Contango Oil & Gas (MCF) 10-K 10 Mar 21 2020 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Mar. 05, 2021	Jun. 30, 2020
Document And Entity Information
Document Type	10-K
Document Period End Date	Dec. 31, 2020
Entity Registrant Name	CONTANGO OIL & GAS CO
Title of 12(b) Security	Common Stock
Trading Symbol	MCF
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 Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 159.2
Entity Common Stock, Shares Outstanding		199,146,980
Entity Central Index Key	0001071993
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Amendment Flag	false

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
CURRENT ASSETS:
Cash and cash equivalents	$ 1,383	$ 1,624
Accounts receivable, net	37,862	39,567
Prepaid expenses	3,360	1,191
Current derivative asset	2,996	3,819
Inventory	442	186
Deposits and other	763
Total current assets	46,806	46,387
Oil and natural gas properties, successful efforts method of accounting:
Proved properties	1,274,508	1,306,916
Unproved properties	16,201	27,619
Other property and equipment	1,669	1,655
Accumulated depreciation, depletion, amortization and impairment	(1,190,475)	(1,045,070)
Total property, plant and equipment, net	101,903	291,120
OTHER NON-CURRENT ASSETS:
Investments in affiliates	6,793	6,766
Long-term derivative asset	497	357
Right-of-use lease assets	5,448	5,885
Debt issuance costs	1,782	3,311
Deposits	7,038
Total other non-current assets	21,558	16,319
TOTAL ASSETS	170,267	353,826
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	83,970	104,593
Current derivative liability	1,317	3,951
Current asset retirement obligations	4,249	2,003
Total current liabilities	89,536	110,547
NON-CURRENT LIABILITIES:
Long-term debt	12,369	72,768
Long-term derivative liability	1,648	2,020
Asset retirement obligations	48,523	49,662
Lease liabilities	2,624	2,789
Total non-current liabilities	65,164	127,239
Total liabilities	154,700	237,786
COMMITMENTS AND CONTINGENCIES (NOTE 14)
SHAREHOLDERS’ EQUITY
Series C convertible preferred stock, $0.04 par value, no shares authorized, issued and outstanding at December 31, 2020 and 2,700,000 shares authorized, issued and outstanding at December 31, 2019		108
Common stock, $0.04 par value, 400 million shares authorized, 173,848,674 shares issued and 173,756,100 shares outstanding at December 31, 2020, 128,985,146 shares issued and 128,977,816 shares outstanding at December 31, 2019	6,941	5,148
Additional paid-in capital	535,192	471,778
Treasury shares at cost (92,574 shares at December 31, 2020 and 7,330 shares at December 31, 2019)	(248)	(18)
Accumulated deficit	(526,318)	(360,976)
Total shareholders’ equity	15,567	116,040
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$ 170,267	$ 353,826

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2020	Dec. 31, 2019
CONSOLIDATED BALANCE SHEETS
Preferred stock, par value (in dollars per share)	$ 0.04	$ 0.04
Preferred stock, shares authorized	0	2,700,000
Preferred stock, shares issued	0	2,700,000
Preferred stock, shares outstanding	0	2,700,000
Common stock, par value (in dollars per share)	$ 0.04	$ 0.04
Common stock, shares authorized	400,000,000	200,000,000
Common stock, shares issued	173,830,390	128,985,146
Common stock, shares outstanding	173,737,816	128,977,816
Treasury stock, shares	92,574	7,330

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
REVENUES:
Revenues	$ 112,920	$ 76,512
EXPENSES:
Operating expenses	72,847	33,205
Exploration expenses	11,594	1,003
Depreciation, depletion and amortization	30,032	39,807
Impairment & abandonment of oil and natural gas properties	168,802	128,290
General and administrative expenses	24,940	24,938
Total expenses	308,215	227,243
OTHER INCOME (EXPENSE):
Gain (loss) from investment in affiliates (net of income taxes)	27	742
Gain from sale of assets	4,501	518
Interest expense	(5,022)	(8,596)
Gain (loss) on derivatives, net	27,585	(3,357)
Other income	3,609	1,848
Total other income	30,700	(8,845)
NET LOSS BEFORE INCOME TAXES	(164,595)	(159,576)
Income tax provision	(747)	(220)
NET LOSS ATTRIBUTABLE TO COMMON STOCK	$ (165,342)	$ (159,796)
NET LOSS PER SHARE:
Basic	$ (1.20)	$ (2.95)
Diluted	$ (1.20)	$ (2.95)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic	137,522	54,136
Diluted	137,522	54,136
Oil and condensate sales [Member]
REVENUES:
Revenues	$ 62,461	$ 44,705
Natural gas sales [Member]
REVENUES:
Revenues	31,381	22,380
Natural gas liquids sales [Member]
REVENUES:
Revenues	17,078	$ 9,427
Fee for service revenues [Member]
REVENUES:
Revenues	$ 2,000

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 loss	$ (165,342)	$ (159,796)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	30,032	39,807
Impairment of oil and natural gas properties	168,732	126,964
Exploration expenditures - dry hole costs	10,455
Amortization of debt issuance costs	1,603	144
Deferred income taxes		424
Gain on sale of assets	(4,501)	(518)
Gain from investment in affiliates	(27)	(742)
Stock-based compensation	4,270	2,352
Unrealized loss (gain) on derivative instruments	(2,321)	5,973
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable & other	1,463	(9,903)
Decrease (increase) in prepaid expenses	(2,169)	451
Increase in inventory	(256)
Increase (decrease) in accounts payable & advances from joint owners	(6,279)	10,739
Increase (decrease) in other accrued liabilities	(7,477)	13,019
Decrease (increase) in income taxes receivable, net	281	(85)
Increase (decrease) in income taxes payable, net	233	(153)
Deposits and other	(7,801)	(6,966)
Net cash provided by operating activities	20,896	21,710
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil & natural gas exploration & development expenditures	(21,689)	(42,737)
Acquisition of oil & natural gas properties		(112,075)
Additions to furniture & equipment	(13)	(53)
Sale of oil and natural gas properties	349	10
Net cash used in investing activities	(21,353)	(154,855)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Credit Agreement	79,700	256,923
Repayments under Credit Agreement	(143,468)	(244,154)
Payroll Protection Program Loan	3,369
Net proceeds from equity offerings	60,919	125,710
Purchase of treasury stock	(230)	(255)
Debt issuance costs	(74)	(3,455)
Net cash provided by financing activities	216	134,769
NET CHANGE IN CASH AND CASH EQUIVALENTS	(241)	1,624
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	1,624	0
CASH AND CASH EQUIVALENTS, END OF PERIOD	$ 1,383	$ 1,624

CONSOLIDATED STATEMENT OF SHARE

CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands	Preferred Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Accumulated Deficit [Member]	Total
Balance at Dec. 31, 2018		$ 1,573	$ 339,981	$ (129,030)	$ (72,135)	$ 140,389
Balance, shares at Dec. 31, 2018		34,158,492
Equity offering-common stock			(86)			(86)
Treasury shares at cost				(186)		(186)
Treasury shares at cost, shares		(49,415)
Restricted shares activity		$ 12	(12)
Restricted shares activity, shares		307,650
Stock-based compensation			1,052			1,052
Net loss					(8,618)	(8,618)
Balance at Mar. 31, 2019		$ 1,585	340,935	(129,216)	(80,753)	132,551
Balance, shares at Mar. 31, 2019		34,416,727
Balance at Dec. 31, 2018		$ 1,573	339,981	(129,030)	(72,135)	140,389
Balance, shares at Dec. 31, 2018		34,158,492
Net loss						(159,796)
Balance at Dec. 31, 2019	$ 108	$ 5,148	471,778	(18)	(360,976)	$ 116,040
Balance, shares at Dec. 31, 2019	2,700,000	128,977,816				128,977,816
Balance at Mar. 31, 2019		$ 1,585	340,935	(129,216)	(80,753)	$ 132,551
Balance, shares at Mar. 31, 2019		34,416,727
Equity offering-common stock			45			45
Treasury shares at cost				(50)		(50)
Treasury shares at cost, shares		(16,133)
Restricted shares activity		$ 2	(2)
Restricted shares activity, shares		42,249
Stock-based compensation			585			585
Net loss					(4,961)	(4,961)
Balance at Jun. 30, 2019		$ 1,587	341,563	(129,266)	(85,714)	128,170
Balance, shares at Jun. 30, 2019		34,442,843
Equity offering-preferred stock	$ 32		7,420			7,452
Equity offering-preferred stock, shares	789,474
Equity offering-common stock		$ 2,058	44,181			46,239
Equity offering-common stock, shares		45,922,870
Treasury shares at cost		$ (221)		129,266	(129,045)
Treasury shares at cost, shares		5,524,498
Treasury shares reissuance		$ (1)	1
Treasury shares reissuance, shares		(25,748)
Stock-based compensation			558			558
Net loss					(7,838)	(7,838)
Balance at Sep. 30, 2019	$ 32	$ 3,423	393,723		(222,597)	174,581
Balance, shares at Sep. 30, 2019	789,474	85,864,463
Equity offering-preferred stock	$ 152		26,154			26,306
Equity offering-preferred stock, shares	3,802,838
Equity offering-common stock		$ 760	44,942			45,702
Equity offering-common stock, shares		19,000,000
Conversion of preferred stock to common stock	$ (76)	$ 757	(629)			52
Conversion of preferred stock to common stock, shares	(1,892,312)	18,923,120
Treasury shares at cost				(18)		(18)
Treasury shares at cost, shares		(7,330)
Restricted shares activity		$ (1)	1
Restricted shares activity, shares		(27,437)
Stock-based compensation			158			158
Will Energy and Juneau acquisitions		$ 209	7,429			7,638
Contango common stock to be issued to Mid-Con unitholders (in shares)		5,225,000
Net loss					(138,379)	(138,379)
Balance at Dec. 31, 2019	$ 108	$ 5,148	471,778	(18)	(360,976)	$ 116,040
Balance, shares at Dec. 31, 2019	2,700,000	128,977,816				128,977,816
Equity offering-common stock			(47)			$ (47)
Treasury shares at cost				(157)		(157)
Treasury shares at cost, shares		(49,474)
Restricted shares activity		$ 3	(3)
Restricted shares activity, shares		77,485
Stock-based compensation			350			350
Net loss					(105,255)	(105,255)
Balance at Mar. 31, 2020	$ 108	$ 5,151	472,078	(175)	(466,231)	10,931
Balance, shares at Mar. 31, 2020	2,700,000	129,005,827
Balance at Dec. 31, 2019	$ 108	$ 5,148	471,778	(18)	(360,976)	$ 116,040
Balance, shares at Dec. 31, 2019	2,700,000	128,977,816				128,977,816
Net loss						$ (165,342)
Balance at Dec. 31, 2020		$ 6,941	535,192	(248)	(526,318)	$ 15,567
Balance, shares at Dec. 31, 2020		173,737,816				173,737,816
Balance at Mar. 31, 2020	$ 108	$ 5,151	472,078	(175)	(466,231)	$ 10,931
Balance, shares at Mar. 31, 2020	2,700,000	129,005,827
Equity offering-common stock		$ 6	477			483
Equity offering-common stock, shares		155,029
Conversion of preferred stock to common stock	$ (108)	$ 108
Conversion of preferred stock to common stock, shares	(2,700,000)	2,700,000
Treasury shares at cost				(23)		(23)
Treasury shares at cost, shares		(13,808)
Restricted shares activity		$ 6	(6)
Restricted shares activity, shares		149,709
Stock-based compensation			265			265
Net loss					(28,034)	(28,034)
Balance at Jun. 30, 2020		$ 5,271	472,814	(198)	(494,265)	(16,378)
Balance, shares at Jun. 30, 2020		131,996,757
Equity offering-common stock			(27)			(27)
Equity offering-common stock, shares		8,900
Treasury shares at cost				(8)		(8)
Treasury shares at cost, shares		(3,678)
Restricted shares activity		$ 41	(41)
Restricted shares activity, shares		1,011,699
Stock-based compensation			1,764			1,764
Net loss					(6,805)	(6,805)
Balance at Sep. 30, 2020		$ 5,312	474,510	(206)	(501,070)	(21,454)
Balance, shares at Sep. 30, 2020		133,013,678
Equity offering-common stock		$ 1,626	58,883			60,509
Equity offering-common stock, shares		40,645,891
Treasury shares at cost				(42)		(42)
Treasury shares at cost, shares		(18,284)
Restricted shares activity		$ 3	(3)
Restricted shares activity, shares		96,531
Stock-based compensation			1,802			1,802
Net loss					(25,248)	(25,248)
Balance at Dec. 31, 2020		$ 6,941	$ 535,192	$ (248)	$ (526,318)	$ 15,567
Balance, shares at Dec. 31, 2020		173,737,816				173,737,816

