement of Operations Lease operating costs - short-term leases $ 1,335 Lease operating costs - operating leases 54 General and administrative, net - operating leases 156 Total lease cost expensed $ 1,545
Lessee, Operating Lease, Disclosure [Table Text Block]	Lease term and the discount rate related to the Company's leases are as follows: Three Months Ended March 31, 2019 Weighted-average remaining lease term (in years) 4.2 Weighted-average discount rate 5.1 %
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	As of March 31, 2019 , the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): March 31, 2019 2019 (remaining after March 31, 2019) $ 648 2020 841 2021 358 2022 36 2023 38 Thereafter 363 Total undiscounted lease payments $ 2,284 Present value adjustment (253 ) Net operating lease liabilities $ 2,031
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	Supplement cash flow information related to leases was as follows (in thousands): Three Months Ended March 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 203 Investing cash flows from operating leases $ 8

Share-Based Compensation (Table

Share-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2019
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock option activity	The following table provides information regarding stock option award activity for the three months ended March 31, 2019 : Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 644,575 $ 28.28 Options granted — $ — Options forfeited (4,197 ) $ 26.96 Options expired — $ — Options exercised — $ — Options outstanding, end of period 640,378 $ 28.29 Options exercisable, end of period 195,178 $ 28.87
Restricted stock activity	The following table provides information regarding restricted stock unit award activity for the three months ended March 31, 2019 : Shares Grant Date Price Restricted stock units outstanding, beginning of period 340,678 $ 27.64 Restricted stock units granted 62,650 $ 22.34 Restricted stock units forfeited (8,044 ) $ 27.47 Restricted stock units vested (61,263 ) $ 27.07 Restricted stock units outstanding, end of period 334,021 $ 26.76

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2019
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 March 31, 2019 Three Months Ended March 31, 2018 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 16,053 11,708 $ 1.37 $ 8,466 11,602 $ 0.73 Dilutive Securities: Restricted Stock Awards — — Restricted Stock Unit Awards 80 18 Stock Option Awards — 107 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 16,053 11,788 $ 1.36 $ 8,466 11,727 $ 0.72

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2019
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	The Company's long-term debt consisted of the following (in thousands): March 31, 2019 December 31, 2018 Credit Facility Borrowings (1) $ 231,000 $ 195,000 Second Lien Notes due 2024 200,000 200,000 431,000 395,000 Unamortized discount on Second Lien Notes due 2024 (1,726 ) (1,782 ) Unamortized debt issuance cost on Second Lien Notes due 2024 (5,067 ) (5,230 ) Long-Term Debt, net $ 424,207 $ 387,988 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of March 31, 2019 and December 31, 2018 , we had $4.1 million and $4.5 million , respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

Price-Risk Management Price-R_3

Price-Risk Management Price-Risk Management (Tables)	3 Months Ended
	Mar. 31, 2019
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 future derivative contracts in place as of March 31, 2019 : Oil Derivative Swaps (NYMEX WTI Settlements) Total Volumes (Bbls) Weighted Average Price 2019 Contracts 2Q19 157,450 $ 57.30 3Q19 176,500 $ 57.98 4Q19 172,500 $ 58.07 2020 Contracts 1Q20 149,300 $ 57.32 2Q20 100,350 $ 56.38 3Q20 97,200 $ 56.49 4Q20 72,000 $ 52.29 2021 Contracts 1Q21 56,175 $ 55.23 Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) Total Volumes Weighted Average Price Weighted Average Collar Floor Weighted Average Collar Call Price 2019 Contracts 2Q19 12,130,000 $ 2.80 3Q19 12,680,000 $ 2.81 4Q19 11,486,000 $ 2.89 2020 Contracts 1Q20 6,280,000 $ 2.87 2Q20 3,688,000 $ 2.76 3Q20 3,585,000 $ 2.76 4Q20 3,362,000 $ 2.77 Collar Contracts 2019 Contracts 2Q19 300,000 $ 2.90 $ 3.15 2021 Contracts 1Q21 4,354,800 $ 2.50 $ 3.52 NGL Contracts Total Volumes (Bbls) Weighted Average Price 2019 Contracts 2Q19 180,000 $ 27.93 3Q19 180,000 $ 27.93 4Q19 180,000 $ 27.93 Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs NYMEX Settlements) Total Volumes Weighted Average Price 2019 Contracts 2Q19 14,477,500 $ 0.05 3Q19 14,625,000 $ 0.04 4Q19 14,625,000 $ (0.02 ) 2020 Contracts 1Q20 11,739,000 $ (0.03 ) 2Q20 11,739,000 $ (0.04 ) 3Q20 11,868,000 $ (0.03 ) 4Q20 11,868,000 $ (0.04 ) 2021 Contracts 1Q21 7,200,000 $ (0.003 ) 2Q21 7,280,000 $ (0.003 ) 3Q21 7,360,000 $ (0.003 ) 4Q21 7,360,000 $ (0.003 ) Oil Basis Contracts (Argus Cushing (WTI) and LLS Settlements) Total Volumes (Bbls) Weighted Average Price 2019 Contracts 2Q19 45,000 $ 4.65 3Q19 45,000 $ 4.65 4Q19 45,000 $ 4.65

