SilverBow Resources (SBOW) 10-K 4 Mar 21 2020 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2020	Jan. 31, 2021	Jun. 30, 2020
Document and Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 2020
Entity File Number	1-8754
Entity Registrant Name	SILVERBOW RESOURCES, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	20-3940661
Entity Address, Address Line One	575 North Dairy Ashford
Entity Address, Address Line Two	Suite 1200
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77079
City Area Code	(281)
Local Phone Number	874-2700
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	SBOW
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Public Float			$ 14,623,839
Entity Common Stock, Shares Outstanding		11,936,679
Entity Central Index Key	0000351817
Current Fiscal Year End Date	--12-31
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Filer Category	Non-accelerated Filer
Document Transition Report	false
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false
Document Annual Report	true

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current Assets:
Cash and cash equivalents	$ 2,118	$ 1,358
Accounts receivable	25,850	36,996
Fair value of commodity derivatives	4,821	12,833
Other current assets	2,184	2,121
Total Current Assets	34,973	53,308
Property and Equipment:
Property and Equipment, Full-Cost Method, including $28,090 and $41,201 of unproved property costs not being amortized	1,343,373	1,247,717
Less - Accumulated depreciation, depletion, and amortization	(801,279)	(380,728)
Property and Equipment, Net	542,094	866,989
Operating Lease, Right-of-Use Asset	4,366	9,374
Fair value of long-term commodity derivatives	281	3,854
Deferred Tax Assets, Net	0	22,669
Other Long-Term Assets	1,421	3,622
Total Assets	583,135	959,816
Current Liabilities:
Accounts payable and accrued liabilities	26,991	39,343
Fair value of commodity derivatives	8,171	6,644
Accrued capital costs	7,324	17,889
Accrued interest	983	1,397
Current lease liability	3,473	6,707
Undistributed oil and gas revenues	11,098	9,166
Total Current Liabilities	58,040	81,146
Long-Term Debt	424,905	472,900
Non-current lease liability	951	2,813
Deferred tax liabilities, net	303	1,582
Asset Retirement Obligation	4,533	4,055
Fair value of long-term commodity derivatives	2,946	1,613
Other long-term liabilities	424	0
Stockholders' Equity:
Preferred Stock, Value, Outstanding	0	0
Common Stock, Value, Issued	121	119
Additional paid-in capital	297,712	292,916
Treasury Stock, Value	(2,372)	(2,282)
Retained earnings (Accumulated deficit)	(204,428)	104,954
Total Stockholders' Equity (Deficit)	91,033	395,707
Total Liabilities and Stockholders' Equity	$ 583,135	$ 959,816

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Capitalized Costs, Unproved Properties	$ 28,090	$ 41,201
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	12,053,763	11,895,032
Common stock, shares outstanding	11,936,679	11,806,679
Treasury stock shares held, at cost	117,084	88,353

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenues:
Oil and gas sales	$ 177,386	$ 288,631
Costs and Expenses:
General and administrative, net	22,608	24,851
Depreciation, depletion, and amortization	64,564	95,915
Accretion of asset retirement obligation	354	329
Lease operating cost	21,360	20,763
Results of Operations, Expense, Other	8	628
Results of Operations, Transportation Costs	20,649	26,968
Severance and other taxes	10,514	13,874
Write-down of oil and gas properties	355,948	0
Total Operating Expenses	496,005	183,328
Operating Income (Loss)	(318,619)	105,303
Net gain (loss) on commodity derivatives	61,304	24,242
Interest expense, net	(31,228)	(36,561)
Other income (expense), net	72	90
Income (Loss) Before Income Taxes	(288,471)	93,074
Provision (Benefit) for Income Taxes	20,911	(21,582)
Net Income (Loss)	$ (309,382)	$ 114,656
Per Share Amounts-
Earnings (Loss) Per Share, Basic	$ (25.99)	$ 9.76
Earnings (Loss) Per Share, Diluted	$ (25.99)	$ 9.74
Weighted Average Shares Outstanding - Basic	11,902	11,753
Weighted Average Shares Outstanding - Diluted	11,902	11,778

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($)	Total	Common Stock	Additional Paid-in Capital	Treasury Stock	Retained Earnings (Deficit)
Beginning Balance	$ 274,827,000	$ 118,000	$ 286,281,000	$ (1,870,000)	$ (9,702,000)
Purchase of treasury shares	(412,000)	0	0	(412,000)	0
Issuance of restricted stock	0	1,000	(1,000)	0	0
Amortization of share-based compensation	6,636,000	0	6,636,000	0	0
Net Income (Loss)	114,656,000	0	0	0	114,656,000
Beginning Balance	395,707,000	119,000	292,916,000	(2,282,000)	104,954,000
Shares issued from option exercise	0	0	0	0	0
Purchase of treasury shares	(90,000)	0	0	(90,000)	0
Issuance of restricted stock	1,000	2,000	(1,000)	0	0
Amortization of share-based compensation	4,797,000	0	4,797,000	0	0
Net Income (Loss)	(309,382,000)	0	0	0	(309,382,000)
Beginning Balance	$ 91,033,000	$ 121,000	$ 297,712,000	$ (2,372,000)	$ (204,428,000)

Consolidated Statements of St_2

Consolidated Statements of Stockholders' Equity (Parenthetical) - shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Statement of Stockholders' Equity [Abstract]
Shares issued from stock option exercises	5	0
Purchase of treasury shares (shares)	28,731	22,482
Issuance of common stock (shares)	0	0
Issuance of restricted stock (shares)	158,726	137,060