Organization and Business

Organization and Business	12 Months Ended
	Dec. 31, 2020
Organization And Business [Abstract]
Organization and Business	CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Organization and Business Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Fort Worth, Texas based independent oil and natural gas company. The Company’s business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties primarily located in Oklahoma, Texas, Wyoming and Louisiana and use that cash flow to explore, develop and acquire oil and natural gas properties across the United States. The following table lists the Company’s primary producing areas as of December 31, 2020: Location Formation Offshore Gulf of Mexico Offshore Louisiana - water depths less than 300 feet Central Oklahoma Mississippian, Woodford, Oswego, Cottage Grove, Chester, Cleveland and Red Fork Western Anadarko Tonkawa, Cottage Grove, Cleveland, Marmaton, Chase Sandstone, Morrow, Chester and Oswego West Texas Wolfcamp A and B Other Onshore (TX, LA, WY) Woodbine, Lewisville, Buda, Georgetown, Eagleford, and Muddy Sandstone Impact of the COVID-19 Pandemic A novel strain of the coronavirus (“COVID-19”) surfaced in late 2019 and has spread, and continues to spread, around the world, including to the United States. In March 2020, the World Health Organization declared COVID-19 a pandemic, and the President of the United States declared the COVID-19 pandemic a national emergency. The COVID-19 pandemic has significantly affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the COVID-19 pandemic has resulted in travel restrictions, business closures and other restrictions that have disrupted the demand for oil throughout the world and, when combined with the oil supply increase attributable to the battle for market share among the Organization of Petroleum Exporting Countries (“OPEC”), Russia and other oil producing nations, resulted in oil prices declining significantly beginning in late February 2020. While there has been a modest recovery in oil prices, the length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global oil demand, which negatively impacted the Company’s results of operations and planned 2020 capital activities. Due to the extreme volatility in oil prices and the impact of COVID-19 on the financial condition of our upstream peers, the Company suspended its drilling program in the Southern Delaware Basin in the first quarter of 2020 and focused on certain measures that included, but were not limited to, the following: · work from home initiatives for all but critical staff and the implementation of social distancing measures; · a company-wide effort to cut costs throughout the Company’s operations; · utilization of the Company’s available storage capacity to temporarily store a portion of its production for later sale at higher prices when advantageous to do so (such as the approximate 50,000 barrels of second quarter oil production we stored and sold during the third quarter of 2020 at higher oil prices); · suspension of any further plans for operated onshore and offshore drilling in 2020; · pursuit of additional “fee for service” opportunities similar to the Management Services Agreement entered into in June 2020 with Mid-Con Energy Partners, LP (“Mid-Con”) (NASDAQ:MCEP), which was terminated at the closing of the Mid-Con Acquisition (as defined below) between the Company and Mid-Con on January 21, 2021); and · potential acquisitions of PDP-heavy assets, with attractive, discounted valuations, in stressed/distressed scenarios or from non-industry owners, such as the Silvertip Acquisition (as defined below). From the Company’s initial entry into the Southern Delaware Basin in 2016 and through early 2019, the Company was focused on the development of its initial 6,500 net acre position in Pecos County, Texas (“Bullseye”), and in December 2018, the Company purchased an additional 4,200 gross operated (1,700 net) acres and 4,000 gross non-operated (200 net) acres to the northeast of its existing acreage (“NE Bullseye”). Contango’s 2019 drilling program included the completion of one well previously drilled in the Bullseye area, the drilling and completion of a second Bullseye well, and the drilling and completion of three wells in the NE Bullseye area. In December 2019, the Company began completion operations on its fourth NE Bullseye well, which began producing in January 2020, and then suspended further drilling in the area in response to the dramatic decline in oil prices. As of December 31, 2020, the Company was producing from 18 wells over its approximate 16,200 gross operated (7,500 company net) acre position in West Texas, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations. In September 2019, the Company entered into unrelated purchase agreements with Will Energy Corporation (“Will Energy”) and White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”) to purchase certain producing assets and undeveloped acreage, primarily in Oklahoma. These transactions closed during the three months ended December 31, 2019, (the “Will Energy Acquisition” and “White Star Acquisition”) and were transformative, as production from these acquisitions represented approximately 70% of the Company’s total net production for the year ended December 31, 2020. See Note 4 – “Acquisitions and Dispositions” for more information. In conjunction with the White Star Acquisition, the Company entered into a new revolving credit agreement with JPMorgan Chase Bank, N.A. and other lenders (the “Credit Agreement”). In connection with the entry into the Credit Agreement, the Company repaid all obligations outstanding on, and terminated, its previous credit agreement with Royal Bank of Canada, which matured on October 1, 2019. The Credit Agreement has since been amended to increase the number of lenders from three to nine, and among other things, to adjust the borrowing base to $130.0 million on January 21, 2021 and $120.0 million on March 31, 2021. See Note 13 – “Long-Term Debt” for more information. The Company completed two stock offerings in the third quarter of 2019. The Company completed an underwritten public offering (the “September 2019 Public Offering”) of 51,447,368 shares of common stock (of which 5,524,498 were reissued treasury shares) for net proceeds of approximately $46.2 million, after deducting the underwriting discount and fees and expenses. Net proceeds from the September 2019 Public Offering were used to fund the cash portion of the purchase price for the Will Energy Acquisition and to repay borrowings outstanding under the Company’s former revolving credit facility to provide incremental liquidity to support the Company’s planned acquisition efforts. In conjunction with the September 2019 Public Offering, the Company also entered into a purchase agreement with affiliates of John C. Goff, a director and significant shareholder, and current chairman of the Company, to issue and sell in a private placement (the “Series A Private Placement”) 789,474 shares of Series A contingent convertible preferred stock, which resulted in net proceeds of approximately $7.5 million. The Company completed two additional stock offerings in the fourth quarter of 2019. In connection with the closing of the White Star Acquisition i n November 2019, the Company completed a private placement of 1,102,838 shares of Series B contingent convertible preferred stock of the Company, which resulted in net proceeds of approximately $21.0 million (the “Series B Private Placement”). Net proceeds from the Series A Private Placement were used to fund a portion of the purchase price and related transaction expenses for the Will Energy Acquisition, and net proceeds from the Series B Private Placement were used to fund a portion of the purchase price and related transaction expenses for the White Star Acquisition. In December 2019, the Company also completed a private placement of 19,000,000 shares of common stock for net proceeds of approximately $45.7 million, after deducting the underwriting discount and fees and expenses (the “December 2019 Offering”). In conjunction with the December 2019 Offering, the Company also completed a private placement of 2,340,000 shares of Series C contingent convertible preferred stock (the “Series C Private Placement”) with affiliates of Mr. Goff, Wilkie S. Colyer, Jr., the Company’s chief executive officer, and others, which resulted in net proceeds of approximately $5.6 million. An additional 360,000 Series C contingent convertible preferred shares were issued in a private placement to the placement agents for the December 2019 Offering and Series C Private Placement, as partial consideration for their services in those offerings. Net proceeds from the December 2019 Offering and Series C Private Placement were used for general corporate purposes, including capital expenditures under the Company’s Joint Development Agreement with Juneau Oil & Gas, LLC (discussed below). In December 2019, the Company obtained approval from the holders of a majority of the voting power of the Company’s capital stock to increase the number of common shares authorized for issuance from 100,000,000 to 200,000,000 common shares, at which time the Series A preferred shares automatically converted into 7,894,740 shares of common stock, the Series B preferred shares automatically converted into 11,028,380 shares of common stock, and the outstanding preferred shares were cancelled. In December 2019, the Company entered into a Joint Development Agreement with Juneau Oil & Gas, LLC (“Juneau”), which provides the Company the right to acquire an interest in up to six of Juneau’s exploratory prospects located in the Gulf of Mexico. The first such exploratory prospect acquired by the Company, located in the Grand Isle Block 45 Area in the shallow waters off of the Louisiana coastline, was determined to be unsuccessful in June 2020. The Company is currently evaluating for future testing a number of exploratory prospects included in the Joint Development Agreement, including its Boss Hogg prospect located in the Eugene Island 298 Area in the shallow waters off of the Louisiana coastline. The Company’s strategy and timing on the testing of the Boss Hogg will be determined during the year based on regulatory considerations, some of which are fluid at this time, and on operational considerations, including the availability of appropriate equipment. Following the reduction in the Company’s drilling program in the latter half of 2019, which then led to the suspension of onshore drilling in the first quarter of 2020, the Company continued to identify opportunities for cost reductions and operating efficiencies in all areas of its operations, while also searching for new resource acquisition opportunities. Acquisition efforts have been, and will continue to be, focused on PDP-heavy assets where the Company might also be able to leverage its geological and operational experience and expertise to reduce operating expenses, enhance production and identify and develop additional drilling opportunities that the Company believes will enable it to economically grow production and add reserves. On June 5, 2020, the Company announced the addition of a new corporate business line that includes offering a property management service (or a “fee for service”) for oil and natural gas companies with distressed or stranded assets, or companies with a desire to reduce administrative costs by engaging a contract operator of its oil and natural gas assets. As part of this service offering, the Company entered into a Management Services Agreement (“MSA”) with Mid-Con, effective July 1, 2020, to provide services as contract operator of record on Mid-Con’s oil and natural gas properties, along with certain administrative and management services, in exchange for an annual services fee of $4 million, paid ratably over the twelve month period, plus reimbursement of certain costs and expenses, a deferred fee of $166,666 per month for each month that the agreement is in effect (not to exceed $2 million), to be paid in a lump sum upon termination of the agreement, and warrants to purchase a minority equity ownership in Mid-Con. In connection with the Company’s acquisition of Mid-Con on January 21, 2021, the MSA was terminated, the deferred fee obligation was forgiven, and the warrants were cancelled. See Note 4 – “Acquisitions and Dispositions” for more information. The Company recorded $2.0 million in revenue during the year ended December 31, 2020 related to this MSA with Mid-Con, which is included in “Fee for services revenue” in the Company’s consolidated statements of operations. On June 8, 2020, the stockholders of the Company, at the Company’s 2020 Annual Meeting of Stockholders, approved an amendment (the “Charter Amendment”) to its Amended and Restated Certificate of Formation with the Secretary of State of the State of Texas to increase the number of authorized shares of common stock, par value of $0.04 per share, of the Company from 200,000,000 shares to 400,000,000 shares, and also approved the conversion of the 2,700,000 shares of the Series C contingent convertible preferred stock, par value $0.04 per share, into 2,700,000 shares of the Company’s common stock. On June 10, 2020, the Company filed the Charter Amendment with the Secretary of State of the State of Texas. On June 24, 2020, the Company entered into an Open Market Sale Agreement (the “Sale Agreement”) among the Company and Jefferies LLC (the “Sales Agent”). Pursuant to the terms of the Sale Agreement, the Company may sell, from time to time through the Sales Agent in the open market, subject to satisfaction of certain conditions, shares of the Company’s common stock, having an aggregate public offering price of up to $100,000,000 (the “Shares”) (the “ATM Program”). The Company intends to use the net proceeds from any sales through the ATM Program, after deducting the Sales Agent’s commission and the Company’s offering expenses, to repay borrowings under its Credit Agreement and for general corporate purposes, including, but not limited to, acquisitions and exploratory drilling. Under the ATM Program, the Company sold 163,929 shares during the year ended December 31, 2020 for net proceeds of $0.5 million. On October 25, 2020, the Company and Mid-Con entered into an agreement and plan of merger providing for the acquisition by the Company of Mid-Con in an all-stock merger transaction in which Mid-Con would become a direct, wholly owned subsidiary of Contango (the “Mid-Con Acquisition”). On October 30, 2020, the Company entered into the Third Amendment (the “Third Amendment”) to its Credit Agreement under which, among other things, would increase the Company’s borrowing base from $75 million to $130.0 million, effective upon the closing of the Mid-Con Acquisition, with an automatic $10.0 million reduction in the borrowing base on March 31, 2021. The Mid-Con acquisition closed on January 21, 2021, with a total of 25,409,164 shares of Contango common stock issued. Upon closing of the Mid-Con Acquisition, the MSA was terminated, and the Company’s borrowing base was increased to $130.0 million. See Note 4 – “Acquisitions and Dispositions” and Note 13 – “Long-Term Debt” for further details. Concurrently with the announcement of the Mid-Con Acquisition, the Company announced the execution of an agreement with a select group of institutional and accredited investors to sell 26,451,988 shares of common stock, which was completed on October 27, 2020. After deducting the underwriting discount and fees and expenses, the net proceeds were approximately $38.8 million, which were used for the Mid-Con Acquisition and for general corporate purposes, including the repayment of debt outstanding under the Company’s Credit Agreement. On November 27, 2020, the Company entered into a purchase and sale agreement (the “Purchase Agreement”) with an undisclosed seller to acquire certain oil and natural gas properties located in the Big Horn Basin in Wyoming and Montana, in the Powder River Basin in Wyoming and in the Permian Basin in Texas and New Mexico (collectively the “Silvertip Acquisition”) for aggregate consideration of approximately $58 million. In connection with the execution of the Purchase Agreement, the Company paid $7.0 million as a deposit for its obligations under the Purchase Agreement, which is included in the consolidated balance sheet as of December 31, 2020. The Silvertip Acquisition closed on February 1, 2021, for a net consideration of approximately $53.2 million (including the $7.0 million deposit previously paid), after customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date. See Note 4 – “Acquisitions and Dispositions” for more information. On December 1, 2020, the Company completed another private placement of 14,193,903 shares of common stock for net proceeds of approximately $21.7 million, after deducting the underwriting discount and fees and expenses. The n et proceeds were used to fund the Silvertip Acquisition and for general corporate purposes, including the repayment of debt outstanding under the Company’s Credit Agreement.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