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2019
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 March 31, 2019 and December 31, 2018 , 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 notes to condensed consolidated financial statements. Fair Value Measurements at (in millions) Total Quoted Prices in Significant Other Significant March 31, 2019 Assets Natural Gas Derivatives $ 3.2 $ — $ 3.2 $ — Natural Gas Basis Derivatives $ 4.3 $ — $ 4.3 $ — Oil Derivatives $ 1.8 $ — $ 1.8 $ — NGL Derivatives $ 3.1 $ — $ 3.1 $ — Liabilities Natural Gas Derivatives $ 1.8 $ — $ 1.8 $ — Natural Gas Basis Derivatives $ 0.8 $ — $ 0.8 $ — Oil Derivatives $ 4.1 $ — $ 4.1 $ — Oil Basis Derivatives $ 0.1 $ — $ 0.1 $ — December 31, 2018 Assets Natural Gas Derivatives $ 7.5 $ — $ 7.5 $ — Natural Gas Basis Derivatives $ 0.4 $ — $ 0.4 $ — Oil Derivatives $ 6.9 $ — $ 6.9 $ — NGL Derivatives $ 4.7 $ — $ 4.7 $ — Liabilities Natural Gas Derivatives $ 1.0 $ — $ 1.0 $ — Natural Gas Basis Derivatives $ 5.3 $ — $ 5.3 $ — NGL Derivatives $ 0.2 $ — $ 0.2 $ —

Asset Retirement Obligations _3

Asset Retirement Obligations Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2019
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, 2018 and the three months ended March 31, 2019 (in thousands): Asset Retirement Obligations as of December 31, 2017 $ 10,787 Accretion expense 419 Liabilities incurred for new wells and facilities construction 93 Reductions due to sold wells and facilities (6,298 ) Reductions due to plugged wells and facilities (180 ) Revisions in estimates (562 ) Asset Retirement Obligations as of December 31, 2018 $ 4,259 Accretion expense 83 Liabilities incurred for new wells and facilities construction 39 Reductions due to sold wells and facilities — Reductions due to plugged wells and facilities (30 ) Revisions in estimates 6 Asset Retirement Obligations as of March 31, 2019 $ 4,357

Commitments and Contingencies_3

Commitments and Contingencies Commitments and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments under non-cancelable leases	Future minimum rental commitments under non-cancelable leases in effect at December 31, 2018 are as follows (in thousands): December 31, 2018 2019 $ 4,470 2020 838 2021 332 Thereafter — Total undiscounted lease payments $ 5,640