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cash Flows from Operating Activities:
Net Income (Loss)	$ (309,382)	$ 114,656
Adjustments to reconcile net income to net cash provided by operation activities -
Write-down of oil and gas properties	355,948	0
Depreciation, depletion, and amortization	64,564	95,915
Accretion of asset retirement obligation	354	329
Deferred income taxes	21,390	(22,101)
Stock-based compensation expense	4,557	6,148
Gain (Loss) on Sale of Derivatives	(61,304)	(24,242)
Cash Received (Paid) On Settlements of Derivative Contracts	78,421	24,631
Asset Retirement Obligation, Cash Paid to Settle	(94)	(83)
Write off of Deferred Debt Issuance Cost	557	82
Other Noncash Income (Expense)	3,061	2,930
Change in assets and liabilities-
(Increase) decrease in accounts receivable and other assets	9,011	11,605
Increase (decrease) in accounts payable and accrued liabilities	(977)	(7,100)
Increase (decrease) in income taxes payable	480	(519)
Increase (decrease) in accrued interest	(414)	(116)
Net Cash Provided by Operating Activities	165,212	203,173
Cash Flows from Investing Activities:
Additions to property and equipment	(114,738)	(282,660)
Acquisition of properties	(4,544)	0
Proceeds from (adjustments to) the sale of property and equipment	4,777	(96)
Payments for (Proceeds from) Other Investing Activities	(826)	(5,112)
Net Cash Used in Investing Activities	(115,331)	(287,868)
Cash Flows from Financing Activities:
Proceeds from bank borrowings	107,000	381,000
Payments of bank borrowings	(156,000)	(297,000)
Purchase of treasury shares	(90)	(412)
Payments of debt issuance costs	(31)	0
Net Cash Provided by (Used in) Financing Activities	(49,121)	83,588
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect	760	(1,107)
Total Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	2,118	1,358
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized	28,929	34,408
Increase (decrease) in accrued payables for capital	$ (19,365)	$ (21,584)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Principles of Consolidation . The accompanying consolidated financial statements include the accounts of SilverBow Resources and its wholly owned subsidiary, SilverBow Resources Operating LLC, 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 consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements. COVID-19 . In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In March, the spot price of West Texas Intermediate (“WTI”) crude oil declined over 50% in response to reductions in global demand due to the COVID-19 pandemic and announcements by Saudi Arabia and Russia of plans to increase crude oil production. Following this unprecedented collapse in crude oil prices, the spot price of Brent and WTI crude oil closed at approximately $15 and $21 per barrel, respectively, on March 31, 2020. In April 2020, WTI oil prices declined further to approximately $10 per barrel for May 2020 delivery. Crude oil prices fell further in April but partially recovered during the second quarter of 2020 with Brent and WTI crude oil closing at approximately $41 and $39 per barrel, respectively, on June 30, 2020. Crude oil prices traded slightly higher in the third quarter of 2020 with Brent and WTI crude closing at approximately $42 and $40 per barrel, on September 30, 2020. Crude oil prices continued to improve in the fourth quarter of 2020 with Brent and WTI crude closing at approximately $52 and $49 per barrel, respectively, on December 31, 2020. In response to these market conditions, including the COVID-19 pandemic and the decline in oil prices and economic outlook, the Company released its sole drilling rig in April 2020, and deferred the completion and placement on production of eight wells until the second half of 2020. In the third quarter of 2020, the Company restarted completions activity and returned to sales all previously curtailed oil volumes and a substantial portion of natural gas volumes. Approximately 20 million cubic feet per day (“MMcf/d”) of net gas production remained shut-in at quarter-end. The Company began returning these volumes to production in late October 2020 to align with favorable natural gas prices, with all previously shut-in volumes returned to production as of December 31, 2020. The full impact of the COVID-19 pandemic continues to evolve as of the date of this report. As such, the full magnitude that the pandemic will have on the Company’s financial condition, liquidity, and future results of operations is uncertain. Management is actively monitoring the impact of the COVID-19 pandemic on the Company's financial condition, liquidity, operations, suppliers, industry and workforce. In addition, if the depressed pricing environment continues for an extended period, it may in the future lead to (i) a further reduction in oil and natural gas reserves, including the possible further removal of proved undeveloped reserves (ii) further impairment of proved and/or unproved oil and natural gas properties and a potential increase in depletion expense and (iii) reductions in the borrowing base under the Credit Agreement as discussed in Note 4. If the COVID-19 pandemic and volatile oil price environment continues, it may have a material adverse effect on the Company’s operating cash flows, liquidity, and future development plans. Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. On February 5, 2021, and in the ordinary course of business, the Company entered into a new five-year lease agreement for office space in Houston, Texas. The operating lease begins on May 18, 2021. Through February 26, 2021, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after December 31, 2020: Oil Derivative Contracts Total Volumes (Bbls) (1) Weighted-Average Price 2021 Contracts Swap Purchase Contracts 1Q21 (2) 13,750 $ 53.10 2Q21 (2) 51,050 $ 53.22 2022 Contracts Swap Contracts 1Q22 45,000 $ 50.00 2Q22 45,500 $ 50.00 3Q22 46,000 $ 50.00 4Q22 46,000 $ 50.00 (1) Bbl refers to one barrel of oil. (2) Transaction for a swap purchase to reduce overall hedge position. Oil Derivative Contracts Total Volumes Weighted-Average Price Calendar Monthly Roll Differential Swaps 2022 Contracts 1Q22 90,000 $ 0.18 2Q22 91,000 $ 0.18 3Q22 92,000 $ 0.18 4Q22 92,000 $ 0.18 Natural Gas Derivative Contracts Total Volumes Weighted-Average Collar Floor Price Weighted-Average Collar Call Price 2021 Contracts 2Q21 1,820,000 $ 2.83 $ 2.98 3Q21 1,850,000 $ 2.88 $ 3.09 4Q21 1,840,000 $ 2.95 $ 3.18 2022 Contracts 1Q22 3,150,000 $ 2.95 $ 3.31 Natural Gas Basis Derivative Swaps Total Volumes (MMBtu) Weighted Average Price 2022 Contracts 1Q22 900,000 $ (0.030) 2Q22 910,000 $ (0.030) 3Q22 920,000 $ (0.030) 4Q22 920,000 $ (0.030) NGL Contracts Total Volumes Weighted-Average Price 2021 Contracts 1Q21 101,714 $ 23.14 2Q21 144,733 $ 24.13 3Q21 146,324 $ 24.13 4Q21 146,324 $ 24.13 Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“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 therefrom, 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 may be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations 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 years ended December 31, 2020 and 2019, such internal costs when capitalized totaled $3.5 million and $5.3 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 4 of these Notes to Consolidated Financial Statements for further discussion on capitalized interest costs). The “Property and Equipment” balances on the accompanying consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): December 31, December 31, Property and Equipment Proved oil and gas properties $ 1,310,008 $ 1,201,296 Unproved oil and gas properties 28,090 41,201 Furniture, fixtures, and other equipment 5,275 5,220 Less – Accumulated depreciation, depletion, amortization & impairment (801,279) (380,728) Property and Equipment, Net $ 542,094 $ 866,989 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 Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas 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 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 a $355.9 million ceiling test write-down for the year ended December 31, 2020. There was no write-down for the year ended December 31, 2019. 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 remain depressed or continue to decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. Revenue Recognition . 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. 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 Consolidated Statements of Operations for years ended December 31, 2020 and 2019 (in thousands): Year Ended December 31, 2020 Year Ended December 31, 2019 Oil, natural gas and NGLs sales: Oil $ 57,651 $ 92,833 Natural gas 105,234 170,558 NGLs 14,500 25,241 Total $ 177,386 $ 288,631 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 December 31, 2020 and 2019, 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, net” balance on the accompanying consolidated balance sheets. At December 31, 2020, our “Accounts receivable, net” balance included $18.8 million for oil and gas sales, $4.0 million due from joint interest owners, $2.4 million for severance tax credit receivables and $0.7 million for other receivables. At December 31, 2019, our “Accounts receivable, net” balance included $24.6 million for oil and gas sales, $3.7 million for joint interest owners, $5.4 million for severance tax credit receivables and $3.3 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 consolidated statements of operations. The amount of supervision fees charged for each of the years ended December 31, 2020 and 2019 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $4.4 million and $4.9 million for the years ended December 31, 2020 and 2019, 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 with a greater than 50% 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 December 31, 2020, we did not have any accrued liability for uncertain tax positions. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020, management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter to offset its net deferred tax assets in excess of deferred tax liabilities. This resulted in tax expense of $21.2 million through the second quarter of 2020. Our income tax provision of $20.9 million for the year ended December 31, 2020 is inclusive of a state income tax benefit of $1.8 million. During the second quarter of 2019, the Company was able to complete several operational initiatives that resulted in increased production, lower development costs and expanded inventory of development prospects. The results of these initiatives led management to determine, after weighing both positive and negative evidence, that the Company would more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, the Company released the valuation allowance resulting in a net deferred income tax benefit of $21.6 million, which is net of $1.1 million of state income tax expense, for the year ended December 31, 2019 On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and modifications to the net interest deduction limitation. On December 27, 2020, President Trump signed into law the Consolidated Appropriations Act, 2021 (the “Appropriations Act”). The Appropriations Act funds the federal government to the end of the fiscal year and provides further COVID-19 economic relief, including expansion of the employee retention credit. The Company continues to examine the impact that the CARES Act and the Appropriations Act may have on its business but does not currently expect either to have a material effect on its financial condition, results of operation, or liquidity. Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying consolidated balance sheets are summarized below (in thousands): December 31, December 31, Trade accounts payable $ 15,930 $ 26,121 Accrued operating expenses 2,491 3,873 Accrued compensation costs 3,771 4,601 Asset retirement obligations – current portion 441 392 Accrued non-income based taxes 1,819 1,413 Accrued corporate and legal fees 150 109 Other payables 2,389 2,834 Total accounts payable and accrued liabilities $ 26,991 $ 39,343 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. Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners' receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. From certain customers we also obtain letters of credit or parent company guarantees, if applicable, to reduce risk of loss. For the years ended December 31, 2020 and 2019, parties that accounted for 10% or more of our total oil and gas receipts were as follows: Purchasers greater than 10% Year Ended December 31, 2020 Year Ended December 31, 2019 Kinder Morgan 19 % 31 % Plains Marketing 17 % 14 % Twin Eagle 17 % 13 % Trafigura US 13 % * Shell Trading * 11 % *Oil and gas receipts less than 10% Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying consolidated balance sheets. For the years ended December 31, 2020 and 2019, we purchased 28,731 and 22,482 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. New Accounting Pronouncements . In March 2020, the FASB issued ASU No. 2020-03. ASU 2020-03 improves and clarifies various financial instruments topics, including the current expected credit loss standard (“CECL”). ASU 2020-03 includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make the standards easier to understand and apply by eliminating inconsistencies and providing clarifications. This guidance is effective beginning on January 1, 2023 for smaller reporting companies. We are still assessing the requirements to determine the impact of this guidance on our consolidated financial statements. Leases . In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), 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 with an effective date of January 1, 2019.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Earnings Per Share	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. 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): Year Ended December 31, 2020 Year Ended December 31, 2019 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ (309,382) 11,902 $ (25.99) $ 114,656 11,753 $ 9.76 Dilutive Securities: Restricted Stock Unit Awards — 25 Stock Option Awards — — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ (309,382) 11,902 $ (25.99) $ 114,656 11,778 $ 9.74 Approximately 0.3 million and 0.5 million stock options to purchase shares were not included in the computation of Diluted EPS for the years ended December 31, 2020 and 2019 respectively, because these stock options were antidilutive. Approximately 0.2 million and 0.3 million shares of restricted stock units that could be converted to common shares were not included in the computation of Diluted EPS for the years ended December 31, 2020 and 2019, respectively, because they were antidilutive. Approximately 0.1 million performance-based restricted stock units were not included in the computation of Diluted EPS for each of the years ended December 31, 2020 and 2019 because they were antidilutive. Approximately 2.1 million warrants to purchase common stock were not included in the computation of Diluted EPS for the year ended December 31, 2019 because these warrants were antidilutive. There were no warrants to purchase common stock for the year ended December 31, 2020 as the warrants expired.

Provision (Benefit) for Income

Provision (Benefit) for Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes	Provision (Benefit) for Income TaxesIncome (Loss) before taxes is as follows (in thousands): Year Ended December 31, 2020 Year Ended December 31, 2019 Income (Loss) Before Income Taxes $ (288,471) $ 93,074 The following is an analysis of the consolidated income tax provision (benefit) (in thousands): Year Ended December 31, 2020 Year Ended December 31, 2019 Current $ (480) $ 519 Deferred 21,391 (22,101) Total $ 20,911 $ (21,582) Reconciliations of income taxes computed using the U.S. Federal statutory rate of (21%) to the effective income tax rate are as follows: Year Ended December 31, 2020 Year Ended December 31, 2019 Federal Statutory Rate 21.0 % 21.0 % State tax provisions (benefits), net of federal benefits 0.6 % 1.0 % Executive compensation limitation — % 0.3 % Other, net (0.2) % 0.1 % Valuation allowance adjustments (28.6) % (45.5) % Effective rate (7.2) % (23.0) % The tax effects of temporary differences representing the net deferred tax asset (liability) at December 31, 2020 and 2019 were as follows (in thousands): Year Ended December 31, 2020 Year Ended December 31, 2019 Deferred tax assets: Federal net operating loss (“NOL”) carryovers $ 93,293 $ 67,610 Other carryover items 610 552 Asset retirement obligations 1,074 960 Share-based compensation 959 1,210 Lease liability 929 1,999 Other 1,029 874 Valuation allowance (82,618) — Total deferred tax assets $ 15,276 $ 73,205 Deferred tax liabilities: Oil and gas exploration and development costs $ (13,008) $ (48,329) Derivative contracts (1,653) (1,820) Leased assets (917) (1,968) Other (1) (1) Total deferred tax liabilities (15,579) (52,118) Net deferred tax asset (liabilities) $ (303) $ 21,087 State net deferred tax liabilities $ (303) $ (1,582) Federal net deferred tax assets — 22,669 Net deferred tax asset (liabilities) $ (303) $ 21,087 The Company’s valuation allowance balance was $82.6 million and $0 million at December 31, 2020 and 2019, respectively. The Company recorded a net deferred tax liability for state income tax purposes at December 31, 2020 and 2019. The Company’s NOL carryforward asset is attributable to Federal tax losses of $115 million generated from 2013 through 2015, $160 million generated in 2017 and $170 million generated from 2018 through 2020. The losses generated between 2013 and 2015 are subject to an annual utilization limit under Sec. 382. These losses will expire between 2034 and 2035 if not utilized. The 2017 loss will expire in 2037 if not utilized. The 2018, 2019 and 2020 losses will not expire under the current tax code, but their usage will be limited to 80% of taxable income. Our U.S. federal and most state income tax returns from 2017 forward are subject to examination. For years prior to 2017 our U.S. federal returns are subject to examination to the extent of our net operating loss (NOL) carryforwards. Our Texas tax returns from 2016 forward are subject to examination. There are no material unresolved items related to periods previously audited by the taxing authorities.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The Company's long-term debt consisted of the following (in thousands): December 31, 2020 December 31, 2019 Credit Facility Borrowings (1) $ 230,000 $ 279,000 Second Lien Notes due 2024 200,000 200,000 430,000 479,000 Unamortized discount on Second Lien Notes due 2024 (1,295) (1,550) Unamortized debt issuance cost on Second Lien Notes due 2024 (3,800) (4,550) Total Long-Term Debt $ 424,905 $ 472,900 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of December 31, 2020 and 2019, we had $1.4 million and $3.1 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings. Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $230.0 million and $279.0 million as of December 31, 2020 and 2019, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”). The Company entered into the Sixth Amendment to the Credit Facility, effective November 2, 2020 (the “Sixth Amendment”), which among other things, (i) decreased the borrowing base under the Credit Facility to $310 million (from $330 million) as part of the regularly scheduled semi-annual redetermination and (ii) decreased the ratio of total debt to EBITDA (defined below) to not exceed 3.5 to 1.0. The Credit Facility matures April 19, 2022 and provides for a maximum credit amount of $600 million and a current borrowing base of $310 million as of December 31, 2020. 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 reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. There were no outstanding letters of credit as of December 31, 2020 and 2019. 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 May 12, 2020, the applicable margin ranged from 1.75% to 2.75% for ABR Loans and 2.75% to 3.75% for Eurodollar Loans. The Alternate Base Rate and LIBOR Rate 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. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. At the present time, the Credit Facility is subject to LIBOR rates but has a term that extends beyond the end of 2021 when LIBOR will be phased out. The Sixth Amendment includes technical updates to address this matter, and we are currently evaluating the potential impact of eventual replacement of the LIBOR interest rate. 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 its subsidiary, including a first priority lien on properties attributed with at least 85% of estimated proved reserves of the Company and its subsidiary. The Credit Agreement contains the following financial covenants: • a ratio of total debt to earnings before interest, tax, depreciation and amortization ("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 for any fiscal quarter ending on or before September 30, 2020 and (ii) 3.5 to 1.0 as of the last day of each fiscal quarter, commencing with fiscal quarter ending December 31, 2020; 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 December 31, 2020, 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, changes in our lender's lending criteria 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 $12.6 million and $15.7 million for the years ended December 31, 2020 and 2019, respectively. The amount of commitment fee amortization included in interest expense, net was $0.4 million and $0.7 million for the years ended December 31, 2020 and 2019, respectively. There was no capitalized interest and $0.2 million on our unproved properties for the years ended December 31, 2020 and 2019, 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”, such second lien facility, the “Second Lien” and such notes, the “Second Lien Notes”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent and certain holders that are a party thereto, and issued notes in an initial principal amount of $200.0 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 $100.0 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 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. 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 its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 85% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary 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. PV-9 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 9%. 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 subsidiary and in the denominator the total net indebtedness of the Company and its restricted subsidiary, of not less than 1.25 to 1.0 as of each date of determination (the “Asset Coverage Ratio”). 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 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 December 31, 2020, 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 December 31, 2020, net amounts recorded for the Second Lien Notes were $194.9 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $18.6 million and $21.1 million for the years ended December 31, 2020 and 2019, 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.