Summary Of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	2. Summary of Significant Accounting Policies Basis of Presentation The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly-owned subsidiaries are consolidated. Other Investments The Company has two seats on the board of directors of Exaro and has significant influence, but not control, over the company. As a result, the Company’s 37% ownership in Exaro is accounted for using the equity method. Under the equity method, the Company’s proportionate share of Exaro's net income increases the balance of its investment in Exaro, while a net loss or payment of dividends decreases its investment. In the consolidated statements of operations, the Company’s proportionate share of Exaro's net income is reported as a single line-item in “Gain from investment in affiliates” (net of income taxes). Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Revenue Recognition Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Based upon the Company’s past experience with its current purchasers and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the past year or currently. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the Company’s gas at the inlet of the plant, and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. When sales volumes exceed the Company’s entitled share, a production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. Production imbalances have not had and currently do not have a material impact on the financial statements. Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company receives purchaser statements from the majority of its customers, but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice. The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the following month that payment is received. Any differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process. The Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment. Cash Equivalents Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of December 31, 2020, the Company had $1.4 million in cash and cash equivalents, after transferring cash balances at the end of each day to reduce outstanding debt under the Company’s revolving Credit Agreement to minimize debt service costs. Under the Company’s cash management system, checks issued but not yet presented to banks by the payee frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the consolidated balance sheets. At December 31, 2020, accounts payable included $2.9 million in outstanding checks that had not been presented for payment. At December 31, 2019, accounts payable included $6.1 million in outstanding checks that had not been presented for payment. Accounts Receivable The Company sells oil, natural gas and NGLs to a limited number of customers. In addition, the Company participates with other parties in the operation of oil and natural gas wells. Substantially all of the Company’s accounts receivables are due from either purchasers of oil, natural gas and NGLs or participants in oil and natural gas wells for which the Company serves as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions and other pertinent factors. Amounts deemed uncollectible are charged to the allowance. Accounts receivable allowance for doubtful accounts was $2.3 million and $1.0 million as of December 31, 2020 and 2019, respectively. At December 31, 2020 and 2019, the carrying value of the Company’s accounts receivable approximated fair value. Oil and Natural Gas Properties - Successful Efforts The Company follows the successful efforts method of accounting for its oil and natural gas activities. The Company’s application of the successful efforts method of accounting for its oil and natural gas exploration and production activities requires judgment as to whether particular wells are developmental or exploratory, since lease acquisition costs and all developmental costs are capitalized, whereas exploratory drilling costs are continuously capitalized until the results are determined. If proved reserves are not discovered, the drilling costs are expensed as exploration costs. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil or natural gas field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory. During the quarter ended June 30, 2020, the Company drilled an unsuccessful exploratory well in the Gulf of Mexico, resulting in a charge of $10.5 million for drilling and prospect costs included in “Exploration expenses” in the Company’s consolidated statements of operations for the year ended December 31, 2020. The evaluation of oil and natural gas leasehold acquisition costs included in unproved properties requires management’s judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions. Depreciation, depletion and amortization ("DD&A") is calculated on a field basis using the unit of production method. Lease acquisition costs are amortized over remaining total proved reserves, and capitalized drilling and development costs of producing oil and natural gas properties, including related support equipment and facilities net of salvage value, are amortized over estimated proved developed oil and natural gas reserves. Upon sale or retirement of properties, the cost and related accumulated DD&A are eliminated from the accounts, and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least annually. Revisions are accounted for prospectively as changes in accounting estimates. Other property and equipment are depreciated using the straight-line method over their estimated useful lives which range between three and 10 years. Impairment of Oil and Natural Gas Properties Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field-by-field basis to the unamortized capitalized cost of the assets in that field. If the estimated future undiscounted cash flows, based on the Company’s estimate of future reserves, oil and natural gas prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. Additionally, the Company may use appropriate market data to determine fair value. In the first quarter of 2020, the COVID-19 pandemic and the resulting deterioration in the global demand for oil, combined with the failure by OPEC and Russia to reach an agreement on lower production quotas until April 2020, caused a dramatic increase in the supply of oil, a corresponding decrease in commodity prices, and reduced the demand for all commodity products. The remainder of 2020 was further adversely affected by the continuation of the COVID-19 pandemic and the actions and measures that countries, states, localities, central banks, international financing and funding organizations, stock markets, businesses and individuals have taken to address the spread of the coronavirus and associated illnesses, the continued volatility of the oil and gas market, and the failure of OPEC and Russia to consistently and fully adhere to the quotas delineated in their agreement. Consequently, during the three months ended March 31, 2020, the Company recorded a $143.3 million non-cash charge for proved property impairment of its onshore properties related to the dramatic decline in commodity prices, the “PV-10” (present value, discounted at a 10% rate) of its proved reserves, and the associated change in its current development plans for its proved undeveloped locations. In the fourth quarter of 2020, the Company recorded an additional $21.1 million non-cash charge for proved property impairment, of which $15.6 million related to its offshore properties as a result of performance revisions in reserves and the decline in gas prices and production yield. The total non-cash proved property impairment recorded during the year ended December 31, 2020 was $164.4 million. For the year ended December 31, 2019, the Company recognized non-cash proved property impairment expense of $117.8 million due to reserve revisions which resulted from the negative impact of performance and price related revisions to the present value of the Company’s year-end proved reserves, and the relationship of that value to the historical carrying cost of its assets on the balance sheet. Included in the impairment charge was $34.5 million related to the Company’s proved offshore Gulf of Mexico properties, primarily a result of performance revisions associated with the re-evaluation of the projected field costs and recoverable condensate volumes. In addition, the Company recognized onshore proved property impairment expense of $83.3 million. The onshore impairment was due primarily to price and performance revisions, which led to the re-evaluation of the economics and future drilling plans for the proved undeveloped locations, which then resulted in the elimination of certain proved undeveloped locations due to the SEC’s five-year development rule for such locations. Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, with any such impairment charged to expense in the period. During the year ended December 31, 2020, the Company recorded a $4.3 million non-cash charge for unproved impairment expense related to undeveloped leases in its Central Oklahoma, Western Anadarko and Other Onshore regions. The Company recorded $2.6 million of this impairment expense in the first quarter of 2020, primarily related to leases the Company acquired from White Star and Will Energy in the fourth quarter of 2019, which were expiring in 2020, and the remaining $1.7 million of the impairment expense was recorded in the fourth quarter of 2020, due to leases expiring in 2021, all of which the Company has no plans to extend or develop as a result of the current commodity price environment and the Company’s continued focus on cost saving and production enhancing strategic initiatives. During the year ended December 31, 2019, the Company recognized impairment expense of approximately $9.2 million related primarily to lease expirations, and near-term expirations, in the Company’s West Texas region. Asset Retirement Obligations Asset Retirement and Environmental Obligations (“ASC 410”) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records an asset retirement obligation (“ARO”) to reflect the Company’s legal obligation related to future plugging and abandonment of its oil and natural gas wells, platforms and associated pipelines and equipment. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis, the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, platforms, and associated pipelines and equipment as these obligations are incurred. The liability is accreted to its present value each period, and the capitalized cost is depleted over the useful life of the related asset. The accretion expense is included in DD&A expense. The estimated liability is based on historical experience in plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free rate, changes in the remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, the Company recognizes a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs. This gain or loss on abandonment is included in impairment and abandonment of oil and natural gas properties expense. See Note 12 – “Asset Retirement Obligation” for additional information. Income Taxes The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. The Company reviews its tax positions quarterly for tax uncertainties. The Company did not have significant uncertain tax positions as of December 31, 2020. As described in Note 16 – “Income Taxes” with respect to Section 382 Ownership Change, the amount of unrecognized tax benefits did not change materially from December 31, 2019 . The amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect the change to have a significant impact on its financial position or results of operations. The Company includes interest and penalties in interest income and general and administrative expenses, respectively, in its consolidated statements of operations. The Company files income tax returns in the United States and various state jurisdictions. The Company’s federal and state tax returns for 2009 – 2020 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed. Concentration of Credit Risk Substantially all of the Company’s accounts receivable result from oil and natural gas sales or joint interest billings to a limited number of third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. See Note 3 – “Concentration of Credit Risk” for additional information. Debt Issuance Costs Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt. On September 17, 2019, the Company entered into the new revolving Credit Agreement with JPMorgan Chase Bank, N.A. and other lenders and incurred $1.8 million of arrangement and upfront fees in connection with the Credit Agreement. On November 1, 2019, the Credit Agreement was amended to add two additional lenders and increase the borrowing base thereunder, and the Company incurred an additional $1.6 million of debt issuance costs. On June 9, 2020, the Credit Agreement was amended to, among other things, reduce the borrowing base. No fees were incurred for the Second Amendment; however, during the three months ended June 30, 2020, the Company expensed $1.0 million of the debt issuance costs discussed above which originally were to be amortized over the life of the loan, due to the reduction in the borrowing base per the Second Amendment. On October 30, 2020, the Company entered into the Third Amendment to the Credit Agreement under which, among other things, increased the Company’s borrowing base from $75.0 million to $130.0 million, effective upon the closing of the Mid-Con Acquisition on January 21, 2021. The Company initially incurred $0.1 million in fees related to the Third Amendment during the three months ended December 31, 2020. During the year ended December 31, 2020, the Company amortized debt issuance costs of $1.6 million related to its Credit Agreement, including the $1.0 million mentioned above. As of December 31, 2020, the remaining balance of these debt issuance costs was $1.8 million, which will be amortized through September 17, 2024, with amortization expense included in the interest expense line item in the Company’s consolidated statements of operations. In January 2021, the Company incurred an additional $0.9 million in fees related to the Third Amendment becoming effective on January 21, 2021, in connection with the closing of the Mid-Con Acquisition. These fees will also be amortized over the remaining term of the loan. Stock-Based Compensation The Company applies the fair value based method to account for stock based compensation. Under this method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the requisite service period, which generally aligns with the award vesting period. The Company classifies the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) as financing cash flows. The fair value of each restricted stock award is estimated as of the date of grant. The fair value of the performance stock units is estimated as of the date of grant using the Monte Carlo simulation pricing model. Inventory Inventory consists primarily of casing and tubing stored temporarily, which will be used for drilling or completion of wells. Inventory is recorded at the lower of cost or market using specific identification method. Derivative Instruments and Hedging Activities The Company accounts for its derivative activities under the provisions of ASC 815, Derivatives and Hedging (“ASC 815”). ASC 815 establishes accounting and reporting requirements that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, the Company hedges a portion of its forecasted oil and natural gas production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction using variable to fixed swaps and collars. The Company elected to not designate any of its derivative positions for hedge accounting. Accordingly, the net change in the mark-to-market valuation of these positions as well as all payments and receipts on settled derivative contracts are recognized in “Gain (loss) on derivatives, net” on the consolidated statements of operations for the years ended December 31, 2020 and 2019. Derivative instruments with settlement dates within one year are included in current assets or liabilities, whereas derivative instruments with settlement dates exceeding one year are included in non-current assets or liabilities. The Company calculates the asset or liability for current and non-current derivative instruments for each counterparty based on the settlement dates within the respective contracts. See Note 6 – “Derivative Instruments” for additional information. Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Contango Resources, Inc., Contango Midstream Company, Contango Operators, Inc., Contaro Company, Contango Alta Investments, Inc. and any other of the Company’s future subsidiaries specified in the prospectus supplement (each a “Subsidiary Guarantor”) are Co-Registrants with the Parent Company under the registration statement, and the registration statement also registered guarantees of debt securities by the Subsidiary Guarantors. The Subsidiary Guarantors are wholly-owned by the Parent Company, either directly or indirectly, and any guarantee by the Subsidiary Guarantors will be full and unconditional. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. Finally, the Parent Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party. Leases The Company recognizes a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term on the Company’s consolidated balance sheet. The Company does not include leases with an initial term of twelve months or less on the balance sheet. The Company recognizes payments on these leases within “Operating expenses” on its consolidated statements of operations. The Company accounts for lease and non-lease contract components as a lease. The Company has procedures to review any new or modified contracts which contain a physical asset on a quarterly basis and determine if an arrangement is, or contains, a lease and determines the proper treatment. See Note 9 – “Leases” for additional information. Recent Accounting Pronouncements In June 2016, the FASB issued ASU 2016-13 - Financial Instruments - Credit Losses (“Topic 326”): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint interest billing receivables. Allowances are to be measured using a current expected credit loss model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. Initially, ASU 2016-13 was effective for all public companies for fiscal years beginning after December 15, 2019. The FASB subsequently issued ASU 2019-04 (“ASU 2019-04”): Codification Improvements to Topic 326, Financial Instruments - Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments and ASU 2019-05 (“ASU 2019-05”): Financial Instruments - Credit Losses (Topic 326) - Targeted Transition Relief. ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to the implementation of ASU 2016-13 and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments. In November 2019, the FASB issued ASU 2019-10 - Financial Instruments - Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates. This amendment deferred the effective date of ASU 2016-13 from January 1, 2020 to January 1, 2023 for calendar year-end smaller reporting companies, which includes the Company. The Company plans to defer the implementation of ASU 2016-13, and the related updates. In November 2019, the FASB issued ASU 2019-12 - Income Taxes (“Topic 740”): Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The amendments in ASU 2019-12 are part of an initiative to reduce complexity in accounting standards and simplify the accounting for income taxes by removing certain exceptions from Topic 740 and making minor improvements to the codification. The amendments in this update are effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations. In March 2020, the FASB issued ASU 2020-04 - Reference Rate Reform (“Topic 848”): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional guidance, for a limited period of time, to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. The amendments in ASU 2020-04 provide optional expedients and exceptions for applying US GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this ASU apply only to contracts, hedging relationships and other transactions that reference LIBOR, or another reference rate, expected to be discontinued because of reference rate reform. The Company is currently assessing the potential impact of ASU 2020-04 on its consolidated financial statements.