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Oil and gas sales	$ 72,064	$ 52,752
Property and Equipment
Proved oil and gas properties	1,005,988		$ 925,865
Unproved oil and gas properties	64,797		56,715
Furniture, fixtures, and other equipment	3,668		3,520
Less - Accumulated depreciation, depletion, and amortization	(306,609)		(284,804)
Net Furniture, Fixtures and other equipment	767,844		701,296
Accounts Payable and Accrued Liabilities
Trade accounts payable	20,728		32,683
Accrued operating expenses	3,258		3,549
Accrued compensation costs	2,066		4,785
Asset retirement obligation - current portion	284		302
Accrued non-income based taxes	2,533		3,583
Accrued corporate and legal fees	335		534
Other payables	2,774		3,485
Total accounts payable and accrued liabilities	31,978		$ 48,921
Oil sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales	14,607	11,439
Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales	51,304	35,753
NGL sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales	$ 6,154	$ 5,560

Summary of Significant Accoun_5

Summary of Significant Accounting Policies (Details Textual) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Apr. 12, 2019	Jan. 01, 2019	Dec. 31, 2018	Apr. 20, 2018
Summary of Significant Accounting Policies
Total capitalized internal costs	$ 1,600	$ 1,400
Proved oil and gas properties	1,005,988				$ 925,865
Unproved oil and gas properties	64,797				56,715
Furniture, fixtures, and other equipment	3,668				3,520
Less - Accumulated depreciation, depletion, and amortization	(306,609)				(284,804)
Net Furniture, Fixtures and other equipment	767,844				701,296
Write-down of oil and gas properties	0	0
Allowance for doubtful accounts receivable, current	100				100
Accounts receivable, gross	21,400				36,900
Accounts receivable related to joint interest owners	4,500				5,600
Severance tax receivable	3,500				2,400
Other receivables	$ 1,900				1,600
Percentage of working interest in wells	100.00%
Total amount of supervision fees charged to wells	$ 1,300	1,100
Income Tax Expense (Benefit)	232	0
Oil and gas sales	72,064	$ 52,752
Trade accounts payable	20,728				32,683
Accrued operating expenses	3,258				3,549
Accrued payroll costs	2,066				4,785
Asset retirement obligation - current portion	284				302
Accrued non-income based taxes	2,533				3,583
Accrued corporate and legal fees	335				534
Other payables	2,774				3,485
Accounts payable and accrued liabilities	$ 31,978				48,921
Purchase of treasury stock (shares)	11,076	10,458
Operating Lease, Right-of-Use Asset	$ 2,024			$ 2,200	$ 0
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
Line of Credit [Member] | New Credit Facility [Member]
Summary of Significant Accounting Policies
Line of Credit Facility, Current Borrowing Capacity						$ 330,000
Line of Credit [Member] | Subsequent Event [Member] | New Credit Facility [Member]
Summary of Significant Accounting Policies
Line of Credit Facility, Current Borrowing Capacity			$ 410,000
Oil sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales	$ 14,607	$ 11,439
Natural gas sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales	51,304	35,753
NGL sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales	$ 6,154	$ 5,560

Leases Leases (Details)

Leases Leases (Details) $ in Thousands	Mar. 31, 2019USD ($)	Mar. 31, 2019USD ($)
Lessee, Lease, Description [Line Items]
Lease, Cost		$ 1,545
Operating Lease, Weighted Average Remaining Lease Term	4 years 2 months	4 years 2 months
Operating Lease, Weighted Average Discount Rate, Percent	5.07%	5.07%
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	$ 648	$ 648
Lessee, Operating Lease, Liability, Payments, Due Year Two	841	841
Lessee, Operating Lease, Liability, Payments, Due Year Three	358	358
Lessee, Operating Lease, Liability, Payments, Due Year Four	36	36
Lessee, Operating Lease, Liability, Payments, Due Year Five	38	38
Lessee, Operating Lease, Liability, Payments, Due after Year Five	363	363
Lessee, Operating Lease, Liability, Payments, Due	2,284	2,284
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(253)	(253)
Operating Lease, Liability	2,031	2,031
Operating Lease, Payments		203
Operating Lease, Payments, Use		8
Lease Operating Expense [Member]
Lessee, Lease, Description [Line Items]
Short-term Lease, Cost		1,335
Operating Lease, Cost		54
General and Administrative Expense [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost		$ 156
Property, Plant and Equipment [Member]
Lessee, Lease, Description [Line Items]
Short-term Lease, Cost	3,983
Operating Lease, Cost	8
Lease, Cost	$ 3,991