Price-Risk Management Price-Ris

Price-Risk Management Price-Risk Management (Notes)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities	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 “Gain (loss) on commodity derivatives, net” on the accompanying 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 years ended December 31, 2020 and 2019, the Company recorded gains of $61.3 million and $24.2 million, respectively, relating to our derivative activities. The Company received net cash payments of $78.4 million and $24.6 million for settled derivative contracts during the years ended December 31, 2020 and 2019, respectively. Included in our collected cash payments during the year ended December 31, 2020 was $38.3 million for monetized derivative contracts received in the first quarter of 2020. At December 31, 2020 and 2019, we had $0.8 million and $2.9 million, respectively, in receivables for settled derivatives which were included on the accompanying consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in January 2021 and 2020, respectively. At December 31, 2020 and 2019, we also had $0.8 million and $0.2 million, respectively, in payables for settled derivatives which were included on the accompanying consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in January 2021 and 2020, respectively. The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. At December 31, 2020 there was $4.8 million and $0.3 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $8.2 million and $2.9 million in current unsettled derivative liabilities and long-term unsettled derivative liabilities, respectively. At December 31, 2019, the Company had $12.8 million and $3.9 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $6.6 million and $1.6 million in current unsettled derivative liabilities 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 an $6.0 million net fair value liability at December 31, 2020 and $8.4 million net fair value asset at December 31, 2019. For further discussion related to the fair value of the Company's derivatives, refer to Note 10 of these Notes to 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 December 31, 2020. Oil Derivative Swaps Total Volumes (Bbls) Weighted Average Price Weighted Average Collar Floor Price Weighted Average Collar Call Price 2021 Contracts 1Q21 143,538 $ 51.89 2Q21 195,646 $ 51.93 3Q21 179,759 $ 51.19 4Q21 163,812 $ 52.39 2022 Contracts 1Q22 88,455 $ 36.79 3Q22 108,100 $ 41.58 Collar Contracts 2021 Contracts 1Q21 155,475 $ 34.15 $ 39.24 2Q21 116,980 $ 34.33 $ 40.30 3Q21 90,620 $ 34.34 $ 39.87 4Q21 84,640 $ 34.70 $ 41.01 2022 Contracts 1Q22 40,500 $ 40.00 $ 45.55 2Q22 115,850 $ 39.25 $ 46.20 Natural Gas Derivative Swaps Total Volumes (MMBtu) Weighted Average Price Weighted Average Collar Floor Price Weighted Average Collar Call Price 2021 Contracts 1Q21 2,398,078 $ 2.74 2Q21 832,255 $ 2.42 3Q21 330,000 $ 2.62 4Q21 290,000 $ 2.69 Collar Contracts 2021 Contracts 1Q21 7,027,800 $ 2.53 $ 3.33 2Q21 5,911,000 $ 2.26 $ 2.70 3Q21 6,045,175 $ 2.15 $ 2.70 4Q21 5,311,000 $ 2.35 $ 2.76 2022 Contracts 1Q22 4,415,000 $ 2.50 $ 3.35 2Q22 4,200,000 $ 2.23 $ 2.70 3Q22 3,933,000 $ 2.39 $ 2.74 Natural Gas Basis Derivative Swaps Total Volumes (MMBtu) Weighted Average Price 2021 Contracts 1Q21 9,900,000 $ (0.022) 2Q21 10,010,000 $ (0.022) 3Q21 10,120,000 $ (0.022) 4Q21 10,120,000 $ (0.022) 2022 Contracts 1Q22 1,800,000 $ (0.080) 2Q22 1,820,000 $ (0.080) 3Q22 1,840,000 $ (0.080) 4Q22 1,840,000 $ (0.080) Oil Basis Derivative Swaps Total Volumes (Bbls) Weighted Average Price 2021 Contracts 1Q21 373,750 $ 1.19 2Q21 329,150 $ 1.22 3Q21 262,200 $ 1.27 4Q21 241,500 $ 1.28 Calendar Monthly Roll Differential Swaps 2021 Contracts 1Q21 367,000 $ (0.40) 2Q21 313,900 $ (0.37) 3Q21 253,000 $ (0.34) 4Q21 241,500 $ (0.33) 2022 Contracts 1Q22 90,000 $ (0.12) 2Q22 91,000 $ (0.12) 3Q22 92,000 $ (0.12) 4Q22 92,000 $ (0.12)

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies We have gas transportation and processing minimum obligations amounting to $5.2 million for 2021, $3.9 million for 2022, $2.6 million for 2023, $1.6 million for 2024, $1.1 million for 2025 and $14.4 million in the aggregate. 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.

Share-Based Compensation Share-

Share-Based Compensation Share-Based Compensation (Notes)	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement, Noncash Expense [Abstract]
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. The Company accounts for forfeitures in compensation cost when they occur. The Company computes a deferred tax benefit for restricted stock awards (“RSUs”), performance-based stock units (“PSUs”) and stock options designed 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 consolidated statements of operations was $4.6 million and $6.1 million for the years ended December 31, 2020 and 2019 respectively. Capitalized share-based compensation was $0.2 million and $0.5 million for the years ended December 31, 2020 and 2019, 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. Our shares available for future grant under the Plans were 726,723 at December 31, 2020. On April 2, 2019, our Board of Directors authorized a one-time grant of market-based awards (both RSUs and PSUs) in exchange for the cancellation of special equity awards (both RSUs and stock options) made to our named executive officers on August 9, 2018 (the “Equity Award Exchange”). As required under the terms of the 2016 Plan, this Equity Award Exchange was subject to shareholder approval. Pursuant to the Equity Award Exchange our executives were given the opportunity to exchange out-of-the-money or “underwater” stock options that were granted in August 2018 and certain RSUs also granted in August 2018 to receive a new equity award that consists of 50% time-based RSUs and 50% PSUs, granted under the 2016 Plan. The incremental compensation cost associated with the Equity Award Exchange was determined to be $1.2 million. This incremental cost was measured as the excess of the fair value of each new equity award, measured as of the date the new equity awards were granted, over the fair value of the stock options and RSUs surrendered in exchange for the new equity awards, measured immediately prior to the cancellation. This incremental compensation cost is being recognized ratably over the vesting period or performance period, as applicable, of the new equity awards. Stock Option Awards The compensation cost related to these awards is based on the grant date fair value and is expensed over the vesting period (generally one five At December 31, 2020, we had $0.6 million in unrecognized compensation cost related to stock option awards. The following table represents stock option award activity for the year ended December 31, 2020: Shares Wtd. Avg. Options outstanding, beginning of period 324,324 $ 27.68 Options expired (20,619) $ 26.96 Options outstanding, end of period 303,705 $ 27.73 Options exercisable, end of period 206,179 $ 28.41 Our outstanding stock option awards at December 31, 2020 had no measurable aggregate intrinsic value. At December 31, 2020 the weighted-average remaining contract life of stock option awards outstanding was 4.8 years and exercisable was 4.0 years. The stock option awards exercisable as of December 31, 2020 had no intrinsic value. Restricted Stock Units The Plans 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 five As of December 31, 2020, we had unrecognized compensation expense of $2.4 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 1.1 years. The following table provides information regarding restricted stock unit activity for the year ended December 31, 2020: Shares Wtd. Avg. Restricted units outstanding, beginning of period 342,683 $ 22.10 Restricted stock units granted 397,285 $ 2.83 Restricted stock units forfeited (6,326) $ 19.46 Restricted stock units vested (158,726) $ 21.38 Restricted stock units outstanding, end of period 574,916 $ 9.02 Performance-Based Stock Units On February 20, 2018, the Company granted 30,700 performance share 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 during the performance period from January 1, 2018 to December 31, 2020. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the date of valuation was $41.66 per unit or 150.61% of the stock price. 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 On May 21, 2019, the Company granted an additional 99,500 performance-based stock units (as part of the Equity Award Exchange discussed above) for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. 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 $18.86 per unit or 112.9% of stock price. The awards have a cliff-vesting period of three As of December 31, 2020, we had unrecognized compensation expense of $1.0 million related to our performance-based stock units based on the assumption of 100.0% target payout. The remaining weighted-average performance period is 1.0 years. No shares vested during the year ended December 31, 2020. Employee Savings Plan We have a savings plan under Section 401(k) of the Internal Revenue Code. The Company contributed on behalf of eligible employees an amount up to 100% of the first 6% of compensation based on the contributions made by the eligible employees in 2020 and 2019. The Company's plan contributions of $0.6 million for both the years ended December 31, 2020 and 2019, respectively, were paid in cash during each pay period. These amounts were recorded as “General and administrative, net” on the accompanying consolidated statements of operations.

Leases Leases (Notes)

Leases Leases (Notes)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Lessee, Operating Leases [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. All of the Company’s leases are 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 accompanying Consolidated Balance Sheets. 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, and the Company does not account for lease and non-lease components separately. 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): Year Ended December 31, 2020 Year Ended December 31, 2019 Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets Property, plant and equipment acquisitions - short-term leases $ 3,774 $ 10,573 Property, plant and equipment acquisitions - operating leases 10 41 Total lease costs in property, plant and equipment additions $ 3,784 $ 10,614 Year Ended December 31, 2020 Year Ended December 31, 2019 Lease Costs Included in the Condensed Consolidated Statements of Operations Lease operating costs - short-term leases $ 724 $ 2,071 Lease operating costs - operating leases 5,655 3,945 General and administrative, net - operating leases 704 681 Total lease cost expensed $ 7,083 $ 6,697 The lease term and the discount rate related to the Company's leases are as follows: As of December 31, 2020 Weighted-average remaining lease term (in years) 1.9 Weighted-average discount rate 4.5 % As of December 31, 2020, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): As of December 31, 2020 2020 $ 3,573 2021 542 2022 166 2023 38 2024 39 Thereafter 287 Total undiscounted lease payments $ 4,645 Present value adjustment (221) Net operating lease liabilities $ 4,424 Supplemental cash flow information related to leases was as follows (in thousands): Year Ended December 31, 2020 Year Ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows $ 6,352 $ 4,609 Investing cash flows $ 10 $ 41 Rental and lease expense was $5.8 million and $5.4 million for the years ended December 31, 2020 and 2019, respectively. The rental and lease expense primarily relates to compressor rentals and the lease of our office space in Houston, Texas. During 2016 the Company entered into a four