Concentration of Credit Risk

Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2020
Concentration Of Credit Risk [Abstract]
Concentration of Credit Risk	3. Concentration of Credit Risk The customer base for the Company is concentrated in the oil and natural gas industry. The Company’s largest three purchasers contributed approximately 36 % of the Company’s total production revenues for the year ended December 31, 2020 . The Company’s sales to these purchasers are not secured with letters of credit, and in the event of non-payment, the Company could lose up to two months of revenues. The loss of two months of revenues would have a material adverse effect on the Company’s financial position. However, we believe our current purchasers could be replaced by other purchasers under contracts with similar terms and conditions.

Acquisitions and Dispositions

Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2020
Acquisitions and Dispositions
Acquisitions and Dispositions	4. Acquisitions and Dispositions Mid-Con Acquisition On October 25, 2020, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement’) with Mid-Con and Mid-Con Energy GP, LLC, the general partner of Mid-Con (“Mid-Con GP”), pursuant to which Mid-Con will merge with and into Michael Merger Sub LLC, a Delaware limited liability company and a wholly-owned, direct subsidiary of the Company. The Mid-Con Acquisition , which closed on January 21, 2021, was unanimously approved by the conflicts committee of the board of directors of Mid-Con, by the full board of directors of Mid-Con, by the disinterested directors of the board of directors of the Company and was subject to shareholder and unitholder approvals and other customary conditions to closing. At the effective time of the Mid-Con Acquisition (the “Effective Time”), each common unit representing limited partner interests in Mid-Con issued and outstanding immediately prior to the Effective Time (other than treasury units or units held by Mid-Con GP) was converted automatically into the right to receive 1.75 shares of the Company’s common stock. A total of 25,409,164 shares of Contango common stock were issued at the closing of the Mid-Con Acquisition. As of January 21, 2021, John C. Goff, Chairman of the Board of Directors of the Company, beneficially owned approximately 56.4% of the common units of Mid-Con, and Travis Goff, John C. Goff’s son and the President of Goff Capital, Inc., served on the board of directors of the general partner of Mid-Con. The Company’s senior management team will run the combined company, and Contango’s board of directors will remain intact as the board of directors of the combined company. The combined company is headquartered in Fort Worth, Texas. The Mid-Con acquisition will be accounted for as a business combination. Therefore, the purchase price will be allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by the Company in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for the timing and amount of future development and operating costs, future plugging and abandonment costs, and a risk adjusted discount rate. The Company expects to complete the purchase price allocation during the twelve-month period following the acquisition date. The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Purchase Price Allocation (in thousands) Consideration: Cash $ 14,520 Exchange ratio of Contango shares for Mid-Con common units 1.75 Contango common stock to be issued to Mid-Con unitholders 25,409 Issue price 3.13 Total consideration $ 79,530 Liabilities Assumed: Accounts payable $ 5,596 Other current liabilities 457 Revolving credit facility 68,487 Asset retirement obligations 29,241 Total liabilities assumed $ 103,781 Assets acquired: Cash and cash equivalents $ 776 Accounts receivable 4,398 Current derivative asset 3,141 Prepaid expenses 162 Proved oil and natural gas properties 172,607 Other property and equipment 730 Other non-current assets 1,497 Total assets acquired $ 183,311 The following unaudited pro forma combined condensed financial data for the years ended December 31, 2020 was derived from the historical financial statements of the Company after giving effect to the Mid-Con acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including the depletion of the fair-valued proved oil and natural gas properties acquired from Mid-Con. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the assets acquired. The pro forma consolidated statement of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the acquisition taken place on January 1, 2020 and is not intended to be a projection of future results. (In thousands except for per share amounts) Year Ended December 31, 2020 Revenues $ 150,569 Net loss $ (188,178) Basic Earnings per share $ (1.02) Diluted earnings per share $ (1.02) Silvertip Acquisition On November 27, 2020, the Company entered into the Purchase Agreement with an undisclosed seller to acquire certain oil and natural gas properties located in the Big Horn Basin in Wyoming and Montana, in the Powder River Basin in Wyoming and in the Permian Basin in Texas and New Mexico, for aggregate consideration of approximately $58 million in cash. In connection with the execution of the Purchase Agreement, the Company paid $7.0 million as a deposit for its obligations under the Purchase Agreement, which is included in the consolidated balance sheet as of December 31, 2020. The Silvertip Acquisition closed on February 1, 2021, and a balance of $46.2 million was paid upon closing, after customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date. Juneau Joint Development Agreement On December 23, 2019, the Company entered into a Joint Development Agreement with Juneau for aggregate consideration of $6.0 million, consisting of $1.69 million in cash and 1,725,000 shares of common stock of the Company. This agreement provides the Company the right to acquire an interest in up to six of Juneau’s exploratory prospects located in the Gulf of Mexico. The first such exploratory prospect acquired by the Company was the Iron Flea prospect located in the Grand Isle Block 45 Area in the shallow waters off of the Louisiana coastline, which was determined to be unsuccessful in June 2020. The Company is currently evaluating for future testing a number of exploratory prospects included in the Joint Development agreement, including the Boss Hogg prospect, located in the Eugene Island 298 Area in the shallow waters off of the Louisiana coastline. Management considers this Boss Hogg prospect to be an excellent complement to its PDP-oriented acquisition strategy and believes it could provide a very compelling economic value proposition, even in the current low oil price environment. The Company is currently working through regulatory considerations and operational factors, including the availability of appropriate equipment, in determining the ultimate strategy for, and timing on, the testing of that prospect. White Star Acquisition On September 30, 2019, the Company entered into an asset purchase and sale agreement with White Star to acquire certain assets and liabilities, including approximately 306,000 net acres located in the STACK, Anadarko and Cherokee operating districts in Oklahoma. The closing of the White Star Acquisition occurred on November 1, 2019, for a total aggregate consideration of $132.5 million. Following adjustments for the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid was approximately $95.7 million in cash. The White Star Acquisition was accounted for as a business combination. Therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and natural gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and natural gas reserves, expectations for the timing and amount of future development and operating costs, future plugging and abandonment costs, and a risk adjusted discount rate. The following table sets forth the Company’s allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Purchase Price Allocation (in thousands) Consideration: Cash $ 95,722 Total consideration $ 95,722 Liabilities Assumed: Accounts payable $ 6,618 Revenue and royalties payable 11,165 Suspended revenue and royalties 22,011 Lease liabilities 3,614 Total liabilities assumed $ 43,408 Assets acquired: Accounts receivable $ 18,037 Other current assets 1,413 Proved oil and natural gas properties 113,150 Unevaluated properties 2,611 Right-of-use lease assets 3,614 Other assets 305 Total assets acquired $ 139,130 The purchase price allocated to the assets acquired increased to $139.1 million from the previously reported $138.5 million due to an increase in the value of inventory acquired of $1.0 million and a decrease in the value of unevaluated properties acquired of $0.4 million. Approximately $21.4 million of revenues and $16.3 million of direct operating expenses attributed to the White Star Acquisition are included in the Company’s consolidated statements of operations for the period of the closing date on November 1, 2019 through December 31, 2019. The following unaudited pro forma combined condensed financial data for the year ended December 31, 2019 was derived from the historical financial statements of the Company after giving effect to the White Star Acquisition, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the private placement of the Company’s Series B contingent convertible preferred stock and an increase in borrowings under the Company’s Credit Agreement, the proceeds of which were used to pay the purchase price of the White Star Acquisition, as well as pro forma adjustments based on then currently available information and certain assumptions that the Company believed were reasonable, including the depletion of the fair-valued proved oil and natural gas properties acquired from White Star and the exclusion of acquisition-related costs incurred by the Company of approximately $1.9 million for the year ended December 31, 2019. The pro forma results of operations do not include any cost savings or other synergies that may have resulted from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the assets acquired. In addition, the results of operations include non-cash impairment expense for White Star based on historical costs and not the fair value of the oil and natural gas properties acquired as reflected in the allocation of the purchase price. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the periods presented, as they were not deemed material. The pro forma consolidated statements of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the acquisition taken place on January 1, 2018 and is not intended to be a projection of future results. (In thousands except for per share amounts) Year Ended December 31, 2019 Revenues $ 207,530 Net loss $ (265,760) Basic Earnings per share $ (4.20) Diluted earnings per share $ (4.20) Will Energy Acquisition On September 12, 2019, the Company announced it entered into a contribution and purchase agreement with Will Energy to acquire approximately 155,900 net acres located in North Louisiana (8,000 net acres) and the Western Anadarko Basin in Western Oklahoma and the Texas Panhandle (147,900 net acres). Closing of the Will Energy Acquisition occurred on October 25, 2019, for a total aggregate consideration of $23 million. Following adjustments for sales of non-core, non-operated Louisiana properties by Will Energy prior to closing, the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid consisted of $14.0 million in cash and 3.5 million shares of common stock. Non-Core Assets Sales During the years ended December 31, 2020 and 2019, the Company completed certain non-core asset sales to enhance its liquidity, eliminate marginal assets and reduce administrative costs. These asset sales provide some immediate liquidity and improve the Company’s balance sheet by removing future asset retirement obligations. On June 1, 2020, the Company closed on the sale of certain producing and non-producing properties located in its Central Oklahoma and Western Anadarko regions. These non-core, marginally economic properties were a minor portion of the value of properties acquired from Will Energy and were sold in exchange for the buyer’s assumption of the plugging and abandonment liabilities of these properties and revenue held in suspense . The Company recorded a gain of $4.2 million as a result of the buyer’s assumption of the asset retirement obligations associated with the sold properties. On April 1, 2020, the Company closed on the sale of certain non-producing properties located in its Central Oklahoma region. These properties were a minor portion of the value of properties acquired from White Star and were sold for approximately $0.5 million. The Company recorded a gain of $0.2 million as a result of the buyer’s assumption of the asset retirement obligations associated with the sold properties. On July 1, 2019, the Company sold certain minor, non-core operated assets located in Frio and Zavala counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.2 million after removal of the asset retirement obligations associated with the sold properties. On June 10, 2019, the Company sold certain minor, non-core operated assets located in Lavaca and Wharton counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.4 million related to the buyer’s assumption of the asset retirement obligations associated with the sold properties.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2020
Fair Value Measurements