Share-Based Compensation (Detai

Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands	Mar. 31, 2019	Feb. 20, 2018	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Share-based Compensation (Details Textual)
Stock-based compensation expenses			$ 1,692	$ 1,359
Share-based compensation (capitalized)			200	100
Employee Stock Option [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 5,600		5,600
Stock option award outstanding aggregate intrinsic value	$ 100		100
Remaining contract life of outstanding stock options.	6 years 11 months
Remaining contract life of exercisable stock option	3 years 6 months
Stock option award exercisable aggregate intrinsic value			$ 0
Stock Option Activity
Options outstanding, beginning of period, shares	640,378		640,378		644,575
Options outstanding, beginning of period, weighted average price	$ 28.29		$ 28.29		$ 28.28
Options granted, shares			0
Options granted, weighted average price			$ 0
Options forfeited, shares			(4,197)
Options forfeited, weighted average share price			$ 26.96
Options canceled, shares			0
Options canceled, weighted average price			$ 0
Options exercised, shares			0
Options exercised, weighted average price			$ 0
Options exercisable, end of period, shares	195,178		195,178
Options exercisable, end of period, weighted average price	$ 28.87		$ 28.87
Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 6,400		$ 6,400
Unrecognized compensation expense weighted-average period			2 years 5 months
Restricted stock activity
Restricted shares outstanding, beginning of period, shares			340,678
Restricted shares outstanding, beginning of period, weighted average price			$ 27.64
Restricted shares granted, shares			62,650
Restricted shares granted, weighted average price			$ 22.34
Restricted shares forfeited, shares			(8,044)
Restricted shares forfeited, weighted average price			$ 27.47
Restricted shares vested, shares			(61,263)
Restricted shares vested, weighted average price			$ 27.07
Restricted shares outstanding, end of period, shares	334,021		334,021
Restricted shares outstanding, end of period, weighted average price	$ 26.76		$ 26.76
Performance-based stock unit [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 800		$ 800
Unrecognized compensation expense weighted-average period	1 year 11 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	100.00%	150.61%	100.00%
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			$ 1,700	$ 1,400

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Basic EPS:
Net Income (Loss)	$ 16,053	$ 8,466
Income, share amounts	11,708	11,602
Earnings Per Share, Basic	$ 1.37	$ 0.73
Dilutive Securities:
Dilutive RSAs	0	0
Dilutive RSUs	80	18
Dilutive Stock Options	0	107
Diluted EPS:
Net Income (Loss) Available to Common Stockholders, Diluted	$ 16,053	$ 8,466
Weighted Average Number of Shares Outstanding, Diluted	11,788	11,727
Earnings Per Share, Diluted	$ 1.36	$ 0.72
Warrant [Member]
Earnings Per Share (Textual)
Antidilutive shares excluded from EPS, shares	4,300	4,300
Stock Options [Member]
Earnings Per Share (Textual)
Antidilutive shares excluded from EPS, shares	600	400
Restricted Stock Units (RSUs) [Member]
Earnings Per Share (Textual)
Antidilutive shares excluded from EPS, shares	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	Nov. 06, 2018	Dec. 15, 2017USD ($)	Apr. 19, 2017USD ($)	Mar. 31, 2019USD ($)	Mar. 31, 2018USD ($)	Apr. 12, 2019USD ($)	Dec. 31, 2018USD ($)	Apr. 20, 2018USD ($)
Bank Borrowings
Long-term Debt, excluding current maturities				$ 424,207			$ 387,988
Gross interest expense including amortization of debt issuance costs				8,759	$ 5,890
Capitalized interest on our unproved properties				100	400
Second Lien [Abstract]
Long-term debt, gross				431,000			395,000
New Credit Facility [Member]
Bank Borrowings
Debt Issuance Costs, Net				4,100			4,500
Second Lien Notes [Member]
Bank Borrowings
Debt Issuance Costs, Net				5,067			5,230
Long-term Debt, excluding current maturities		$ 198,000		200,000			200,000
Debt instrument escalating basis spread on base rate		50
Gross interest expense including amortization of debt issuance costs				5,300	4,700
Second Lien [Abstract]
Long-term debt, gross		$ 200,000
Debt Instrument, Unamortized Discount		(2,000)		$ (1,726)			(1,782)
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		1.25
Discount Rate for Estimated Future Net Revenues from Proved Properties				10.00%
Second Lien, Covenant, Debt to EBITDA Ratio, Minimum		4.5
Long-term debt, net				$ 193,200
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				231,000			$ 195,000
Line of Credit Facility, Current Borrowing Capacity								$ 330,000
Decrease in applicable margin to calculate interest	25
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				$ 3,500	$ 1,500
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	0.0100
Debt Instrument Escalating Rates for Eurodollar Rate Loans	0.0200
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	0.0200
Debt Instrument Escalating Rates for Eurodollar Rate Loans	0.0300
Subsequent Event [Member] | Line of Credit [Member] | New Credit Facility [Member]
Bank Borrowings
Line of Credit Facility, Current Borrowing Capacity						$ 410,000