Acquisitions and Dispositions

Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
Acquisitions and Dispositions	Acquisitions and DispositionsEffective 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, $0.8 million and $5.1 million was paid during the years ended December 31, 2020 and 2019, respectively. The remaining obligation under this contract is $1.6 million and is carried in the accompanying consolidated balance sheet as a current liability in “Accounts payable and accrued liabilities” as of December 31, 2020. On April 3, 2020, we acquired additional properties in the Eagle Ford for approximately $5.0 million, including assumed liabilities. The acquisition included eight producing wells, basic infrastructure and acreage in Webb, La Salle, and McMullen Counties. We allocated all of the purchase price to proved oil and gas properties. The Company accounted for this transaction as an asset acquisition with the properties added to our full cost pool balance. On May 13, 2020, the Company divested an overriding royalty interest in Converse and Niobrara Counties, Wyoming for approximately $4.8 million. The sales of our Wyoming assets did not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds were recorded as adjustments to our domestic full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Wyoming operations through the date of sale.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements Fair Value on a Recurring Basis . Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien Notes. 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 fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. These are considered Level 2 valuations (defined below). 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. The following table presents our assets and liabilities that are measured on a recurring basis as of December 31, 2020 and 2019, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 5 of these Notes to Consolidated Financial Statements. Fair Value Measurements at (in millions) Total Quoted Prices in Significant Other Significant December 31, 2020 Assets Natural Gas Derivatives $ 1.5 $ — $ 1.5 $ — Natural Gas Basis Derivatives $ 1.1 $ — $ 1.1 $ — Oil Derivatives $ 2.5 $ — $ 2.5 $ — Liabilities Natural Gas Derivatives $ 4.0 $ — $ 4.0 $ — Natural Gas Basis Derivatives $ 0.4 $ — $ 0.4 $ — Oil Derivatives $ 5.9 $ — $ 5.9 $ — Oil Basis Derivatives $ 0.8 $ — $ 0.8 $ — December 31, 2019 Assets Natural Gas Derivatives $ 11.7 $ — $ 11.7 $ — Natural Gas Basis Derivatives $ 3.4 $ — $ 3.4 $ — Oil Derivatives $ 1.6 $ — $ 1.6 $ — Liabilities Natural Gas Derivatives $ 0.2 $ — $ 0.2 $ — Natural Gas Basis Derivatives $ 0.9 $ — $ 0.9 $ — Oil Derivatives $ 7.0 $ — $ 7.0 $ — Oil Basis Derivatives $ 0.1 $ — $ 0.1 $ — 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)	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	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 consolidated balance sheets. The following provides a roll-forward of our asset retirement obligations (in thousands): Asset Retirement Obligations as of December 31, 2018 $ 4,259 Accretion expense 329 Liabilities incurred for new wells and facilities construction 250 Reductions due to plugged wells and facilities (82) Revisions in estimates (309) Asset Retirement Obligations as of December 31, 2019 $ 4,447 Accretion expense 354 Liabilities incurred for new wells and facilities construction 281 Reductions due to plugged wells and facilities (103) Revisions in estimates (5) Asset Retirement Obligations as of December 31, 2020 $ 4,974 At December 31, 2020 and 2019, approximately $0.4 million of our asset retirement obligations were classified as current liabilities in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation . The accompanying consolidated financial statements include the accounts of SilverBow Resources and its wholly owned subsidiary, SilverBow Resources Operating LLC, 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 consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements.
Use of Estimates	Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“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 therefrom, 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 may be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations 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.
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 years ended December 31, 2020 and 2019, such internal costs when capitalized totaled $3.5 million and $5.3 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 4 of these Notes to Consolidated Financial Statements for further discussion on capitalized interest costs). The “Property and Equipment” balances on the accompanying consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): December 31, December 31, Property and Equipment Proved oil and gas properties $ 1,310,008 $ 1,201,296 Unproved oil and gas properties 28,090 41,201 Furniture, fixtures, and other equipment 5,275 5,220 Less – Accumulated depreciation, depletion, amortization & impairment (801,279) (380,728) Property and Equipment, Net $ 542,094 $ 866,989 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 Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas 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 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 a $355.9 million ceiling test write-down for the year ended December 31, 2020. There was no write-down for the year ended December 31, 2019. 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 remain depressed or continue to 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
Revenue Recognition	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. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers.
Accounts Receivable	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 December 31, 2020 and 2019, 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, net” balance on the accompanying 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 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 with a greater than 50% 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 December 31, 2020, we did not have any accrued liability for uncertain tax positions. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020, management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter to offset its net deferred tax assets in excess of deferred tax liabilities. This resulted in tax expense of $21.2 million through the second quarter of 2020. Our income tax provision of $20.9 million for the year ended December 31, 2020 is inclusive of a state income tax benefit of $1.8 million. During the second quarter of 2019, the Company was able to complete several operational initiatives that resulted in increased production, lower development costs and expanded inventory of development prospects. The results of these initiatives led management to determine, after weighing both positive and negative evidence, that the Company would more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, the Company released the valuation allowance resulting in a net deferred income tax benefit of $21.6 million, which is net of $1.1 million of state income tax expense, for the year ended December 31, 2019 On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and modifications to the net interest deduction limitation. On December 27, 2020, President Trump signed into law the Consolidated Appropriations Act, 2021 (the “Appropriations Act”). The Appropriations Act funds the federal government to the end of the fiscal year and provides further COVID-19 economic relief, including expansion of the employee retention credit. The Company continues to examine the impact that the CARES Act and the Appropriations Act may have on its business but does not currently expect either to have a material effect on its financial condition, results of operation, or liquidity.
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying consolidated balance sheets are summarized below (in thousands): December 31, December 31, Trade accounts payable $ 15,930 $ 26,121 Accrued operating expenses 2,491 3,873 Accrued compensation costs 3,771 4,601 Asset retirement obligations – current portion 441 392 Accrued non-income based taxes 1,819 1,413 Accrued corporate and legal fees 150 109 Other payables 2,389 2,834 Total accounts payable and accrued liabilities $ 26,991 $ 39,343
Cash and Cash Equivalents and Restricted Cash	Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted.
Credit Risk Due To Certain Concentrations	Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners' receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. From certain customers we also obtain letters of credit or parent company guarantees, if applicable, to reduce risk of loss.
Treasury Stock	Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying consolidated balance sheets. For the years ended December 31, 2020 and 2019, we purchased 28,731 and 22,482 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.
New Accounting Pronouncements	New Accounting Pronouncements . In March 2020, the FASB issued ASU No. 2020-03. ASU 2020-03 improves and clarifies various financial instruments topics, including the current expected credit loss standard (“CECL”). ASU 2020-03 includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make

Earnings Per Share Earning Per

Earnings Per Share Earning Per Share (Policies)	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per ShareBasic 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.

Long-Term Debt Long-Term Debt (

Long-Term Debt Long-Term Debt (Policies)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Debt Issuance Costs	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)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities, Policy	Price-Risk Management ActivitiesDerivatives 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 “Gain (loss) on commodity derivatives, net” on the accompanying 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.

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies (Policies)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies We have gas transportation and processing minimum obligations amounting to $5.2 million for 2021, $3.9 million for 2022, $2.6 million for 2023, $1.6 million for 2024, $1.1 million for 2025 and $14.4 million in the aggregate. 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.

Share-Based Compensation Shar_2

Share-Based Compensation Share-Based Compensation (Policies)	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement, Noncash Expense [Abstract]
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. The Company accounts for forfeitures in compensation cost when they occur. The Company computes a deferred tax benefit for restricted stock awards (“RSUs”), performance-based stock units (“PSUs”) and stock options designed 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 consolidated statements of operations was $4.6 million and $6.1 million for the years ended December 31, 2020 and 2019 respectively. Capitalized share-based compensation was $0.2 million and $0.5 million for the years ended December 31, 2020 and 2019, 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. Our shares available for future grant under the Plans were 726,723 at December 31, 2020.

Leases Leases (Policies)

Leases Leases (Policies)	12 Months Ended
	Dec. 31, 2020
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. All of the Company’s leases are 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 accompanying Consolidated Balance Sheets. 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, and the Company does not account for lease and non-lease components separately. The Company recognizes lease expense on a straight-line basis over the lease term.

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Measurements (Policies)	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	Fair Value Measurements Fair Value on a Recurring Basis . Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien Notes. 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 fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. These are considered Level 2 valuations (defined below). 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)	12 Months Ended
	Dec. 31, 2020
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 consolidated balance sheets.

Summary of Signigicant Accounti

Summary of Signigicant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Schedule of Subsequent Events	Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. On February 5, 2021, and in the ordinary course of business, the Company entered into a new five-year lease agreement for office space in Houston, Texas. The operating lease begins on May 18, 2021. Through February 26, 2021, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after December 31, 2020: Oil Derivative Contracts Total Volumes (Bbls) (1) Weighted-Average Price 2021 Contracts Swap Purchase Contracts 1Q21 (2) 13,750 $ 53.10 2Q21 (2) 51,050 $ 53.22 2022 Contracts Swap Contracts 1Q22 45,000 $ 50.00 2Q22 45,500 $ 50.00 3Q22 46,000 $ 50.00 4Q22 46,000 $ 50.00 (1) Bbl refers to one barrel of oil. (2) Transaction for a swap purchase to reduce overall hedge position. Oil Derivative Contracts Total Volumes Weighted-Average Price Calendar Monthly Roll Differential Swaps 2022 Contracts 1Q22 90,000 $ 0.18 2Q22 91,000 $ 0.18 3Q22 92,000 $ 0.18 4Q22 92,000 $ 0.18 Natural Gas Derivative Contracts Total Volumes Weighted-Average Collar Floor Price Weighted-Average Collar Call Price 2021 Contracts 2Q21 1,820,000 $ 2.83 $ 2.98 3Q21 1,850,000 $ 2.88 $ 3.09 4Q21 1,840,000 $ 2.95 $ 3.18 2022 Contracts 1Q22 3,150,000 $ 2.95 $ 3.31 Natural Gas Basis Derivative Swaps Total Volumes (MMBtu) Weighted Average Price 2022 Contracts 1Q22 900,000 $ (0.030) 2Q22 910,000 $ (0.030) 3Q22 920,000 $ (0.030) 4Q22 920,000 $ (0.030) NGL Contracts Total Volumes Weighted-Average Price 2021 Contracts 1Q21 101,714 $ 23.14 2Q21 144,733 $ 24.13 3Q21 146,324 $ 24.13 4Q21 146,324 $ 24.13
Property and Equipment	The following is a detailed breakout of our “Property and Equipment” balances (in thousands): December 31, December 31, Property and Equipment Proved oil and gas properties $ 1,310,008 $ 1,201,296 Unproved oil and gas properties 28,090 41,201 Furniture, fixtures, and other equipment 5,275 5,220 Less – Accumulated depreciation, depletion, amortization & impairment (801,279) (380,728) Property and Equipment, Net $ 542,094 $ 866,989
Disaggregation of Revenue	The following table provides information regarding our oil and gas sales, by product, reported on the Consolidated Statements of Operations for years ended December 31, 2020 and 2019 (in thousands): Year Ended December 31, 2020 Year Ended December 31, 2019 Oil, natural gas and NGLs sales: Oil $ 57,651 $ 92,833 Natural gas 105,234 170,558 NGLs 14,500 25,241 Total $ 177,386 $ 288,631
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying consolidated balance sheets are summarized below (in thousands): December 31, December 31, Trade accounts payable $ 15,930 $ 26,121 Accrued operating expenses 2,491 3,873 Accrued compensation costs 3,771 4,601 Asset retirement obligations – current portion 441 392 Accrued non-income based taxes 1,819 1,413 Accrued corporate and legal fees 150 109 Other payables 2,389 2,834 Total accounts payable and accrued liabilities $ 26,991 $ 39,343
Oil and Gas receipts greater than 10%	For the years ended December 31, 2020 and 2019, parties that accounted for 10% or more of our total oil and gas receipts were as follows: Purchasers greater than 10% Year Ended December 31, 2020 Year Ended December 31, 2019 Kinder Morgan 19 % 31 % Plains Marketing 17 % 14 % Twin Eagle 17 % 13 % Trafigura US 13 % * Shell Trading * 11 %