Fair Value Measurements	5. Fair Value Measurements Pursuant to ASC 820, Fair Value Measurements and Disclosures (“ASC 820”), the Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3. Derivatives are recorded at fair value at the end of each reporting period. The Company records the net change in the fair value of these positions in “Gain (loss) on derivatives, net” in the Company’s consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 6 – “Derivative Instruments” for additional discussion of derivatives. During the year ended December 31, 2020, the Company’s derivative contracts were with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. As such, the Company was exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company did not anticipate any nonperformance. The Company did not post collateral under any of these contracts as they are secured under the Credit Agreement or under unsecured lines of credit with non-bank counterparties. Estimates of the fair value of financial instruments are made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s Credit Agreement approximates carrying value because the interest rate approximates current market rates and are re-set at least every three months. See Note 13 – “Long-Term Debt” for further information. Fair value estimates used for non-financial assets are evaluated at fair value on a non-recurring basis and include oil and natural gas properties evaluated for impairment when facts and circumstances indicate that there may be an impairment. If the unamortized cost of properties exceeds the undiscounted cash flows related to the properties, the value of the properties is compared to the fair value estimated as discounted cash flows related to the risk-adjusted proved, probable and possible reserves related to the properties. Fair value measurements based on these inputs are classified as Level 3. Impairments Contango tests proved oil and natural gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and natural gas properties on a field-by-field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Asset Retirement Obligations The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and natural gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 at inception.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2020
Derivative Instruments [Abstract]
Derivative Instruments	6. Derivative Instruments The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil and natural gas production. The Company typically hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to a portion of its production, the Company’s strategy provides only partial protection against declines in commodity prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions and commodity price forecasts. As of December 31, 2020, the Company’s oil and natural gas derivative positions consisted of “swaps”. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for oil and natural gas. The Company has also, from time to time, entered into “costless collars” derivative positions. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract, and a purchased put, which establishes a minimum price. It is the Company’s practice to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company did not post collateral under any of these contracts as they are secured under the Credit Agreement or under unsecured lines of credit with non-bank counterparties. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Gain (loss) on derivatives, net” on the consolidated statements of operations. See Note 5 – “Fair Value Measurements” for additional information. The Company currently has derivative contracts in place to cover production periods through the first quarter of 2023, which include the hedges novated from Mid-Con and the additional hedges entered into in the first quarter of 2021, as discussed below. These contracts include oil hedges for 2.1 MMBbls of 2021 production with an average floor price of $54.85 per barrel and 1.4 MMBbls of 2022 production with an average floor price of $50.24 per barrel. For natural gas, the Company’s derivative contracts include 12.4 Bcf of 2021 production with an average floor price of $2.62 per MMBtu and 10.1 Bcf of 2022 production with an average floor price of $2.60 per MMBtu. Approximately 97% of the Company’s hedges are swaps, and the Company has no three-way collars or short puts. The Company had the following financial derivative contracts in place as of December 31, 2020: Commodity Period Derivative Volume/Month Price/Unit Fair Value Oil Jan 2021 - March 2021 Swap 19,000 Bbls $ 50.00 (1) 78 Oil April 2021 - July 2021 Swap 12,000 Bbls $ 50.00 (1) 71 Oil Aug 2021 - Sept 2021 Swap 10,000 Bbls $ 50.00 (1) 39 Oil Jan 2021 - July 2021 Swap 62,000 Bbls $ 52.00 (1) 1,490 Oil Aug 2021 - Sept 2021 Swap 55,000 Bbls $ 52.00 (1) 434 Oil Oct 2021 - Dec 2021 Swap 64,000 Bbls $ 52.00 (1) 840 Oil April 2022 - Oct 2022 Swap 25,000 Bbls $ 42.04 (1) (784) Natural Gas Jan 2021 - March 2021 Swap 185,000 MMBtus $ 2.505 (2) (1) Natural Gas April 2021 - July 2021 Swap 120,000 MMBtus $ 2.505 (2) (43) Natural Gas Aug 2021 - Sept 2021 Swap 10,000 MMBtus $ 2.505 (2) (4) Natural Gas Jan 2021 - March 2021 Swap 185,000 MMBtus $ 2.508 (2) (3) Natural Gas April 2021 - July 2021 Swap 120,000 MMBtus $ 2.508 (2) (44) Natural Gas Aug 2021 - Sept 2021 Swap 10,000 MMBtus $ 2.508 (2) (4) Natural Gas Jan 2021 - March 2021 Swap 650,000 MMBtus $ 2.508 (2) (6) Natural Gas April 2021 - Oct 2021 Swap 400,000 MMBtus $ 2.508 (2) (400) Natural Gas Nov 2021 - Dec 2021 Swap 580,000 MMBtus $ 2.508 (2) (402) Natural Gas April 2021 - Nov 2021 Swap 70,000 MMBtus $ 2.36 (2) (175) Natural Gas Dec 2021 Swap 350,000 MMBtus $ 2.36 (2) (195) Natural Gas Jan 2022 - March 2022 Swap 780,000 MMBtus $ 2.542 (2) (865) Natural Gas April 2022 - July 2022 Swap 650,000 MMBtus $ 2.515 (2) 252 Natural Gas Aug 2022 - Oct 2022 Swap 350,000 MMBtus $ 2.515 (2) 71 Natural Gas Jan 2022 - March 2022 Swap 250,000 MMBtus $ 3.149 (2) 179 Total net fair value of derivative instruments (in thousands) $ 528 (1) Based on West Texas Intermediate oil prices. (2) Based on Henry Hub NYMEX natural gas prices. The Company had the following financial derivative contracts in place as of December 31, 2019: Commodity Period Derivative Volume/Month Price/Unit Fair Value Oil Jan 2020 - June 2020 Swap 22,000 Bbls $ 57.74 (1) (289) Oil July 2020 - Dec 2020 Swap 15,000 Bbls $ 57.74 (1) 68 Oil Jan 2020 - March 2020 Swap 2,700 Bbls $ 54.33 (1) (51) Oil April 2020 - June 2020 Swap 2,500 Bbls $ 54.33 (1) (37) Oil July 2020 Swap 5,500 Bbls $ 54.33 (1) (21) Oil Aug 2020 - Oct 2020 Swap 2,500 Bbls $ 54.33 (1) (21) Oil Nov 2020 - Dec 2020 Swap 3,500 Bbls $ 54.33 (1) (12) Oil Jan 2020 - Feb 2020 Swap 42,500 Bbls $ 54.70 (1) (517) Oil March 2020 - July 2020 Swap 37,500 Bbls $ 54.70 (1) (842) Oil Aug 2020 - Dec 2020 Swap 35,000 Bbls $ 54.70 (1) (354) Oil Jan 2020 - Feb 2020 Swap 42,500 Bbls $ 54.58 (1) (527) Oil March 2020 - July 2020 Swap 37,500 Bbls $ 54.58 (1) (864) Oil Aug 2020 - Dec 2020 Swap 35,000 Bbls $ 54.58 (1) (373) Oil Jan 2020 - Oct 2020 Collar 3,442 Bbls $ 52.00 - 65.70 (1) 18 Oil Jan 2021 - March 2021 Swap 19,000 Bbls $ 50.00 (1) (291) Oil April 2021 - July 2021 Swap 12,000 Bbls $ 50.00 (1) (196) Oil Aug 2021 - Sept 2021 Swap 10,000 Bbls $ 50.00 (1) (67) Oil Jan 2021 - July 2021 Swap 62,000 Bbls $ 52.00 (1) (1,122) Oil Aug 2021 - Sept 2021 Swap 55,000 Bbls $ 52.00 (1) (157) Oil Oct 2021 - Dec 2021 Swap 64,000 Bbls $ 52.00 (1) (184) Natural Gas Jan 2020 - March 2020 Swap 425,000 MMBtus $ 2.841 (2) 856 Natural Gas Jan 2020 - March 2020 Collar 225,000 MMBtus $ 2.45 - 3.40 (2) 209 Natural Gas April 2020 - July 2020 Swap 400,000 MMBtus $ 2.532 (2) 493 Natural Gas Aug 2020 - Oct 2020 Swap 40,000 MMBtus $ 2.532 (2) 25 Natural Gas Nov 2020 - Dec 2020 Swap 375,000 MMBtus $ 2.696 (2) 134 Natural Gas Jan 2020 - March 2020 Swap 300,000 MMBtus $ 2.53 (2) 325 Natural Gas April 2020 - July 2020 Swap 400,000 MMBtus $ 2.53 (2) 490 Natural Gas Aug 2020 - Dec 2020 Swap 350,000 MMBtus $ 2.53 (2) 223 Natural Gas Jan 2020 - March 2020 Swap 300,000 MMBtus $ 2.532 (2) 327 Natural Gas April 2020 - July 2020 Swap 400,000 MMBtus $ 2.532 (2) 493 Natural Gas Aug 2020 - Dec 2020 Swap 350,000 MMBtus $ 2.532 (2) 226 Natural Gas Jan 2021 - March 2021 Swap 185,000 MMBtus $ 2.505 (2) (78) Natural Gas April 2021 - July 2021 Swap 120,000 MMBtus $ 2.505 (2) 99 Natural Gas Aug 2021 - Sept 2021 Swap 10,000 MMBtus $ 2.505 (2) 4 Natural Gas Jan 2021 - March 2021 Swap 185,000 MMBtus $ 2.508 (2) (75) Natural Gas April 2021 - July 2021 Swap 120,000 MMBtus $ 2.508 (2) 104 Natural Gas Aug 2021 - Sept 2021 Swap 10,000 MMBtus $ 2.508 (2) 4 Natural Gas Jan 2021 - March 2021 Swap 650,000 MMBtus $ 2.508 (2) (268) Natural Gas April 2021 - Oct 2021 Swap 400,000 MMBtus $ 2.508 (2) 544 Natural Gas Nov 2021 - Dec 2021 Swap 580,000 MMBtus $ 2.508 (2) 20 Total net fair value of derivative instruments (in thousands) $ (1,684) (1) Based on West Texas Intermediate oil prices. (2) Based on Henry Hub NYMEX natural gas prices. In addition to the above financial derivative instruments, the Company also had a costless swap agreement with a Midland WTI – Cushing oil differential swap price of $0.05 per barrel of oil. The agreement fixed the Company’s exposure to that differential on 12,000 barrels of oil per month for January 2020 through June 2020 and 10,000 barrels per month for July 2020 through December 2020. The fair value of this costless swap agreement was in a liability position of $0.1 million as of December 31, 2019. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2020 (in thousands). Gross Netting (1) Total Assets $ 3,493 $ — $ 3,493 Liabilities $ (2,965) $ — $ (2,965) (1) Represents counterparty netting under agreements governing such derivatives. Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset or liability” on the Company’s consolidated balance sheet and include swaps that are carried at fair value. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2019 (in thousands). Gross Netting (1) Total Assets $ 4,176 $ — $ 4,176 Liabilities $ (5,971) $ — $ (5,971) (1) Represents counterparty netting under agreements governing such derivatives. Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset or liability” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value. The following table summarizes the effect of derivative contracts on the Consolidated Statements of Operations for the years ended December 31, 2020 and 2019 (in thousands): Year Ended December 31, Contract Type 2020 2019 Crude oil contracts $ 18,561 $ 1,614 Natural gas contracts 6,703 1,002 Realized gain $ 25,264 $ 2,616 Crude oil contracts $ 8,120 $ (10,012) Natural gas contracts (5,799) 4,039 Unrealized gain (loss) $ 2,321 $ (5,973) Gain (loss) on derivatives, net $ 27,585 $ (3,357) In conjunction with the closing of the Mid-Con Acquisition in January 2021, the Company acquired the following additional derivative contracts via novation from Mid-Con: Commodity Period Derivative Volume/Month Price/Unit Oil Jan 2021 Swap 20,883 Bbls $ 55.78 (1) Oil Feb 2021 Swap 20,804 Bbls $ 55.78 (1) Oil March 2021 Swap 20,725 Bbls $ 55.78 (1) Oil April 2021 Swap 20,647 Bbls $ 55.78 (1) Oil May 2021 Swap 20,563 Bbls $ 55.78 (1) Oil June 2021 Swap 20,487 Bbls $ 55.78 (1) Oil July 2021 Swap 20,412 Bbls $ 55.78 (1) Oil Aug 2021 Swap 20,301 Bbls $ 55.78 (1) Oil Sept 2021 Swap 20,228 Bbls $ 55.78 (1) Oil Oct 2021 Swap 20,155 Bbls $ 55.78 (1) Oil Nov 2021 Swap 20,084 Bbls $ 55.78 (1) Oil Dec 2021 Swap 20,012 Bbls $ 55.78 (1) Oil Jan 2021 Collar 20,883 Bbls $ 52.00 - 58.80 (1) Oil Feb 2021 Collar 20,804 Bbls $ 52.00 - 58.80 (1) Oil March 2021 Collar 20,725 Bbls $ 52.00 - 58.80 (1) Oil April 2021 Collar 20,647 Bbls $ 52.00 - 58.80 (1) Oil May 2021 Collar 20,563 Bbls $ 52.00 - 58.80 (1) Oil June 2021 Collar 20,487 Bbls $ 52.00 - 58.80 (1) Oil July 2021 Collar 20,412 Bbls $ 52.00 - 58.80 (1) Oil Aug 2021 Collar 20,301 Bbls $ 52.00 - 58.80 (1) Oil Sept 2021 Collar 20,228 Bbls $ 52.00 - 58.80 (1) Oil Oct 2021 Collar 20,155 Bbls $ 52.00 - 58.80 (1) Oil Nov 2021 Collar 20,084 Bbls $ 52.00 - 58.80 (1) Oil Dec 2021 Collar 20,012 Bbls $ 52.00 - 58.80 (1) (1) Based on West Texas Intermediate oil prices. In the first quarter of 2021, the Company entered into the following additional derivative contracts: Commodity Period Derivative Volume/Month Price/Unit Oil March 2021 - Oct 2021 Swap 25,000 Bbls $ 54.77 (1) Oil Nov 2021 - Dec 2021 Swap 15,000 Bbls $ 54.77 (1) Oil March 2021 Swap 50,000 Bbls $ 63.31 (1) Oil April 2021 Swap 50,000 Bbls $ 63.13 (1) Oil May 2021 Swap 50,000 Bbls $ 62.71 (1) Oil June 2021 Swap 50,000 Bbls $ 62.17 (1) Oil July 2021 Swap 50,000 Bbls $ 61.50 (1) Oil Aug 2021 Swap 50,000 Bbls $ 60.94 (1) Oil Sep 2021 Swap 50,000 Bbls $ 60.38 (1) Oil Oct 2021 Swap 50,000 Bbls $ 59.89 (1) Oil Nov 2021 Swap 50,000 Bbls $ 59.46 (1) Oil Dec 2021 Swap 50,000 Bbls $ 59.01 (1) Oil Jan 2022 Swap 60,000 Bbls $ 52.94 (1) Oil Feb 2022 Swap 60,000 Bbls $ 52.65 (1) Oil March 2022 Swap 60,000 Bbls $ 52.29 (1) Oil April 2022 Swap 47,500 Bbls $ 51.98 (1) Oil May 2022 Swap 45,000 Bbls $ 51.71 (1) Oil June 2022 Swap 45,000 Bbls $ 51.41 (1) Oil July 2022 Swap 45,000 Bbls $ 51.13 (1) Oil Aug 2022 Swap 45,000 Bbls $ 50.89 (1) Oil Sep 2022 Swap 45,000 Bbls $ 50.65 (1) Oil Oct 2022 Swap 45,000 Bbls $ 50.45 (1) Oil Nov 2022 Swap 55,000 Bbls $ 50.26 (1) Oil Dec 2022 Swap 55,000 Bbls $ 50.22 (1) Oil Jan 2023 Swap 57,500 Bbls $ 49.81 (1) Oil Feb 2023 Swap 57,500 Bbls $ 49.63 (1) Oil Jan 2022 Swap 60,000 Bbls $ 52.96 (1) Oil Feb 2022 Swap 60,000 Bbls $ 52.66 (1) Oil March 2022 Swap 60,000 Bbls $ 52.27 (1) Oil April 2022 Swap 47,500 Bbls $ 51.96 (1) Oil May 2022 Swap 45,000 Bbls $ 51.72 (1) Oil June 2022 Swap 45,000 Bbls $ 51.42 (1) Oil July 2022 Swap 45,000 Bbls $ 51.13 (1) Oil Aug 2022 Swap 45,000 Bbls $ 50.90 (1) Oil Sep 2022 Swap 45,000 Bbls $ 50.66 (1) Oil Oct 2022 Swap 45,000 Bbls $ 50.47 (1) Oil Nov 2022 Swap 55,000 Bbls $ 50.26 (1) Oil Dec 2022 Swap 55,000 Bbls $ 50.01 (1) Oil Jan 2023 Swap 57,500 Bbls $ 49.79 (1) Oil Feb 2023 Swap 57,500 Bbls $ 49.62 (1) Natural Gas March 2021 Swap 100,000 MMBtus $ 2.96 (2) Natural Gas April 2021 - July 2021 Swap 350,000 MMBtus $ 2.96 (2) Natural Gas Aug 2021 - Oct 2021 Swap 500,000 MMBtus $ 2.96 (2) Natural Gas Nov 2021 Swap 450,000 MMBtus $ 2.96 (2) Natural Gas April 2022 Swap 175,000 MMBtus $ 2.51 (2) Natural Gas May 2022 - July 2022 Swap 150,000 MMBtus $ 2.51 (2) Natural Gas Aug 2022 - Oct 2022 Swap 400,000 MMBtus $ 2.51 (2) Natural Gas Nov 2022 - Feb 2023 Swap 750,000 MMBtus $ 2.72 (2) (1) Based on West Texas Intermediate oil prices. (2) Based on Henry Hub NYMEX natural gas prices.