Acquisitions and Dispositions_2

Acquisitions and Dispositions Acquisitions and Dispositions (Details) - USD ($) $ in Thousands	Jan. 24, 2018	Mar. 31, 2019	Mar. 31, 2018	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		$ 1,278	$ 6,042
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
Cash to be released for purchase and sale contract		$ 6,200

Price-Risk Management Price-R_4

Price-Risk Management Price-Risk Management (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)bblMMBTU$ / MMBTU$ / Boe	Mar. 31, 2018USD ($)	Dec. 31, 2018USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Price Risk Derivatives, Net | $	$ (4,000)	$ (6,400)
Cash Received (Paid) On Settlements of Derivative Contracts | $	1,077	$ 977
Receivables for Settled Derivatives | $	1,000		$ 700
Payables for Settled Derivatives | $	200		2,200
Derivative, Fair Value, Net | $	5,600		13,000
Other Current Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	8,300		15,300
Other Noncurrent Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	4,000		4,300
Other Current Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	4,600		2,800
Other Noncurrent Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	$ 2,200		$ 3,700
Swap [Member] | Oil Derivative Swaps [Member] | Second Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	157,450
Derivative, Swap Type, Fixed Price | $ / Boe	57.30
Swap [Member] | Oil Derivative Swaps [Member] | Third Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	176,500
Derivative, Swap Type, Fixed Price | $ / Boe	57.98
Swap [Member] | Oil Derivative Swaps [Member] | Fourth Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	172,500
Derivative, Swap Type, Fixed Price | $ / Boe	58.07
Swap [Member] | Oil Derivative Swaps [Member] | First Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	149,300
Derivative, Swap Type, Fixed Price | $ / Boe	57.32
Swap [Member] | Oil Derivative Swaps [Member] | Second Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	100,350
Derivative, Swap Type, Fixed Price | $ / Boe	56.38
Swap [Member] | Oil Derivative Swaps [Member] | Third Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	97,200
Derivative, Swap Type, Fixed Price | $ / Boe	56.49
Swap [Member] | Oil Derivative Swaps [Member] | Fourth Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	72,000
Derivative, Swap Type, Fixed Price | $ / Boe	52.29
Swap [Member] | Oil Derivative Swaps [Member] | First Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	56,175
Derivative, Swap Type, Fixed Price | $ / Boe	55.23
Swap [Member] | Natural Gas Derivative Swaps [Member] | Second Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,130,000
Derivative, Swap Type, Fixed Price	2.80
Swap [Member] | Natural Gas Derivative Swaps [Member] | Third Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,680,000
Derivative, Swap Type, Fixed Price	2.81
Swap [Member] | Natural Gas Derivative Swaps [Member] | Fourth Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	11,486,000
Derivative, Swap Type, Fixed Price	2.89
Swap [Member] | Natural Gas Derivative Swaps [Member] | First Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	6,280,000
Derivative, Swap Type, Fixed Price	2.87
Swap [Member] | Natural Gas Derivative Swaps [Member] | Second Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,688,000
Derivative, Swap Type, Fixed Price	2.76
Swap [Member] | Natural Gas Derivative Swaps [Member] | Third Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,585,000
Derivative, Swap Type, Fixed Price	2.76
Swap [Member] | Natural Gas Derivative Swaps [Member] | Fourth Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,362,000
Derivative, Swap Type, Fixed Price	2.77
Swap [Member] | Natural Gas Liquid Derivative [Member] | Second Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	180,000
Derivative, Swap Type, Fixed Price	27.93
Swap [Member] | Natural Gas Liquid Derivative [Member] | Third Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	180,000
Derivative, Swap Type, Fixed Price	27.93
Swap [Member] | Natural Gas Liquid Derivative [Member] | Fourth Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	180,000
Derivative, Swap Type, Fixed Price	27.93
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	14,477,500
Derivative, Basis Swap Type, Fixed Price	0.05
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	14,625,000
Derivative, Basis Swap Type, Fixed Price	0.04
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	14,625,000
Derivative, Basis Swap Type, Fixed Price	(0.02)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | First Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	11,739,000
Derivative, Basis Swap Type, Fixed Price	(0.03)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	11,739,000
Derivative, Basis Swap Type, Fixed Price	(0.04)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	11,868,000
Derivative, Basis Swap Type, Fixed Price	(0.03)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2020 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	11,868,000
Derivative, Basis Swap Type, Fixed Price	(0.04)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | First Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,200,000
Derivative, Basis Swap Type, Fixed Price	(0.003)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,280,000
Derivative, Basis Swap Type, Fixed Price	(0.003)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,360,000
Derivative, Basis Swap Type, Fixed Price	(0.003)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,360,000
Derivative, Basis Swap Type, Fixed Price	(0.003)
Basis Swap [Member] | Oil Basis Derivative [Member] | Second Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	45,000
Derivative, Basis Swap Type, Fixed Price	4.65
Basis Swap [Member] | Oil Basis Derivative [Member] | Third Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	45,000
Derivative, Basis Swap Type, Fixed Price	4.65
Basis Swap [Member] | Oil Basis Derivative [Member] | Fourth Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	45,000
Derivative, Basis Swap Type, Fixed Price	4.65
Forward Contracts [Member] | Natural Gas Derivative Swaps [Member] | Second Quarter 2019 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	300,000
Derivative, Average Floor Price	2.90
Derivative, Average Cap Price	3.15
Forward Contracts [Member] | Natural Gas Derivative Swaps [Member] | First Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,354,800
Derivative, Average Floor Price	2.50
Derivative, Average Cap Price	3.52