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2020
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): Year Ended December 31, 2020 Year Ended December 31, 2019 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ (309,382) 11,902 $ (25.99) $ 114,656 11,753 $ 9.76 Dilutive Securities: Restricted Stock Unit Awards — 25 Stock Option Awards — — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ (309,382) 11,902 $ (25.99) $ 114,656 11,778 $ 9.74

Provision (Benefit) for Incom_2

Provision (Benefit) for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Summary of income (Loss) from continuing operations before taxes	Income (Loss) before taxes is as follows (in thousands): Year Ended December 31, 2020 Year Ended December 31, 2019 Income (Loss) Before Income Taxes $ (288,471) $ 93,074
Summary of consolidated income tax provision (benefit)	The following is an analysis of the consolidated income tax provision (benefit) (in thousands): Year Ended December 31, 2020 Year Ended December 31, 2019 Current $ (480) $ 519 Deferred 21,391 (22,101) Total $ 20,911 $ (21,582)
Reconciliations of income taxes computed using the U.S. Federal statutory rate to the effective income tax rates	Reconciliations of income taxes computed using the U.S. Federal statutory rate of (21%) to the effective income tax rate are as follows: Year Ended December 31, 2020 Year Ended December 31, 2019 Federal Statutory Rate 21.0 % 21.0 % State tax provisions (benefits), net of federal benefits 0.6 % 1.0 % Executive compensation limitation — % 0.3 % Other, net (0.2) % 0.1 % Valuation allowance adjustments (28.6) % (45.5) % Effective rate (7.2) % (23.0) %
Tax effects of temporary differences representing the net deferred tax asset (liability)	The tax effects of temporary differences representing the net deferred tax asset (liability) at December 31, 2020 and 2019 were as follows (in thousands): Year Ended December 31, 2020 Year Ended December 31, 2019 Deferred tax assets: Federal net operating loss (“NOL”) carryovers $ 93,293 $ 67,610 Other carryover items 610 552 Asset retirement obligations 1,074 960 Share-based compensation 959 1,210 Lease liability 929 1,999 Other 1,029 874 Valuation allowance (82,618) — Total deferred tax assets $ 15,276 $ 73,205 Deferred tax liabilities: Oil and gas exploration and development costs $ (13,008) $ (48,329) Derivative contracts (1,653) (1,820) Leased assets (917) (1,968) Other (1) (1) Total deferred tax liabilities (15,579) (52,118) Net deferred tax asset (liabilities) $ (303) $ 21,087 State net deferred tax liabilities $ (303) $ (1,582) Federal net deferred tax assets — 22,669 Net deferred tax asset (liabilities) $ (303) $ 21,087

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Long-term debt	The Company's long-term debt consisted of the following (in thousands): December 31, 2020 December 31, 2019 Credit Facility Borrowings (1) $ 230,000 $ 279,000 Second Lien Notes due 2024 200,000 200,000 430,000 479,000 Unamortized discount on Second Lien Notes due 2024 (1,295) (1,550) Unamortized debt issuance cost on Second Lien Notes due 2024 (3,800) (4,550) Total Long-Term Debt $ 424,905 $ 472,900 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of December 31, 2020 and 2019, we had $1.4 million and $3.1 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)	12 Months Ended
	Dec. 31, 2020
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 December 31, 2020. Oil Derivative Swaps Total Volumes (Bbls) Weighted Average Price Weighted Average Collar Floor Price Weighted Average Collar Call Price 2021 Contracts 1Q21 143,538 $ 51.89 2Q21 195,646 $ 51.93 3Q21 179,759 $ 51.19 4Q21 163,812 $ 52.39 2022 Contracts 1Q22 88,455 $ 36.79 3Q22 108,100 $ 41.58 Collar Contracts 2021 Contracts 1Q21 155,475 $ 34.15 $ 39.24 2Q21 116,980 $ 34.33 $ 40.30 3Q21 90,620 $ 34.34 $ 39.87 4Q21 84,640 $ 34.70 $ 41.01 2022 Contracts 1Q22 40,500 $ 40.00 $ 45.55 2Q22 115,850 $ 39.25 $ 46.20 Natural Gas Derivative Swaps Total Volumes (MMBtu) Weighted Average Price Weighted Average Collar Floor Price Weighted Average Collar Call Price 2021 Contracts 1Q21 2,398,078 $ 2.74 2Q21 832,255 $ 2.42 3Q21 330,000 $ 2.62 4Q21 290,000 $ 2.69 Collar Contracts 2021 Contracts 1Q21 7,027,800 $ 2.53 $ 3.33 2Q21 5,911,000 $ 2.26 $ 2.70 3Q21 6,045,175 $ 2.15 $ 2.70 4Q21 5,311,000 $ 2.35 $ 2.76 2022 Contracts 1Q22 4,415,000 $ 2.50 $ 3.35 2Q22 4,200,000 $ 2.23 $ 2.70 3Q22 3,933,000 $ 2.39 $ 2.74 Natural Gas Basis Derivative Swaps Total Volumes (MMBtu) Weighted Average Price 2021 Contracts 1Q21 9,900,000 $ (0.022) 2Q21 10,010,000 $ (0.022) 3Q21 10,120,000 $ (0.022) 4Q21 10,120,000 $ (0.022) 2022 Contracts 1Q22 1,800,000 $ (0.080) 2Q22 1,820,000 $ (0.080) 3Q22 1,840,000 $ (0.080) 4Q22 1,840,000 $ (0.080) Oil Basis Derivative Swaps Total Volumes (Bbls) Weighted Average Price 2021 Contracts 1Q21 373,750 $ 1.19 2Q21 329,150 $ 1.22 3Q21 262,200 $ 1.27 4Q21 241,500 $ 1.28 Calendar Monthly Roll Differential Swaps 2021 Contracts 1Q21 367,000 $ (0.40) 2Q21 313,900 $ (0.37) 3Q21 253,000 $ (0.34) 4Q21 241,500 $ (0.33) 2022 Contracts 1Q22 90,000 $ (0.12) 2Q22 91,000 $ (0.12) 3Q22 92,000 $ (0.12) 4Q22 92,000 $ (0.12)

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Stock Option Valuation Assumptions	The compensation cost related to these awards is based on the grant date fair value and is expensed over the vesting period (generally one five
Stock Option Activity	The following table represents stock option award activity for the year ended December 31, 2020: Shares Wtd. Avg. Options outstanding, beginning of period 324,324 $ 27.68 Options expired (20,619) $ 26.96 Options outstanding, end of period 303,705 $ 27.73 Options exercisable, end of period 206,179 $ 28.41
Restricted Stock Units Activity	The following table provides information regarding restricted stock unit activity for the year ended December 31, 2020: Shares Wtd. Avg. Restricted units outstanding, beginning of period 342,683 $ 22.10 Restricted stock units granted 397,285 $ 2.83 Restricted stock units forfeited (6,326) $ 19.46 Restricted stock units vested (158,726) $ 21.38 Restricted stock units outstanding, end of period 574,916 $ 9.02

Leases Leases (Tables)

Leases Leases (Tables)	12 Months Ended
	Dec. 31, 2020
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): Year Ended December 31, 2020 Year Ended December 31, 2019 Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets Property, plant and equipment acquisitions - short-term leases $ 3,774 $ 10,573 Property, plant and equipment acquisitions - operating leases 10 41 Total lease costs in property, plant and equipment additions $ 3,784 $ 10,614 Year Ended December 31, 2020 Year Ended December 31, 2019 Lease Costs Included in the Condensed Consolidated Statements of Operations Lease operating costs - short-term leases $ 724 $ 2,071 Lease operating costs - operating leases 5,655 3,945 General and administrative, net - operating leases 704 681 Total lease cost expensed $ 7,083 $ 6,697
Lessee, Operating Lease, Disclosure [Table Text Block]	The lease term and the discount rate related to the Company's leases are as follows: As of December 31, 2020 Weighted-average remaining lease term (in years) 1.9 Weighted-average discount rate 4.5 %
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	As of December 31, 2020, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): As of December 31, 2020 2020 $ 3,573 2021 542 2022 166 2023 38 2024 39 Thereafter 287 Total undiscounted lease payments $ 4,645 Present value adjustment (221) Net operating lease liabilities $ 4,424
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	Supplemental cash flow information related to leases was as follows (in thousands): Year Ended December 31, 2020 Year Ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows $ 6,352 $ 4,609 Investing cash flows $ 10 $ 41

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table presents our assets and liabilities that are measured on a recurring basis as of December 31, 2020 and 2019, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 5 of these Notes to Consolidated Financial Statements. Fair Value Measurements at (in millions) Total Quoted Prices in Significant Other Significant December 31, 2020 Assets Natural Gas Derivatives $ 1.5 $ — $ 1.5 $ — Natural Gas Basis Derivatives $ 1.1 $ — $ 1.1 $ — Oil Derivatives $ 2.5 $ — $ 2.5 $ — Liabilities Natural Gas Derivatives $ 4.0 $ — $ 4.0 $ — Natural Gas Basis Derivatives $ 0.4 $ — $ 0.4 $ — Oil Derivatives $ 5.9 $ — $ 5.9 $ — Oil Basis Derivatives $ 0.8 $ — $ 0.8 $ — December 31, 2019 Assets Natural Gas Derivatives $ 11.7 $ — $ 11.7 $ — Natural Gas Basis Derivatives $ 3.4 $ — $ 3.4 $ — Oil Derivatives $ 1.6 $ — $ 1.6 $ — Liabilities Natural Gas Derivatives $ 0.2 $ — $ 0.2 $ — Natural Gas Basis Derivatives $ 0.9 $ — $ 0.9 $ — Oil Derivatives $ 7.0 $ — $ 7.0 $ — Oil Basis Derivatives $ 0.1 $ — $ 0.1 $ —

Asset Retirement Obligations _3

Asset Retirement Obligations Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Roll-forward of our asset retirement obligations	The following provides a roll-forward of our asset retirement obligations (in thousands): Asset Retirement Obligations as of December 31, 2018 $ 4,259 Accretion expense 329 Liabilities incurred for new wells and facilities construction 250 Reductions due to plugged wells and facilities (82) Revisions in estimates (309) Asset Retirement Obligations as of December 31, 2019 $ 4,447 Accretion expense 354 Liabilities incurred for new wells and facilities construction 281 Reductions due to plugged wells and facilities (103) Revisions in estimates (5) Asset Retirement Obligations as of December 31, 2020 $ 4,974