Stock Based Compensation

Stock Based Compensation	12 Months Ended
	Dec. 31, 2020
Stock-Based Compensation [Abstract]
Stock-Based Compensation	7. Stock Based Compensation Effective January 1, 2014, the Company implemented performance-based long-term bonus plans under its compensation plan at the time (the “2009 Plan”) for the benefit of all employees through a Cash Incentive Bonus Plan (“CIBP”) and a Long-Term Incentive Plan (“LTIP”). The specific targeted performance measures under these sub-plans are approved by the Compensation Committee and/or the Company’s board of directors (the “Board”). Upon achieving the performance levels established each year, bonus awards under the CIBP and LTIP will be calculated as a percentage of base salary of each employee for the plan year. The CIBP and LTIP plan awards for each year are expected to be disbursed in the first quarter of the following year. Employees must be employed by the Company at the time that awards are disbursed to be eligible. The CIBP awards will be paid in cash while LTIP awards will consist of restricted common stock, performance stock units and/or stock options. The number of shares of restricted common stock and the number of shares underlying the stock options granted will be determined based upon the fair market value of the common stock on the date of the grant. Third Amended and Restated 2009 Incentive Compensation Plan As of December 31, 2020, the Company had in place the Contango Oil & Gas Company Third Amended and Restated 2009 Incentive Compensation Plan (“the Third Amended 2009 Plan”) which allows for stock options, restricted stock or performance stock units to be awarded to officers, directors and employees as a performance-based award. On March 21, 2017, the Board amended and restated the Company’s then existing incentive compensation plan through the adoption of the Second Amended 2009 Plan. The Second Amended 2009 Plan provides for both cash awards and equity awards to officers, directors, employees or consultants of the Company. On June 8, 2020 the Board amended and restated the Second Amended 2009 Plan through the adoption of the Third Amended 2009 Plan, which, among other things, increased the number of shares of the Company’s common stock authorized for issuance pursuant to the Third Amended 2009 Plan by 9,000,000 shares and increased the maximum aggregate number of shares of common stock that may be granted to any individual during any calendar year from 250,000 to 1,000,000 . Awards made under the Third Amended 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board. Under the terms of the Third Amended 2009 Plan, shares of the Company’s common stock may be issued for plan awards. Stock options under the Third Amended 2009 Plan must have an exercise price of each option equal to or greater than the market price of the Company’s common stock on the date of grant. The Company may grant officers and employees both incentive stock options intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified as incentive stock options. Options granted generally expire after five or ten years. The vesting schedule for all equity awards varies from immediately to over a three-year period. As of December 31, 2020, the Company had approximately 6.2 million shares of equity awards available for future grant under the Third Amended 2009 Plan, assuming performance stock units are settled at 100% of target. 2005 Stock Incentive Plan The 2005 Plan was adopted by the Company’s Board in conjunction with the merger with Crimson Exploration, Inc. This plan expired on February 25, 2015, and therefore, no additional shares are available for grant. Stock Options A summary of stock options as of and for the years ended December 31, 2020 and 2019 is presented in the table below (dollars in thousands, except per share data): Year Ended December 31, 2020 2019 Weighted Weighted Shares Average Shares Average Under Exercise Under Exercise Options Price Options Price Outstanding, beginning of the period 20,964 $ 58.53 33,637 $ 55.82 Exercised — $ — — $ — Expired / Forfeited (1,117) $ 39.00 (12,673) $ 51.34 Outstanding, end of year 19,847 $ 59.62 20,964 $ 58.53 Aggregate intrinsic value $ — $ — Exercisable, end of year 19,847 $ 59.62 20,964 $ 58.53 Aggregate intrinsic value $ — $ — Available for grant, end of the period * 6,240,312 1,480,389 Weighted average fair value of options granted during the period $ — $ — * Assumes performance stock units are settled at 100% of target. During the years ended December 31, 2020 and 2019, the Company did not issue any stock options. During the years ended December 31, 2020 and December 31, 2019, 1,117 and 12,673 stock options previously issued were forfeited by former employees, respectively. As of December 31, 2020, there were 19,847 stock options vested and exercisable under the 2005 Plan. The exercise price for such options ranges from $28.96 to $60.33 per share, with an average remaining contractual life of 0.2 years. Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the years ended December 31, 2020 and 2019, there was no excess tax benefit recognized. See Note 2 – “Summary of Significant Accounting Policies”. Compensation expense related to employee stock option grants are recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. During the years ended December 31, 2020 and 2019, the Company did not recognize any stock option expense. The aggregate intrinsic value of stock options exercised/forfeited during each of the years ended December 31, 2020 and 2019 was zero. Restricted Stock During the year ended December 31, 2020, the Company issued 1,041,365 restricted stock awards to new and existing employees, which vest over three years, as part of their overall compensation package. During the year ended December 31, 2020, the Company issued 152,248 restricted stock awards to the members of the board of directors, which vest on the one-year anniversary of the date of grant, as well as an additional 50,914 restricted stock awards, in lieu of cash fees earned for the third quarter of 2020, which vested immediately. During the year ended December 31, 2020, 55,064 restricted stock awards were forfeited by former employees. The weighted average fair value of the restricted shares granted during the year was $2.22, with a total grant date fair value of approximately $2.8 million with no adjustment for an estimated weighted average forfeiture rate. During the year ended December 31, 2019, the Company issued 307,650 restricted stock awards to new and existing employees, which vest over three years, plus an additional 80,410 restricted stock awards to the members of the board of directors, which vest on the one-year anniversary of the date of grant, as part of their overall compensation package. During the year ended December 31, 2019, 91,346 restricted stock awards were forfeited by former employees. The weighted average fair value of the restricted shares granted during the year was $2.91, with a total grant date fair value of approximately $1.1 million with no adjustment for an estimated weighted average forfeiture rate. Restricted stock activity as of December 31, 2020 and 2019 and for the years then ended is presented in the table below (dollars in thousands, except per share data): 2020 2019 Weighted Aggregate Weighted Aggregate Restricted Average Intrinsic Restricted Average Intrinsic Shares Fair Value Value Shares Fair Value Value Outstanding, beginning of the period 403,221 $ 3.66 $ 214 459,621 $ 7.26 $ 662 Granted 1,244,527 2.22 65 388,060 2.91 — Vested (289,636) 3.48 700 (353,114) 7.41 1,171 Canceled / Forfeited (55,064) 2.45 16 (91,346) 4.08 41 Not vested, end of the period 1,303,048 2.38 228 403,221 3.66 214 The Company recognized approximately $1.3 million and $1.9 million in restricted stock compensation expense during the years ended December 31, 2020 and 2019, respectively, for restricted shares granted to its officers, employees and directors. The lower 2020 expense is primarily related to the issuance of stock in the third quarter of 2020 as compared to stock issued in the first quarter of 2019. As of December 31, 2020, there were 1,303,048 shares of unvested restricted stock outstanding, and an additional $2.3 million of compensation expense related to restricted stock remains to be recognized over the remaining vesting period of 2.1 years. Performance Stock Units Performance stock units (“PSUs”) represent the opportunity to receive shares of the Company’s common stock at the time of settlement. The number of shares to be awarded upon settlement of the PSUs may range from 0% to 300% of the targeted number of PSUs stated in the award agreements, contingent upon the achievement of certain share price appreciation targets compared to share appreciation of a specific peer group or peer group index over a three-year period. The PSUs vest at the end of the three-year performance period, with the final number of shares to be issued determined at that time, based on the Company’s share performance during the period compared to the average performance of the peer group. Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determined using the Monte Carlo simulation model, which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the PSUs with shares of the Company’s common stock after three years, the PSU awards are accounted for as equity awards, and the fair value is calculated on the grant date. The simulation model calculates the payout percentage based on the stock price performance over the performance period. The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair value expense is amortized over the life of the PSU award. During the year ended December 31, 2020, the Company granted 2,846,140 PSUs to executive officers and certain employees as part of their overall compensation package. The performance period will be measured between May 1, 2020 and April 30, 2023. These granted PSUs were valued at a weighted average fair value of $4.90 per unit. All fair value prices were determined using the Monte Carlo simulation model. In January 2020, 77,485 shares of the PSUs granted in 2017 vested , of which 22,972 PSUs were withheld for taxes, and are included with the restricted stock activity in the consolidated statement of shareholders’ equity. In December 2020, 68,476 shares of the PSUs granted in 2018 vested , of which 18,284 PSUs were withheld for taxes and are included with the restricted stock activity in the consolidated statement of shareholders’ equity. No PSUs were forfeited d uring the year ended December 31, 2020. The Company recognized approximately $3.0 million in stock compensation expense related to PSUs during 2020. As of December 31, 2020, an additional $11.7 million of compensation expense related to PSUs remained to be recognized over the remaining vesting period of 2.3 years. During the year ended December 31, 2019, the Company granted 117,105 PSUs to executive officers and employees as part of their overall compensation package, which will be measured between January 1, 2019 and December 31, 2021, and were valued at a weighted average fair value of $6.42 per unit. All fair value prices were determined using the Monte Carlo simulation model. During the year ended December 31, 2019, 71,945 PSUs were forfeited by former employees, including 49,773 PSU forfeitures due to the resignations of the Company’s former Senior Vice President of Exploration and Senior Vice President of Operations and Engineering in February 2019. The Company only recognized approximately $0.5 million in stock compensation expense related to PSUs during 2019, primarily due to the expiration of PSUs which failed to meet their target as of December 31, 2018 and the above referenced forfeitures.

Share Repurchase Programs

Share Repurchase Programs	12 Months Ended
	Dec. 31, 2020
Share Repurchase Programs [Abstract]
Share Repurchase Programs	8. Share Repurchase Program In September 2011, the Company’s board of directors approved a $50 million share repurchase program. All shares are to be purchased in the open market or through privately negotiated transactions. Purchases are made subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market, and when the Company believes its stock price to be undervalued. Repurchased shares of common stock become authorized but unissued shares and may be issued in the future for general corporate and other purposes. No shares were purchased during the years ended December 31, 2020 and 2019. As of December 31, 2020, the Company had $31.8 million available under the share repurchase program for future purchases; however, repurchases could be limited by provisions of the Company’s Credit Agreement.

Leases

Leases	12 Months Ended
	Dec. 31, 2020
Leases
Leases	9. Leases As of January 1, 2019, the Company adopted Accounting Standards Codification Topic 842 – Leases (“ASC 842”), which requires lessees to recognize a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis, and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term on the Company’s consolidated balance sheet. During the year ended December 31, 2020, the Company entered into new compressor contracts with lease terms of twelve months or more, which qualify as operating leases. The Company also entered into new contracts for vehicles and office equipment with lease terms of twelve months or more, which qualify as finance leases. As of December 31, 2020, the Company’s operating leases were for compressors and office space for two corporate offices and three field offices, while the Company’s finance leases were for vehicles and office equipment. These leases do not have a material net impact on the Company’s consolidated financial statements. The following table summarizes the balance sheet information related to the Company’s leases as of December 31, 2020 and December 31, 2019 (in thousands): December 31, 2020 December 31, 2019 Operating lease right of use asset (1) $ 2,452 $ 4,316 Operating lease liability - current (2) $ (1,832) $ (2,597) Operating lease liability - long-term (3) (522) (1,738) Total operating lease liability $ (2,354) $ (4,335) Financing lease right of use asset (1) $ 2,996 $ 1,569 Financing lease liability - current (2) $ (940) $ (524) Financing lease liability - long-term (3) (2,102) (1,051) Total financing lease liability $ (3,042) $ (1,575) (1) Included in “Right-of-use lease assets” on the consolidated balance sheet. (2) Included in “Accounts payable and accrued liabilities” on the consolidated balance sheet. (3) Included in “Lease liabilities” on the consolidated balance sheet. The Company’s leases generally do not provide an implicit rate, and therefore the Company uses its incremental borrowing rate as the discount rate when measuring operating lease liabilities. The incremental borrowing rate represents an estimate of the interest rate the Company would incur at lease commencement to borrow an amount equal to the lease payments on a collateralized basis over the term of a lease. For operating leases existing prior to January 1, 2019, the incremental borrowing rate as of January 1, 2019 was used for the remaining lease term. The table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of December 31, 2020 and December 31, 2019: December 31, 2020 December 31, 2019 Weighted Average Remaining Lease Terms (in years): Operating leases Financing leases Weighted Average Discount Rate: Operating leases Financing leases Maturities for the Company’s lease liabilities on the consolidated balance sheet as of December 31, 2020, were as follows (in thousands): December 31, 2020 Operating Leases Financing Leases 2021 $ 1,906 $ 1,094 2022 240 980 2023 170 823 2024 158 459 Total future minimum lease payments 2,474 3,356 Less: imputed interest (120) (314) Present value of lease liabilities $ 2,354 $ 3,042 The following table summarizes expenses related to the Company’s leases for the three months ended December 31, 2020 and December 31, 2019 (in thousands): Three Months Ended December 31, 2020 Three Months Ended December 31, 2019 Operating lease cost (1) (2) $ 843 $ 542 Financing lease cost - amortization of right-of-use assets 231 87 Financing lease cost - interest on lease liabilities 47 17 Administrative lease cost (3) 19 19 Short-term lease cost (1) (4) 360 741 Total lease cost $ 1,500 $ 1,406 (1) This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. (2) Costs related to office leases and compressors with lease terms of twelve months of more. (3) Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year. (4) Costs related primarily to drilling rigs, generators and compressor agreements with lease terms of more than one month and less than one year. The following table summarizes expenses related to the Company’s leases for the years ended December 31, 2020 and December 31, 2019 (in thousands): Year Ended December 31, 2020 Year Ended December 31, 2019 Operating lease cost (1) (2) $ 3,055 $ 742 Financing lease cost - amortization of right-of-use assets 642 92 Financing lease cost - interest on lease liabilities 131 18 Administrative lease cost (3) 75 75 Short-term lease cost (1) (4) 1,974 4,101 Total lease cost $ 5,877 $ 5,028 (1) This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. (2) Costs related to office leases and compressors with lease terms of twelve months of more. Higher costs in 2020 due to additional leases related to the properties acquired from Will Energy and White Star during the three months ended December 31, 2019. (3) Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year. (4) Costs related primarily to drilling rigs, generators and compressor agreements with lease terms of more than one month and less than one year. There were $3.2 million and $0.9 million in cash payments related to operating leases and financing leases, respectively, during the year ended December 31, 2020. There were $0.8 million and $0.1 million in cash payments related to operating leases and financing leases, respectively, during the year ended December 31, 2019.