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 3.2	$ 7.5
Derivative Liability	1.8	1
Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	4.3	0.4
Derivative Liability	0.8	5.3
Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	1.8	6.9
Derivative Liability	4.1
Natural Gas Liquid Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	3.1	4.7
Derivative Liability		0.2
Oil Basis Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	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] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	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	0
Derivative Liability		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
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	3.2	7.5
Derivative Liability	1.8	1
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	4.3	0.4
Derivative Liability	0.8	5.3
Fair Value, Inputs, Level 2 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	1.8	6.9
Derivative Liability	4.1
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	3.1	4.7
Derivative Liability		0.2
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	0.1
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] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	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	0
Derivative Liability		$ 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

Asset Retirement Obligations _4

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	$ 4,357		$ 4,259	$ 10,787
Accretion expense	83	$ 159	419
Liabilities incurred for new wells and facilities construction	39		93
Reductions due to sold wells and facilities	0		(6,298)
Reductions due to plugged wells and facilities	(30)		(180)
Revisions in estimates	6		(562)
Asset retirement obligation - current portion	$ 284		$ 302

Commitments and Contingencies_4

Commitments and Contingencies Commitments and Contingencies (Details) - Operating lease commitments [Member] $ in Thousands	Dec. 31, 2018USD ($)
Other Commitments [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 4,470
Operating Leases, Future Minimum Payments, Due in Two Years	838
Operating Leases, Future Minimum Payments, Due in Three Years	332
Operating Leases, Future Minimum Payments, Due in Four Years	0
Operating Leases, Future Minimum Payments Due	$ 5,640