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 177,386	$ 288,631
Concentration Risk, Percentage	10.00%
Property, Plant and Equipment [Abstract]
Proved oil and gas properties	$ 1,310,008	1,201,296
Unproved oil and gas properties	28,090	41,201
Furniture, fixtures, and other equipment	5,275	5,220
Less - Accumulated depreciation, depletion, and amortization	(801,279)	(380,728)
Property, Plant and Equipment, Net	542,094	866,989
Accounts Payable and Accrued Liabilities [Abstract]
Trade accounts payable	15,930	26,121
Accrued operating expenses	2,491	3,873
Accrued payroll costs	3,771	4,601
Asset retirement obligation - current portion	441	392
Accrued taxes	1,819	1,413
Accrued Professional Fees, Current	150	109
Other payables	2,389	2,834
Total accounts payable and accrued liabilities	$ 26,991	$ 39,343
Kinder Morgan Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	19.00%	31.00%
Plains Marketing Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	17.00%	14.00%
Twin Eagle Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	17.00%	13.00%
Shell Trading Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage		11.00%
Trafigura US
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	13.00%
Oil sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 57,651	$ 92,833
Natural gas sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	105,234	170,558
NGL sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 14,500	$ 25,241

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details Textual) $ in Thousands, MMcf in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2020USD ($)	Dec. 31, 2020USD ($)bblMMBTU$ / MMBTU$ / Boeshares	Dec. 31, 2019USD ($)shares	Feb. 26, 2021MMBTUbbl$ / MMBTU$ / Boe	Sep. 30, 2020MMcf	Apr. 21, 2020	Mar. 31, 2020
Summary of Significant Accounting Policies (Textual) [Abstract]
Brent Spot Price	41	52			42		15
WTI Spot Price	39	49			40		21
WTI May 2020 Pricing						10
Curtailed Natural Gas Volumes | MMcf					20
Total capitalized internal costs | $		$ 3,500	$ 5,300
Write-down of oil and gas properties | $		$ 355,948	0
Discount rate for estimated future net revenues from proved properties		10.00%
Revenue from Contract with Customer, Excluding Assessed Tax | $		$ 177,386	288,631
Allowance for doubtful accounts receivable, current | $		100	100
Accounts receivable from oil and gas sales | $		18,800	24,600
Accounts receivable related to joint interest owners | $		4,000	3,700
Severance tax credit receivables | $		2,400	5,400
Other receivables | $		$ 700	3,300
Percentage of working interest in wells		100.00%
Total amount of supervision fees charged to wells | $		$ 4,400	4,900
Income Tax Expense (Benefit) | $	$ 21,200	20,911	(21,582)
Current State and Local Tax Expense (Benefit) | $		$ (1,800)	$ 1,100
Treasury Stock, Shares, Acquired | shares		28,731	22,482
Operating Lease, Right-of-Use Asset | $		$ 4,366	$ 9,374
Concentration Risk, Percentage		10.00%
First Quarter 2021 [Member] | Natural Gas Basis Derivative [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price		(0.022)
First Quarter 2021 [Member] | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU		7,027,800
Derivative, Average Floor Price		2.53
Derivative, Average Cap Price		3.33
First Quarter 2021 [Member] | Natural Gas Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price		2.74
First Quarter 2021 [Member] | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU		155,475
Derivative, Average Floor Price		34.15
Derivative, Average Cap Price		39.24
First Quarter 2021 [Member] | Oil Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price | $ / Boe		51.89
First Quarter 2021 [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl		367,000
Derivative, Swap Type, Average Fixed Price		(0.40)
First Quarter 2021 [Member] | Swap Purchase | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				13,750
Derivative, Swap Type, Average Fixed Price | $ / Boe				53.10
First Quarter 2021 [Member] | NGL Contract | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				101,714
Derivative, Swap Type, Average Fixed Price | $ / Boe				23.14
Second Quarter 2021 [Member] | Natural Gas Basis Derivative [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price		(0.022)
Second Quarter 2021 [Member] | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU		5,911,000
Derivative, Average Floor Price		2.26
Derivative, Average Cap Price		2.70
Second Quarter 2021 [Member] | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU				1,820,000
Derivative, Average Floor Price				2.83
Derivative, Average Cap Price				2.98
Second Quarter 2021 [Member] | Natural Gas Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price		2.42
Second Quarter 2021 [Member] | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU		116,980
Derivative, Average Floor Price		34.33
Derivative, Average Cap Price		40.30
Second Quarter 2021 [Member] | Oil Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price | $ / Boe		51.93
Second Quarter 2021 [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl		313,900
Derivative, Swap Type, Average Fixed Price		(0.37)
Second Quarter 2021 [Member] | Swap Purchase | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				51,050
Derivative, Swap Type, Average Fixed Price | $ / Boe				53.22
Second Quarter 2021 [Member] | NGL Contract | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				144,733
Derivative, Swap Type, Average Fixed Price | $ / Boe				24.13
Third Quarter 2021 [Member] | Natural Gas Basis Derivative [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price		(0.022)
Third Quarter 2021 [Member] | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU		6,045,175
Derivative, Average Floor Price		2.15
Derivative, Average Cap Price		2.70
Third Quarter 2021 [Member] | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU				1,850,000
Derivative, Average Floor Price				2.88
Derivative, Average Cap Price				3.09
Third Quarter 2021 [Member] | Natural Gas Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price		2.62
Third Quarter 2021 [Member] | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU		90,620
Derivative, Average Floor Price		34.34
Derivative, Average Cap Price		39.87
Third Quarter 2021 [Member] | Oil Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price | $ / Boe		51.19
Third Quarter 2021 [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl		253,000
Derivative, Swap Type, Average Fixed Price		(0.34)
Third Quarter 2021 [Member] | NGL Contract | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				146,324
Derivative, Swap Type, Average Fixed Price | $ / Boe				24.13
Fourth Quarter 2021 [Member] | Natural Gas Basis Derivative [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price		(0.022)
Fourth Quarter 2021 [Member] | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU		5,311,000
Derivative, Average Floor Price		2.35
Derivative, Average Cap Price		2.76
Fourth Quarter 2021 [Member] | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU				1,840,000
Derivative, Average Floor Price				2.95
Derivative, Average Cap Price				3.18
Fourth Quarter 2021 [Member] | Natural Gas Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price		2.69
Fourth Quarter 2021 [Member] | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU		84,640
Derivative, Average Floor Price		34.70
Derivative, Average Cap Price		41.01
Fourth Quarter 2021 [Member] | Oil Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price | $ / Boe		52.39
Fourth Quarter 2021 [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl		241,500
Derivative, Swap Type, Average Fixed Price		(0.33)
Fourth Quarter 2021 [Member] | NGL Contract | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				146,324
Derivative, Swap Type, Average Fixed Price | $ / Boe				24.13
First Quarter 2022 | Natural Gas Basis Derivative [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price		(0.080)
First Quarter 2022 | Natural Gas Basis Derivative [Member] | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU				900,000
Derivative, Swap Type, Average Fixed Price				(0.030)
First Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU		4,415,000
Derivative, Average Floor Price		2.50
Derivative, Average Cap Price		3.35
First Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU				3,150,000
Derivative, Average Floor Price				2.95
Derivative, Average Cap Price				3.31
First Quarter 2022 | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU		40,500
Derivative, Average Floor Price		40
Derivative, Average Cap Price		45.55
First Quarter 2022 | Oil Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price | $ / Boe		36.79
First Quarter 2022 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				45,000
Derivative, Swap Type, Average Fixed Price | $ / Boe				50
First Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl		90,000
Derivative, Swap Type, Average Fixed Price		(0.12)
First Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				90,000
Derivative, Swap Type, Average Fixed Price				0.18
Second Quarter 2022 | Natural Gas Basis Derivative [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price		(0.080)
Second Quarter 2022 | Natural Gas Basis Derivative [Member] | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU				910,000
Derivative, Swap Type, Average Fixed Price				(0.030)
Second Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU		4,200,000
Derivative, Average Floor Price		2.23
Derivative, Average Cap Price		2.70
Second Quarter 2022 | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU		115,850
Derivative, Average Floor Price		39.25
Derivative, Average Cap Price		46.20
Second Quarter 2022 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				45,500
Derivative, Swap Type, Average Fixed Price | $ / Boe				50
Second Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl		91,000
Derivative, Swap Type, Average Fixed Price		(0.12)
Second Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				91,000
Derivative, Swap Type, Average Fixed Price				0.18
Third Quarter 2022 | Natural Gas Basis Derivative [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price		(0.080)
Third Quarter 2022 | Natural Gas Basis Derivative [Member] | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU				920,000
Derivative, Swap Type, Average Fixed Price				(0.030)
Third Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU		3,933,000
Derivative, Average Floor Price		2.39
Derivative, Average Cap Price		2.74
Third Quarter 2022 | Oil Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price | $ / Boe		41.58
Third Quarter 2022 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				46,000
Derivative, Swap Type, Average Fixed Price | $ / Boe				50
Third Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl		92,000
Derivative, Swap Type, Average Fixed Price		(0.12)
Third Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				92,000
Derivative, Swap Type, Average Fixed Price				0.18
Fourth Quarter 2022 | Natural Gas Basis Derivative [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Swap Type, Average Fixed Price		(0.080)
Fourth Quarter 2022 | Natural Gas Basis Derivative [Member] | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | MMBTU				920,000
Derivative, Swap Type, Average Fixed Price				(0.030)
Fourth Quarter 2022 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				46,000
Derivative, Swap Type, Average Fixed Price | $ / Boe				50
Fourth Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl		92,000
Derivative, Swap Type, Average Fixed Price		(0.12)
Fourth Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative, Nonmonetary Notional Amount | bbl				92,000
Derivative, Swap Type, Average Fixed Price				0.18
Kinder Morgan Concentration Risk [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Concentration Risk, Percentage		19.00%	31.00%
Plains Marketing Concentration Risk [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Concentration Risk, Percentage		17.00%	14.00%
Twin Eagle Concentration Risk [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Concentration Risk, Percentage		17.00%	13.00%
Shell Trading Concentration Risk [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Concentration Risk, Percentage			11.00%
Trafigura US
Summary of Significant Accounting Policies (Textual) [Abstract]
Concentration Risk, Percentage		13.00%
Minimum [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Property, Plant and Equipment, Useful Life		2 years
Maximum [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Property, Plant and Equipment, Useful Life		20 years
Oil sales [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Revenue from Contract with Customer, Excluding Assessed Tax | $		$ 57,651	$ 92,833
Natural gas sales [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Revenue from Contract with Customer, Excluding Assessed Tax | $		105,234	170,558
NGL sales [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Revenue from Contract with Customer, Excluding Assessed Tax | $		$ 14,500	$ 25,241

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Basic EPS:
Net Income (Loss)	$ (309,382)	$ 114,656
Income, Share Amounts	11,902	11,753
Earnings (Loss) Per Share, Basic	$ (25.99)	$ 9.76
Dilutive Securities:
Dilutive Restricted Stock Unit Awards	0	25
Dilutive Stock Option Awards	0	0
Diluted EPS:
Net Income (Loss) Available to Common Stockholders, Diluted	$ (309,382)	$ 114,656
Weighted Average Number of Shares Outstanding, Diluted	11,902	11,778
Earnings (Loss) Per Share, Diluted	$ (25.99)	$ 9.74
Stock Options [Member]
Earnings Per Share (Textual) [Abstract]
Antidilutive shares not included in the computation of diluted EPS	300	500
Restricted Stock Units (RSUs) [Member]
Earnings Per Share (Textual) [Abstract]
Antidilutive shares not included in the computation of diluted EPS	200	300
Performance Shares [Member]
Earnings Per Share (Textual) [Abstract]
Antidilutive shares not included in the computation of diluted EPS	100	100
Warrant [Member]
Earnings Per Share (Textual) [Abstract]
Antidilutive shares not included in the computation of diluted EPS	0	2,100