Other Financial Information

Other Financial Information	12 Months Ended
	Dec. 31, 2020
Other Financial Information [Abstract]
Other Financial Information	10. Other Financial Information The following table provides additional detail for accounts receivable, prepaids and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): December 31, December 31, 2020 2019 Accounts receivable: Trade receivables $ 20,306 $ 21,110 Receivable for Alta Resources distribution 1,712 1,712 Joint interest billings 15,637 13,104 Income taxes receivable 268 509 Other receivables 2,209 4,126 Allowance for doubtful accounts (1) (2,270) (994) Total accounts receivable $ 37,862 $ 39,567 Prepaid Expenses: Prepaid insurance $ 2,825 $ 683 Other (2) 535 508 Total Prepaid Expenses $ 3,360 $ 1,191 Accounts payable and accrued liabilities: Royalties and revenue payable $ 23,701 $ 15,905 Legal suspense related to revenues (3) 27,983 33,739 Advances from partners (4) 76 6,733 Accrued exploration and development (4) 490 8,210 Trade payables 14,273 14,086 Accrued general and administrative expenses (5) 6,191 12,037 Accrued operating expenses 5,755 5,794 Accrued operating and finance leases 2,772 3,120 Other accounts payable and accrued liabilities 2,729 4,969 Total accounts payable and accrued liabilities $ 83,970 $ 104,593 (1) Increase in 2020 primarily due to the additional properties acquired from Will Energy and White Star. (2) Other prepaids primarily includes software licenses. (3) Suspended revenues primarily relate to amounts for which there is some question as to valid ownership, unknown addresses of payees or some other payment dispute. (4) Decrease in 2020 due to a decrease in drilling and completion activity. In response to the dramatic decline in commodity prices in the first quarter of 2020, the Company suspended further operated drilling in its West Texas area, and in its other onshore areas. (5) The December 31, 2019 balance includes an accrual of $6.3 million for a legal judgment that was paid in April 2020. See Note 14 – “Commitment and Contingencies” for further information. Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the years ended December 31, 2020 and 2019, in thousands: Year Ended December 31, 2020 2019 Cash payments: Interest payments $ 3,592 $ 7,761 Income tax payments, net of cash refunds 293 668 Non-cash items excluded from investing activities in the consolidated statements of cash flows: Increase (decrease) in accrued capital expenditures (7,615) 1,841

Investment In Exaro Energy III

Investment In Exaro Energy III LLC	12 Months Ended
	Dec. 31, 2020
Investment In Exaro Energy III LLC [Abstract]
Investment In Exaro Energy III LLC	11. Investment in Exaro Energy III LLC Through the Company’s wholly-owned subsidiary, Contaro Company (“Contaro”), the Company committed to invest up to $67.5 million in Exaro for an ownership interest of approximately 37%. The aggregate commitment of all the Exaro investors was approximately $183 million. The Company did not make any contributions during the year ended December 31, 2020 and has no plans to invest additional funds in Exaro, as the commitment to invest in Exaro expired on March 31, 2017. As of December 31, 2020, the Company had invested approximately $46.9 million. Contango’s share in the equity of Exaro at December 31, 2020 was approximately $6.8 million. The Company’s share in Exaro's results of operations recognized for the years ended December 31, 2020 and 2019 was a gain of approximately $27,000, net of zero tax expense and a gain of approximately $1.0 million, net of zero tax, respectively.

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	12. Asset Retirement Obligation The Company accounts for its retirement obligation of long lived assets by recording the net present value of a liability for an ARO in the period in which it is incurred. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Activities related to the Company’s ARO during the years ended December 31, 2020 and 2019 were as follows (in thousands): Year Ended December 31, 2020 2019 Balance as of the beginning of the period $ 51,665 $ 13,497 Liabilities incurred during period 5 256 Liabilities settled during period (338) (1,380) Accretion 2,702 1,062 Sales (5,239) (816) Acquisitions — 37,596 Change in estimate 3,978 1,450 Balance as of the end of the period $ 52,773 $ 51,665 All of the total liabilities incurred during the years ended December 31, 2020 and 2019 were related to new wells drilled during the period. All of the total liabilities settled during the years ended December 31, 2020 and 2019 were related to wells plugged and abandoned during the period. The acquisitions refer to new liabilities assumed from the properties acquired in 2019 from White Star and Will Energy. The change in estimate relates to year-end adjustments for updated estimated plugging and abandonment costs, primarily in the Company’s Central Oklahoma and Western Anadarko regions.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2020
Long-Term Debt
Long-Term Debt	13. Long-Term Debt Credit Agreement On September 17, 2019, the Company entered into its new revolving Credit Agreement with JPMorgan Chase Bank, N.A. and other lenders, which established a borrowing base of $65 million. The borrowing base is subject to semi-annual redeterminations which will occur on or around May 1 st and November 1 st of each year. The Credit Agreement was amended on November 1, 2019, in conjunction with the closing of the Will Energy Acquisition and White Star Acquisition, to add two additional lenders and increase the borrowing base thereunder to $145 million. On June 9, 2020, the Company entered into the Second Amendment to the Credit Agreement (the “Second Amendment”). The Second Amendment redetermined the borrowing base at $95 million, among other things, pursuant to the regularly scheduled redetermination process. The Second Amendment also provided for further $10 million automatic reductions in the borrowing base on each of June 30, 2020 and September 30, 2020. O In connection with the closing of the Mid-Con Acquisition on January 21, 2021, the borrowing base increased automatically to $130.0 million. The next regularly scheduled borrowing base redetermination is on or before May 1, 2021. Initially, the Company incurred $1.8 million of arrangement and upfront fees in connection with the Credit Agreement and incurred an additional $1.6 million in fees for the first amendment to the Credit Agreement, all to be amortized over the remaining term of the Credit Agreement. No fees were incurred for the Second Amendment; however, during the three months ended June 30, 2020, the Company expensed $1.0 million of the debt issuance costs discussed above, which originally were to be amortized over the life of the loan, due to the reduction in the borrowing base per the Second Amendment. The Company initially incurred $0.1 million in fees related to the Third Amendment during the three months ended December 31, 2020. During the year ended December 31, 2020, the Company amortized debt issuance costs of $1.6 million related to the Credit Agreement, including the $1.0 million mentioned above. As of December 31, 2020, the remaining balance of these fees was $1.8 million, which will be amortized through September 17, 2024. In January 2021, the Company incurred an additional $0.9 million in fees related to the Third Amendment that became effective on January 21, 2021, in connection with the closing of the Mid-Con Acquisition. These fees will also be amortized over the remaining term of the loan. As of December 31, 2020, the Company had $9.0 million outstanding under the Credit Agreement and $1.9 million in outstanding letters of credit. As of December 31, 2019, the Company had $72.8 million outstanding under the Credit Agreement and $1.9 million in outstanding letters of credit. As of December 31, 2020, borrowing availability under the Credit Agreement was $64.1 million. The Credit Agreement is collateralized by liens on substantially all of the Company’s oil and natural gas properties and other assets and security interests in the stock of its wholly owned and/or controlled subsidiaries. The Company’s wholly owned and/or controlled subsidiaries are also required to join as guarantors under the Credit Agreement. Borrowings under the Credit Agreement bear interest at LIBOR, the U.S. prime rate, or the federal funds rate, plus a 1.75% to 3.75% margin, dependent upon the amount outstanding. Total interest expense under the Company’s Credit Agreement, including commitment fees, the additional $1.0 million in expensed loan fees discussed above and other financing fees was approximately $5.0 million for the year ended December 31, 2020. Total interest expense under the Company’s current and previous credit agreements, including commitment fees and other financing fees, was approximately $8.6 million for the year ended December 31, 2019. The weighted average interest rates in effect at December 31, 2020 and December 31, 2019 were 2.9% and 4.3% under the Credit Agreement, respectively. The Credit Agreement contains customary and typical restrictive covenants. The Credit Agreement requires a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of less than or equal to 3.50, both as defined in the Credit Agreement. The Second Amendment includes a waiver of the Current Ratio requirement until the quarter ending March 31, 2022. Additionally, the Second Amendment, among other things, provides for an increase in the Applicable Margin grid on borrowings outstanding of 50 basis points, and includes provisions requiring monthly aged accounts payable reports and typical anti-cash hoarding and cash sweep provisions with respect to a consolidated cash balance in excess of $5.0 million. The Credit Agreement also contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, a going concern qualification, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. As of December 31, 2020, the Company was in compliance with all of its covenants under the Credit Agreement. Paycheck Protection Program Loan On April 10, 2020, the Company entered into a promissory note evidencing an unsecured loan in the amount of approximately $3.4 million (the “PPP Loan”) made to the Company under the Paycheck Protection Program (the “PPP”). The PPP was established under the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”), signed into law on March 27, 2020, and is administered by the U.S. Small Business Administration. The PPP Loan to the Company is being made through JPMorgan Chase Bank, N.A and is included in “Long-Term Debt” on the Company’s consolidated balance sheet. The PPP Loan matures on the two-year anniversary of the funding date and bears interest at a fixed rate of 1.00% per annum. Monthly principal and interest payments, less the amount of any potential forgiveness (discussed below), will commence after the six-month anniversary of the funding date. The promissory note evidencing the PPP Loan provides for customary events of default, including, among others, those relating to failure to make payment, bankruptcy, breaches of representations and material adverse effects. The Company may prepay the principal of the PPP Loan at any time without incurring any prepayment charges. Under the terms of the CARES Act, PPP loan recipients can apply for and be granted forgiveness for all or a portion of the loans granted under the PPP, subject to an audit. Under the CARES Act, loan forgiveness is available, subject to limitations, for the sum of documented payroll costs, covered mortgage interest payments, covered rent payments and covered utilities during either: (1) the eight-week period beginning on the funding date; or (2) the 24-week period beginning on the funding date. Forgiveness is reduced if full-time employee headcount declines, or if salaries and wages for employees with salaries of $100,000 or less annually are reduced by more than 25%. The Company utilized the PPP Loan amount for qualifying expenses during the 24-week coverage period, and on September 30, 2020, submitted its application for forgiveness of all of the PPP Loan in accordance with the terms of the CARES Act and related guidance. The Company is currently awaiting a response from the Small Business Administration. In the event the PPP Loan or any portion thereof is forgiven, the amount forgiven is applied to the outstanding principal.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2020
Commitments And Contingencies [Abstract]
Commitments and Contingencies	14. Commitments and Contingencies Contango leases its office space, compressors, vehicles and certain other equipment, which are considered operating and finance leases. See Note 9 – “Leases” for more information. The Company also incurs commitments on its oil and natural gas leases, such as delay rentals, surface damage payments and rental payments associated with salt water disposal contracts. As of December 31, 2020, minimum future operating and finance lease payments and other commitments listed above for Contango’s fiscal years are as follows (in thousands): Fiscal years ending December 31, 2021 $ 3,941 2022 2,163 2023 1,872 2024 1,496 2025 and thereafter 879 Total $ 10,351 The amounts incurred under operating and finance leases and payments related to delay rentals, surface use and salt water disposal contracts during the years ended December 31, 2020 and 2019 were approximately $4.3 million and $1.5 million, respectively. The increase in 2020 payments is due to the properties acquired in the Will Energy Acquisition and the White Star Acquisition. Throughput Contract Commitment The Company had a signed a throughput agreement with a third-party pipeline owner/operator that constructed a natural gas gathering pipeline in Southeast Texas that allowed the Company to defray the cost of building the pipeline itself. Beginning in late 2016, the Company was unable to meet the minimum monthly gas volume deliveries through this line in Southeast Texas and continued to not meet the minimum throughput requirements under the agreement through the expiration of the throughput commitment on March 31, 2020. As of December 31, 2019, the Company recorded a $1.0 million loss contingency through the end of the contract in March 2020, which was paid in three equal monthly installments in 2020. As the remaining throughput commitment fees of $1.0 million were accrued during the year ended December 31, 2019, the Company incurred no expense related to this commitment in 2020. Legal Proceedings From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below. On November 16, 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by the Company or by predecessor operators to which the Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decades-old poorly documented transactions. Based on prior summary judgments, the trial court entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company appealed the trial court’s decision to the applicable state Court of Appeals, and in the fourth quarter of 2017, the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. In the first quarter of 2018, the Company filed a motion for rehearing with the Court of Appeals, which was denied, as expected. The Company filed a petition requesting a review by the Texas Supreme Court, as the Company believes the trial and appellate courts erred in the interpretation of the law. In early October 2019, the Texas Supreme Court notified the Company that it would not hear this case. The Company engaged additional legal representation to assist in the preparation of an amended petition requesting that the Texas Supreme Court reconsider its initial decision to not review the case. That amended petition was filed, and in mid-March 2020, the Texas Supreme Court decided they would not re-hear the case. Consequently, during the three months ended December 31, 2019, the Company recorded a $6.3 million liability for the judgment, interest and fees, with $3.5 million of such liability related to suspended funds reflected in “Accounts payable and accrued liabilities” on the Company’s consolidated balance sheet for the year ended December 31, 2019. The judgment, interest and fees were paid in April 2020. On January 14, 2016, the Company was named as the defendant in a lawsuit filed in the District Court for Harris County in Texas by a third-party operator. The Company participated in the drilling of a well in 2012, which experienced serious difficulties during the initial drilling, which eventually led to the plugging and abandoning of the wellbore prior to reaching the target depth. In dispute is whether the Company is responsible for the additional costs related to the drilling difficulties and plugging and abandonment. In September 2019, the case went to trial, and, in October 2019, the court ruled in favor of the plaintiff. Prior to the judgment, the Company had approximately $1.1 million in accounts payable related to the disputed costs associated with this case. As a result of the judgment, during the three months ended September 30, 2019, the Company recorded an additional $2.1 million liability for the final judgment plus fees and interest. The Company also prepared and filed an appeal with the appellate court for a review of the initial trial court decision The plaintiff petitioned the appellate court for an extension of time to file briefs with the court until late in the fourth quarter of 2020. On January 23, 2021, the appellate court notified both parties that it would begin reviewing the merits of the case beginning on February 23, 2021. On March 3, 2021, the appellate court affirmed the trial court’s decision. The Company plans to appeal the decision to the Supreme Court. While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various insurance policies that may provide coverage when certain types of legal proceedings are determined adversely.