Provision (Benefit) for Incom_3

Provision (Benefit) for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Summary of income (Loss) from continuing operations before taxes
Income (Loss) Before Income Taxes	$ (288,471)	$ 93,074

Consolidated income tax provisi

Consolidated income tax provision (benefit) (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2020	Dec. 31, 2020	Dec. 31, 2019
Summary of consolidated income tax provision (benefit)
Current income taxes		$ (480)	$ 519
Deferred Income Tax Expense (Benefit)		21,391	(22,101)
Income tax provision (benefit)	$ 21,200	$ 20,911	$ (21,582)

Reconciliation of income taxes

Reconciliation of income taxes using federal statutory rate to effective income tax rate (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Reconciliations of income taxes computed using the U.S. Federal statutory rate to the effective income tax rates
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%
State tax provisions (benefits), net of federal benefits	0.60%	1.00%
Executive compensation limitation	0.00%	0.30%
Other, net	(0.20%)	0.10%
Valuation allowance adjustments	(28.60%)	(45.50%)
Effective rate	(7.20%)	(23.00%)

Tax effects of temporary differ

Tax effects of temporary differences representing the net DTA (DTL) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred tax assets:
DTA, Federal net operating losses (NOLs)	$ 93,293	$ 67,610
DTA, Other loss carryforwards	610	552
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Asset Retirement Obligations	1,074	960
DTA, Unrealized share-based compensation	959	1,210
Deferred Tax Assets, Tax Deferred Expense, Other	929	1,999
DTA, Other	1,029	874
DTA, Valuation Allowance	(82,618)	0
Total deferred tax assets	15,276	73,205
Deferred tax liabilities:
DTL, Oil and gas exploration and development costs	(13,008)	(48,329)
Deferred Tax Liabilities, Derivatives	(1,653)	(1,820)
Deferred Tax Liabilities, Leasing Arrangements	(917)	(1,968)
DTL, Other	(1)	(1)
Total deferred tax liabilites	15,579	52,118
Net deferred tax liabilities	(303)	21,087
State deferred tax liabilities, net	(303)	(1,582)
Federal deferred tax assets, net	$ 0	$ 22,669

Provision (Benefit) for Incom_4

Provision (Benefit) for Income Taxes (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Effective income tax rate reconciliation, percent	21.00%	21.00%
Deferred Tax Assets, Valuation Allowance	$ 82,618	$ 0
Operating Loss Carryforward, Income Tax Limitation	80.00%
Tax Year 2015 [Member]
Operating Loss Carryforwards	$ 115,000
Tax Year 2017 [Member]
Operating Loss Carryforwards	160,000
Tax Year 2020
Operating Loss Carryforwards	$ 170,000

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands	Nov. 02, 2020USD ($)	May 12, 2020USD ($)	Dec. 15, 2017USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Apr. 19, 2017USD ($)
Bank Borrowings
Long-Term Debt, excluding current maturities				$ 424,905	$ 472,900
Interest expense including commitment fees and amortization of debt issuance costs relating to the credit facility				31,228	36,561
Second Lien
Long-term Debt, Gross				$ 430,000	479,000
Discount Rate for Estimated Future Net Revenues from Proved Properties				10.00%
Line of Credit [Member]
Bank Borrowings
Capitalized interest on our unproved properties				$ 0	200
New Credit Facility [Member]
Bank Borrowings
Debt Issuance Costs, Net				(1,400)	(3,100)
New Credit Facility [Member] | Line of Credit [Member]
Bank Borrowings
Long-Term Debt, excluding current maturities				230,000	279,000
Line of Credit, current borrowing base	$ 310,000	$ 330,000		310,000
Line of Credit Facility, Maximum Borrowing Capacity		$ 600,000
Line of Credit, Letters of Credit Issuable						$ 25,000
Line of Credit Facility, Commitment Fee Percentage		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	3.5	4
Line of Credit, Covenant, Current Ratio, Minimum		1
Interest expense including commitment fees and amortization of debt issuance costs relating to the credit facility				12,600	15,700
Commitment fees included in interest expense, net				400	700
New Credit Facility [Member] | Line of Credit [Member] | Minimum [Member] | Alternative Base Interest Rate [Member]
Bank Borrowings
Debt Instrument escalating basis spread on base rate		0.0175
Debt instrument escalating rates for eurodollar rate loans		0.0275
New Credit Facility [Member] | Line of Credit [Member] | Maximum [Member] | Alternative Base Interest Rate [Member]
Bank Borrowings
Debt Instrument escalating basis spread on base rate		0.0275
Debt instrument escalating rates for eurodollar rate loans		0.0375
Second Lien Notes [Member]
Bank Borrowings
Debt Issuance Costs, Net				(3,800)	(4,550)
Long-Term Debt, excluding current maturities			$ 198,000	200,000	200,000
Interest expense including commitment fees and amortization of debt issuance costs relating to the credit facility				18,600	21,100
Second Lien
Long-term Debt, Gross			200,000
Debt Instrument, Unamortized Discount			(2,000)	(1,295)	$ (1,550)
Additional notes issuable			$ 100,000
Additional interest in the event of default			0.020
Make whole premium during year 3			0.020
Make whole premium during year 4			0.010
Second Lien, Required Security Interest on Proved Reserves			85.00%
Second Lien, Required Security Interest on Oil and Gas Properties			85.00%
Discount Rate for Estimated Future Net Revenues for Proved Properties at 9%			9.00%
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				$ 194,900
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

Price-Risk Management Price-R_4

Price-Risk Management Price-Risk Management (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)bblMMBTU$ / MMBTU$ / Boe	Dec. 31, 2019USD ($)
Derivative [Line Items]
Gain (Loss) on Price Risk Derivatives, Net | $	$ 61,300	$ 24,200
Cash Received (Paid) On Settlements of Derivative Contracts | $	78,421	24,631
Cash Received (Paid) On Monetized Derivative Contracts | $	38,300
Receivables for Settled Derivatives | $	800	2,900
Payables for Settled Derivatives | $	800	200
Derivative, Fair Value, Net | $	(6,000)	8,400
Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	4,800	12,800
Other Noncurrent Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	300	3,900
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	8,200	6,600
Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	$ 2,900	$ 1,600
Swap [Member] | First Quarter 2021 [Member] | Oil Derivative [Member]
Derivative [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	143,538
Derivative, Swap Type, Average Fixed Price | $ / Boe	51.89
Swap [Member] | First Quarter 2021 [Member] | Natural Gas Derivative [Member]
Derivative [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	2,398,078
Derivative, Swap Type, Average Fixed Price	2.74
Swap [Member] | Second Quarter 2021 [Member] | Oil Derivative [Member]
Derivative [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	195,646
Derivative, Swap Type, Average Fixed Price | $ / Boe	51.93
Swap [Member] | Second Quarter 2021 [Member] | Natural Gas Derivative [Member]
Derivative [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	832,255
Derivative, Swap Type, Average Fixed Price	2.42
Swap [Member] | Third Quarter 2021 [Member] | Oil Derivative [Member]
Derivative [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	179,759
Derivative, Swap Type, Average Fixed Price | $ / Boe	51.19
Swap [Member] | Third Quarter 2021 [Member] | Natural Gas Derivative [Member]
Derivative [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	330,000
Derivative, Swap Type, Average Fixed Price	2.62
Swap [Member] | Fourth Quarter 2021 [Member] | Oil Derivative [Member]
Derivative [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	163,812
Derivative, Swap Type, Average Fixed Price | $ / Boe	52.39
Swap [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative [Member]
Derivative [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	290,000
Derivative, Swap Type, Average Fixed Price	2.69
Swap [Member] | First Quarter 2022 | Oil Derivative [Member]
Derivative [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	88,455
Derivative, Swap Type, Average Fixed Price | $ / Boe	36.79
Swap [Member] | Third Quarter 2022 | Oil Derivative [Member]
Derivative [Line Items]
Portion of Future Oil and Gas Production Being Hedged | bbl	108,100
Derivative, Swap Type, Average Fixed Price | $ / Boe	41.58
Collar Contracts [Member] | First Quarter 2021 [Member] | Oil Derivative [Member]
Derivative [Line Items]
Derivative, Average Floor Price	34.15
Derivative, Average Cap Price	39.24
Derivative, Nonmonetary Notional Amount | MMBTU	155,475
Collar Contracts [Member] | First Quarter 2021 [Member] | Natural Gas Derivative [Member]
Derivative [Line Items]
Derivative, Average Floor Price	2.53
Derivative, Average Cap Price	3.33
Derivative, Nonmonetary Notional Amount | MMBTU	7,027,800
Collar Contracts [Member] | Second Quarter 2021 [Member] | Oil Derivative [Member]
Derivative [Line Items]
Derivative, Average Floor Price	34.33
Derivative, Average Cap Price	40.30
Derivative, Nonmonetary Notional Amount | MMBTU	116,980
Collar Contracts [Member] | Second Quarter 2021 [Member] | Natural Gas Derivative [Member]
Derivative [Line Items]
Derivative, Average Floor Price	2.26
Derivative, Average Cap Price	2.70
Derivative, Nonmonetary Notional Amount | MMBTU	5,911,000
Collar Contracts [Member] | Third Quarter 2021 [Member] | Oil Derivative [Member]
Derivative [Line Items]
Derivative, Average Floor Price	34.34
Derivative, Average Cap Price	39.87
Derivative, Nonmonetary Notional Amount | MMBTU	90,620
Collar Contracts [Member] | Third Quarter 2021 [Member] | Natural Gas Derivative [Member]
Derivative [Line Items]
Derivative, Average Floor Price	2.15
Derivative, Average Cap Price	2.70
Derivative, Nonmonetary Notional Amount | MMBTU	6,045,175
Collar Contracts [Member] | Fourth Quarter 2021 [Member] | Oil Derivative [Member]
Derivative [Line Items]
Derivative, Average Floor Price	34.70
Derivative, Average Cap Price	41.01
Derivative, Nonmonetary Notional Amount | MMBTU	84,640
Collar Contracts [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative [Member]
Derivative [Line Items]
Derivative, Average Floor Price	2.35
Derivative, Average Cap Price	2.76
Derivative, Nonmonetary Notional Amount | MMBTU	5,311,000
Collar Contracts [Member] | First Quarter 2022 | Oil Derivative [Member]
Derivative [Line Items]
Derivative, Average Floor Price	40
Derivative, Average Cap Price	45.55
Derivative, Nonmonetary Notional Amount | MMBTU	40,500
Collar Contracts [Member] | First Quarter 2022 | Natural Gas Derivative [Member]
Derivative [Line Items]
Derivative, Average Floor Price	2.50
Derivative, Average Cap Price	3.35
Derivative, Nonmonetary Notional Amount | MMBTU	4,415,000
Collar Contracts [Member] | Second Quarter 2022 | Oil Derivative [Member]
Derivative [Line Items]
Derivative, Average Floor Price	39.25
Derivative, Average Cap Price	46.20
Derivative, Nonmonetary Notional Amount | MMBTU	115,850
Collar Contracts [Member] | Second Quarter 2022 | Natural Gas Derivative [Member]
Derivative [Line Items]
Derivative, Average Floor Price	2.23
Derivative, Average Cap Price	2.70
Derivative, Nonmonetary Notional Amount | MMBTU	4,200,000
Collar Contracts [Member] | Third Quarter 2022 | Natural Gas Derivative [Member]
Derivative [Line Items]
Derivative, Average Floor Price	2.39
Derivative, Average Cap Price	2.74
Derivative, Nonmonetary Notional Amount | MMBTU	3,933,000
Basis Swap [Member] | First Quarter 2021 [Member] | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	9,900,000
Derivative, Swap Type, Average Fixed Price	(0.022)
Basis Swap [Member] | First Quarter 2021 [Member] | Oil Basis Derivative [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	1.19
Derivative, Nonmonetary Notional Amount | bbl	373,750
Basis Swap [Member] | First Quarter 2021 [Member] | Oil Basis Calendar Monthly Roll Differential Swap
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.40)
Derivative, Nonmonetary Notional Amount | bbl	367,000
Basis Swap [Member] | Second Quarter 2021 [Member] | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	10,010,000
Derivative, Swap Type, Average Fixed Price	(0.022)
Basis Swap [Member] | Second Quarter 2021 [Member] | Oil Basis Derivative [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	1.22
Derivative, Nonmonetary Notional Amount | bbl	329,150
Basis Swap [Member] | Second Quarter 2021 [Member] | Oil Basis Calendar Monthly Roll Differential Swap
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.37)
Derivative, Nonmonetary Notional Amount | bbl	313,900
Basis Swap [Member] | Third Quarter 2021 [Member] | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	10,120,000
Derivative, Swap Type, Average Fixed Price	(0.022)
Basis Swap [Member] | Third Quarter 2021 [Member] | Oil Basis Derivative [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	1.27
Derivative, Nonmonetary Notional Amount | bbl	262,200
Basis Swap [Member] | Third Quarter 2021 [Member] | Oil Basis Calendar Monthly Roll Differential Swap
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.34)
Derivative, Nonmonetary Notional Amount | bbl	253,000
Basis Swap [Member] | Fourth Quarter 2021 [Member] | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	10,120,000
Derivative, Swap Type, Average Fixed Price	(0.022)
Basis Swap [Member] | Fourth Quarter 2021 [Member] | Oil Basis Derivative [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	1.28
Derivative, Nonmonetary Notional Amount | bbl	241,500
Basis Swap [Member] | Fourth Quarter 2021 [Member] | Oil Basis Calendar Monthly Roll Differential Swap
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.33)
Derivative, Nonmonetary Notional Amount | bbl	241,500
Basis Swap [Member] | First Quarter 2022 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	1,800,000
Derivative, Swap Type, Average Fixed Price	(0.080)
Basis Swap [Member] | First Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.12)
Derivative, Nonmonetary Notional Amount | bbl	90,000
Basis Swap [Member] | Second Quarter 2022 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	1,820,000
Derivative, Swap Type, Average Fixed Price	(0.080)
Basis Swap [Member] | Second Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.12)
Derivative, Nonmonetary Notional Amount | bbl	91,000
Basis Swap [Member] | Third Quarter 2022 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	1,840,000
Derivative, Swap Type, Average Fixed Price	(0.080)
Basis Swap [Member] | Third Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.12)
Derivative, Nonmonetary Notional Amount | bbl	92,000
Basis Swap [Member] | Fourth Quarter 2022 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Future Gas Production Hedged in MMBtu (Energy Item Type) | MMBTU	1,840,000
Derivative, Swap Type, Average Fixed Price	(0.080)
Basis Swap [Member] | Fourth Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.12)
Derivative, Nonmonetary Notional Amount | bbl	92,000

Commitments and Contingencies (

Commitments and Contingencies (Details Textual) - Gas transportation and processing obligations [Member] $ in Millions	Dec. 31, 2020USD ($)
Obligations (Textual)
Contractual Obligation, Due in Next Fiscal Year	$ 5.2
Contractual Obligation, Due in Second Year	3.9
Contractual Obligation, Due in Third Year	2.6
Contractual Obligation, Due in Fourth Year	1.6
Contractual Obligation, Due in Fifth Year	1.1
Contractual Obligation	$ 14.4

Share-Based Compensation (Detai

Share-Based Compensation (Details 1) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Restricted Stock Units (RSUs) [Member]
Restricted stock activity
Restricted units outstanding	574,916	342,683
Restricted units outstanding, weighted average price	$ 9.02	$ 22.10
Restricted stock units granted	397,285
Restricted stock units granted, weighted average price	$ 2.83
Restricted stock units forfeited	(6,326)
Restricted stock units forfeited, weighted average price	$ 19.46
Restricted stock units vested	(158,726)
Restricted stock units vested, weighted average price	$ 21.38
Share-based Payment Arrangement, Option [Member]
Stock option activity in shares and weighted average price
Options outstanding, beginning of period, shares	324,324
Options outstanding, beginning of period, weighted average price	$ 27.68
Options expired	(20,619)
Options expired, weighted average price	$ 26.96
Options outstanding, end of period, shares	303,705
Options outstanding, end of period, weighted average price	$ 27.73
Options exercisable, end of period, shares	206,179
Options exercisable, end of period, weighted average price	$ 28.41

Share-Based Compensation (Det_2

Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands	Dec. 31, 2020	May 21, 2019	Feb. 20, 2018	Dec. 31, 2020	Dec. 31, 2019	Apr. 02, 2019
Stock-Based Compensation Plan
Share-based compensation expenses				$ 4,557	$ 6,148
Share-based Payment Arrangement, Amount Capitalized				$ 200	500
Shares available for future grant under stock compensation plans	726,723			726,723
Employee Savings Plan [Abstract]
Employee Savings Plan, Employer Matching Contribution, Percent				100.00%
Employee Savings Plan, Maximum Annual Contribution Per Employee, Percent				6.00%
Employee Savings Plan, Employer Discretionary Contribution Amount				$ 600	600
General and Administrative Expense [Member]
Stock-Based Compensation Plan
Share-based compensation expenses				4,600	$ 6,100
Share-based Payment Arrangement, Option - Equity Exchange Award [Member]
Stock Option Awards
Unrecognized compensation cost related to stock awards						$ 1,200
Share-based Payment Arrangement, Option [Member]
Stock Option Awards
Unrecognized compensation cost related to stock awards	$ 600			600
Outstanding stock options aggregate intrinsic value	0			$ 0
Remaining contract life of outstanding stock options.				4 years 9 months 18 days
Remaining contract life of exercisable stock option				4 years
Intrinsic value of exercised stock option				$ 0
Restricted Stock Units (RSUs) [Member]
Stock-Based Compensation Plan
Equity Award Exchange Percentage of Award						50.00%
Stock Option Awards
Unrecognized compensation cost related to stock awards	2,400			$ 2,400
Restricted Stock Units [Abstract]
Weighted average recognition period of cost related to stock awards				1 year 1 month 6 days
Performance Share Units [Abstract]
Restricted stock units granted				397,285
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value				$ 2.83
Restricted stock units vested				158,726
Performance-based stock unit [Member]
Stock-Based Compensation Plan
Equity Award Exchange Percentage of Award						50.00%
Stock Option Awards
Unrecognized compensation cost related to stock awards	$ 1,000			$ 1,000
Restricted Stock Units [Abstract]
Weighted average recognition period of cost related to stock awards	1 year
Performance Share Units [Abstract]
Restricted stock units granted		99,500	30,700
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 18.86	$ 41.66
Percent of payout for performance based stock units	100.00%	112.90%	150.61%	100.00%
Restricted stock units vested				0
Minimum Payout [Member] | Share-based Payment Arrangement, Option [Member]
Restricted Stock Units [Abstract]
Vesting period				1 year
Minimum Payout [Member] | Restricted Stock Units (RSUs) [Member]
Restricted Stock Units [Abstract]
Vesting period				1 year
Minimum Payout [Member] | Performance-based stock unit [Member]
Performance Share Units [Abstract]
Percent of payout for performance based stock units		0.00%	0.00%
Maximum Payout [Member] | Share-based Payment Arrangement, Option [Member]
Restricted Stock Units [Abstract]
Vesting period				5 years
Maximum Payout [Member] | Restricted Stock Units (RSUs) [Member]
Restricted Stock Units [Abstract]
Vesting period				5 years
Maximum Payout [Member] | Performance-based stock unit [Member]
Performance Share Units [Abstract]
Percent of payout for performance based stock units		200.00%	200.00%
Performance Period for Award				3 years

Leases Leases (Details)

Leases Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2017
Lessee, Lease, Description [Line Items]
Lease, Cost	$ 7,083	$ 6,697
Operating Lease, Weighted Average Remaining Lease Term	1 year 10 months 24 days
Operating Lease, Weighted Average Discount Rate, Percent	4.50%
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	$ 3,573
Lessee, Operating Lease, Liability, Payments, Due Year Two	542
Lessee, Operating Lease, Liability, Payments, Due Year Three	166
Lessee, Operating Lease, Liability, Payments, Due Year Four	38
Lessee, Operating Lease, Liability, Payments, Due Year Five	39
Lessee, Operating Lease, Liability, Payments, Due after Year Five	287
Lessee, Operating Lease, Liability, Payments, Due	4,645
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(221)
Operating Lease, Liability	4,424
Operating Lease, Payments	6,352	4,609
Operating Lease, Payments, Use	10	41
Operating Leases, Rent Expense	5,800	5,400
Building [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract			4 years
Operating Leases, Future Minimum Payments Due	300
General and Administrative Expense [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	704	681
Lease Operating Expense [Member]
Lessee, Lease, Description [Line Items]
Short-term Lease, Cost	724	2,071
Operating Lease, Cost	5,655	3,945
Property, Plant and Equipment [Member]
Lessee, Lease, Description [Line Items]
Short-term Lease, Cost	3,774	10,573
Operating Lease, Cost	10	41
Lease, Cost	$ 3,784	$ 10,614

Acquisitions and Dispositions (

Acquisitions and Dispositions (Details) - USD ($) $ in Thousands	May 13, 2020	Apr. 03, 2020	Dec. 31, 2020	Dec. 31, 2019	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			$ 826	$ 5,112
Payments to Acquire Oil and Gas Property			4,544	$ 0
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			$ 1,600
Eagle Ford Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments to Acquire Oil and Gas Property		$ 5,000
Wyoming Disposition
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	$ 4,800

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Fair Value, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Natural Gas Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	$ 1.5	$ 11.7
Derivative Liability	4	0.2
Natural Gas Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	1.1	3.4
Derivative Liability	0.4	0.9
Oil Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	2.5	1.6
Derivative Liability	5.9	7
Oil Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Liability	0.8	0.1
Fair Value, Inputs, Level 1 [Member] | Natural Gas Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Oil Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Oil Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Liability	0	0
Fair Value, Inputs, Level 2 [Member] | Natural Gas Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	1.5	11.7
Derivative Liability	4	0.2
Fair Value, Inputs, Level 2 [Member] | Natural Gas Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	1.1	3.4
Derivative Liability	0.4	0.9
Fair Value, Inputs, Level 2 [Member] | Oil Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	2.5	1.6
Derivative Liability	5.9	7
Fair Value, Inputs, Level 2 [Member] | Oil Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Liability	0.8	0.1
Fair Value, Inputs, Level 3 [Member] | Natural Gas Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Oil Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Oil Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Liability	$ 0	$ 0

Asset Retirement Obligations _4

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	$ 4,974	$ 4,447	$ 4,259
Accretion expense	354	329
Liabilities incurred for new wells and facilities construction	281	250
Asset Retirement Obligation, Liabilities Plugged	(103)	(82)
Revisions in estimates	(5)	(309)
Asset retirement obligation - current portion	$ 441	$ 392

Uncategorized Items - sbow-2020

Label	Element	Value
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	us-gaap_CashCashEquivalentsRestrictedCashAndRestrictedCashEquivalents	$ 2,465,000