Net Loss Per Common Share

Net Loss Per Common Share	12 Months Ended
	Dec. 31, 2020
Net Loss Per Common Share
Net Loss Per Common Share	15. Net Loss Per Common Share A reconciliation of the components of basic and diluted net loss per common share for the years ended December 31, 2020 and 2019 is presented below (in thousands): Year Ended December 31, 2020 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (165,342) 137,522 $ (1.20) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $ (165,342) 137,522 $ (1.20) Year Ended December 31, 2019 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (159,796) 54,136 $ (2.95) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $ (159,796) 54,136 $ (2.95) The numerator for basic earnings per share is net loss attributable to common stockholders. The numerator for diluted earnings per share is net loss available to common stockholders. Potential dilutive securities (stock options, restricted stock and PSUs) have not been considered when their effect would be antidilutive. The potentially dilutive shares would have been 529,508 shares and 613,506 shares for the years ended December 31, 2020 and 2019, respectively.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Taxes [Abstract]
Income Taxes	16. Income Taxes Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statements and income tax reporting. Numerous judgments and assumptions are inherent in the determination of deferred income tax assets and liabilities as well as income taxes payable in the current period. The Company is subject to taxation in several jurisdictions, and the calculation of its tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions. Income Tax Computation Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate rate of 21 percent for the years ended December 31, 2020 and 2019, respectively, to pretax income as follows (dollars in thousands): Year Ended December 31, 2020 2019 Benefit at statutory tax rate $ (34,663) 21.00 % $ (33,561) 21.00 % State income tax provision, net of federal benefit 467 (0.28) % 555 (0.35) % State deferred tax benefit (5,553) 3.36 % — — % Permanent differences 26 (0.02) % 30 (0.02) % Stock based compensation 81 (0.05) % 979 (0.61) % Valuation allowance 40,059 (24.27) % 34,239 (21.42) % Other 330 (0.20) % (2,022) 1.26 % Income tax provision $ 747 (0.46) % $ 220 (0.14) % The effective tax rate for the years ended December 31, 2020 and 2019 varies from the statutory rate primarily as a result of recording a valuation allowance. The provision (benefit) for income taxes for the periods indicated are comprised of the following (in thousands): Year Ended December 31, 2020 2019 Current tax provision (benefit): Federal $ 275 $ (335) State 472 555 Total $ 747 $ 220 Deferred tax benefit: Federal $ — $ — State — — Total $ — $ — Total tax provision (benefit): Federal $ 275 $ (335) State 472 555 Total $ 747 $ 220 Included in gain from investment in affiliates $ — $ — Total income tax provision $ 747 $ 220 The Federal income tax expense results from an adjustment in the previous period of the credit for Alternative Minimum Tax (“AMT”) paid in prior years. As a result of the tax reform in 2017, the corporate AMT was repealed, and any AMT credit was made refundable. The first half of the credit was refunded when the Company filed its 2018 federal income tax return, and the second half of the credit was refunded when the Company filed its 2019 federal tax return. The CARES Act modified the timing of these refunds, allowing the Company to request an expedited refund of $0.3 million during the quarter ended June 30, 2020. This amount was previously accounted for as an income tax benefit when the corporate AMT was repealed. State income tax expense relates to income taxes for the quarter and the nine months which are expected to be owed to the states of Louisiana and Oklahoma resulting from activities within those states and, in each case, that are not shielded by existing Federal tax attributes. Additionally, under the CARES Act, the Company will benefit from an amendment to Internal Revenue Code Section 163(j) that temporarily increases deductible interest expense limitations. Specifically, the CARES Act increases the 30% Adjusted Taxable Income (“ATI”) limitation to 50% of ATI for taxable years beginning in each of 2019 and 2020. This will have the effect of allowing the Company to use a Section 163(j) carryover from the prior year that was not limited by Section 382 (discussed below). The Company does not expect to benefit from any other income tax-related provisions of the CARES Act. The net deferred tax is comprised of the following (in thousands): December 31, 2020 2019 Deferred tax assets: Net operating loss carryforward $ 84,982 $ 80,617 Deferred compensation 447 — Derivative instruments — 377 State deferred tax assets 6,507 954 Oil and gas properties 39,081 11,436 Investment in affiliates 752 2,799 Recognized built in loss carryforward 9,987 6,718 163(j) Carryforward 1,828 1,585 Other 1,796 964 Total deferred tax assets before valuation allowance $ 145,380 $ 105,450 Valuation allowance (145,269) (105,212) Net deferred tax assets $ 111 $ 238 Deferred tax liability: Deferred compensation $ — $ (238) Derivative instruments (111) — Deferred tax liability $ (111) $ (238) Total net deferred tax $ — $ — Accounting for uncertainty in income taxes prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the amount of deferred tax liabilities, level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, the Company believes it is not more-likely-than-not that it will realize the benefits of these deductible differences and has recorded a valuation allowance for federal and state purposes of approximately $138.8 million and approximately $6.5 million, respectively. As of December 31, 2020, the Company had federal net operating loss (“NOL”) carryforwards of approximately $404.7 million and state NOLs of $26.4 million. The Federal NOL carryforwards are made up of: (i) those acquired in the merger with Crimson Exploration, Inc. (“Crimson”) in 2013 (the “Merger”) and (ii) from subsequent taxable losses during the years 2014 through 2020 due to lower commodity prices and utilization of various elections available to the Company in expensing capital expenditures incurred in the development of oil and natural gas properties. Generally, these NOLs are available to reduce future taxable income and the related income tax liability subject to the limitations set forth in Internal Revenue Code Section 382 related to changes of more than 50% of ownership of the Company’s stock by 5% or greater shareholders over a three-year period (a Section 382 Ownership Change) from the time of such an ownership change. Recently passed legislation, however, temporarily suspends the Section 172 limitation for NOLs arising in a tax year beginning in 2018, 2019 or 2020 and also allows these NOLs to be carried back five years. On November 19, 2018, the Company completed a follow-on offering (the “2018 Offering”) of 7.5 million additional shares of common stock. Prior to December 18, 2018, the underwriters exercised their Green Shoe option purchasing an additional approximate 1.1 million shares, resulting in a total of approximately 8.6 million primary shares issued in the Offering. This issuance resulted in a Section 382 Ownership Change (the “2018 Ownership Change”) which limits the Company’s future ability to use its NOLs. As such, the Company is limited in use of NOLs for amounts incurred prior to November 20, 2018 in an amount estimated to be approximately $2.4 million per year (plus any recognized built in gains during the next five years) or until expiration of each annual vintage of NOL (generally, 20 years for each annual vintage of NOLs incurred prior to 2018). On September 12, 2019, as discussed in Note 1 – “Organization and Business”, the Company completed the September 2019 Public Offering which also resulted in a Section 382 Ownership Change on that date (the “2019 Ownership Change” and, together with the 2018 Ownership Change, the “Ownership Changes”). Due to changing market conditions, the Company’s ability to utilize pre-2018 NOLs on that date could be limited to $700,000 a year (in pre-tax dollars). This lower annual limitation resulting from the 2019 Ownership Change effectively eliminates the ability to utilize these tax attributes in the future. The Company is also affected by the limitation in Section 163(j) on interest taken in any given tax year. As of December 31, 2020, the Company had a limitation of $2.4 million which will carry over indefinitely. Additionally, the Company’s post-2017 NOLs of $132.7 million are also not subject to expiration, but are limited to offsetting 80% of the Company’s taxable income in any year of usage after December 31, 2020. These carryovers are subject to any applicable Section 382 limitation (discussed above). As a result of the Ownership Changes, the Company has recorded a valuation allowance against substantially all of its NOLs and other deferred tax assets. The valuation allowance balance at December 31, 2020 is $145.3 million. ASC 740, Income Taxes (“ASC 740”) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. As a result of the Merger, the Company acquired certain tax positions taken by Crimson in prior years. These positions are not expected to have a material impact on results of operations, financial position or cash flows. A reconciliation of the beginning and ending amount of unrecognized income tax benefits is as follows (in thousands): Unrecognized Tax Benefits Balance at December 31, 2019 $ — Additions based on tax positions related to the current year — Additions based on tax positions related to prior years — Additions due to acquisitions — Reductions due to a lapse of the applicable statute of limitations — Change in rate due to remeasurement — Balance at December 31, 2020 $ — The Company’s policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense) in the Company’s consolidated statements of operations. The Company had no interest or penalties related to unrecognized tax benefits for the year ended December 31, 2020 or any prior years. The total amount of unrecognized tax benefit, if recognized, that would affect the effective tax rate was zero. Generally, the Company’s income tax years of 2009 through 2020 remain open and subject to examination by Federal tax authorities, and the tax years of 2009 through 2020 remain open and subject to examination by the tax authorities in Texas, Louisiana and Oklahoma, which are the jurisdictions where the Company carries its principal operations. These audits can result in adjustments of taxes due or adjustments of the NOL carryforwards that are available to offset future taxable income. The Company currently has no ongoing tax audits and has not been notified of pending activity by taxing jurisdictions. The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of the statute of limitations prior to December 31, 2020.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent Events	17. Subsequent Events Mid-Con Acquisition On January 21, 2021, the Company closed the Mid-Con Acquisition in an all-stock merger transaction. At the time of close, each common unit representing limited partner interests in Mid-Con issued and outstanding (other than treasury units or units held by Mid-Con GP) was converted automatically into the right to receive 1.75 shares of the Company’s common stock. A total of 25,409,164 shares of Contango common stock were issued at the closing of the Mid-Con Acquisition. See Note 4 – “Acquisitions and Dispositions” for more information. Silvertip Acquisition On February 1, 2021, the Company closed the Silvertip Acquisition to acquire certain oil and natural gas properties located in the Big Horn Basin in Wyoming and Montana, in the Powder River Basin in Wyoming and in the Permian Basin in Texas and New Mexico, for aggregate consideration of approximately $58 million in cash. The Company previously paid a $7.0 million deposit during the three months ended December 31, 2020, in connection with the execution of the purchase agreement, and a balance of $46.2 million was paid upon closing of the Silvertip Acquisition, after customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date. See Note 4 – “Acquisitions and Dispositions” for more information.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
Summary Of Significant Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly-owned subsidiaries are consolidated.
Subsidiary Guarantees	Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Contango Resources, Inc., Contango Midstream Company, Contango Operators, Inc., Contaro Company, Contango Alta Investments, Inc. and any other of the Company’s future subsidiaries specified in the prospectus supplement (each a “Subsidiary Guarantor”) are Co-Registrants with the Parent Company under the registration statement, and the registration statement also registered guarantees of debt securities by the Subsidiary Guarantors. The Subsidiary Guarantors are wholly-owned by the Parent Company, either directly or indirectly, and any guarantee by the Subsidiary Guarantors will be full and unconditional. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. Finally, the Parent Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party.
Other Investments	Other Investments The Company has two seats on the board of directors of Exaro and has significant influence, but not control, over the company. As a result, the Company’s 37% ownership in Exaro is accounted for using the equity method. Under the equity method, the Company’s proportionate share of Exaro's net income increases the balance of its investment in Exaro, while a net loss or payment of dividends decreases its investment. In the consolidated statements of operations, the Company’s proportionate share of Exaro's net income is reported as a single line-item in “Gain from investment in affiliates” (net of income taxes).
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.
Revenue Recognition	Revenue Recognition Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Based upon the Company’s past experience with its current purchasers and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the past year or currently. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the Company’s gas at the inlet of the plant, and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. When sales volumes exceed the Company’s entitled share, a production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. Production imbalances have not had and currently do not have a material impact on the financial statements. Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company receives purchaser statements from the majority of its customers, but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice. The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the following month that payment is received. Any differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process. The Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment.
Cash Equivalents	Cash Equivalents Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of December 31, 2020, the Company had $1.4 million in cash and cash equivalents, after transferring cash balances at the end of each day to reduce outstanding debt under the Company’s revolving Credit Agreement to minimize debt service costs. Under the Company’s cash management system, checks issued but not yet presented to banks by the payee frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the consolidated balance sheets. At December 31, 2020, accounts payable included $2.9 million in outstanding checks that had not been presented for payment. At December 31, 2019, accounts payable included $6.1 million in outstanding checks that had not been presented for payment.
Accounts Receivable	Accounts Receivable The Company sells oil, natural gas and NGLs to a limited number of customers. In addition, the Company participates with other parties in the operation of oil and natural gas wells. Substantially all of the Company’s accounts receivables are due from either purchasers of oil, natural gas and NGLs or participants in oil and natural gas wells for which the Company serves as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions and other pertinent factors. Amounts deemed uncollectible are charged to the allowance. Accounts receivable allowance for doubtful accounts was $2.3 million and $1.0 million as of December 31, 2020 and 2019, respectively. At December 31, 2020 and 2019, the carrying value of the Company’s accounts receivable approximated fair value.
Oil and Gas Properties - Successful Efforts	Oil and Natural Gas Properties - Successful Efforts The Company follows the successful efforts method of accounting for its oil and natural gas activities. The Company’s application of the successful efforts method of accounting for its oil and natural gas exploration and production activities requires judgment as to whether particular wells are developmental or exploratory, since lease acquisition costs and all developmental costs are capitalized, whereas exploratory drilling costs are continuously capitalized until the results are determined. If proved reserves are not discovered, the drilling costs are expensed as exploration costs. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil or natural gas field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory. During the quarter ended June 30, 2020, the Company drilled an unsuccessful exploratory well in the Gulf of Mexico, resulting in a charge of $10.5 million for drilling and prospect costs included in “Exploration expenses” in the Company’s consolidated statements of operations for the year ended December 31, 2020. The evaluation of oil and natural gas leasehold acquisition costs included in unproved properties requires management’s judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions. Depreciation, depletion and amortization ("DD&A") is calculated on a field basis using the unit of production method. Lease acquisition costs are amortized over remaining total proved reserves, and capitalized drilling and development costs of producing oil and natural gas properties, including related support equipment and facilities net of salvage value, are amortized over estimated proved developed oil and natural gas reserves. Upon sale or retirement of properties, the cost and related accumulated DD&A are eliminated from the accounts, and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least annually. Revisions are accounted for prospectively as changes in accounting estimates. Other property and equipment are depreciated using the straight-line method over their estimated useful lives which range between three and 10 years.
Impairment of Long-Lived Assets	Impairment of Oil and Natural Gas Properties Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field-by-field basis to the unamortized capitalized cost of the assets in that field. If the estimated future undiscounted cash flows, based on the Company’s estimate of future reserves, oil and natural gas prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. Additionally, the Company may use appropriate market data to determine fair value. In the first quarter of 2020, the COVID-19 pandemic and the resulting deterioration in the global demand for oil, combined with the failure by OPEC and Russia to reach an agreement on lower production quotas until April 2020, caused a dramatic increase in the supply of oil, a corresponding decrease in commodity prices, and reduced the demand for all commodity products. The remainder of 2020 was further adversely affected by the continuation of the COVID-19 pandemic and the actions and measures that countries, states, localities, central banks, international financing and funding organizations, stock markets, businesses and individuals have taken to address the spread of the coronavirus and associated illnesses, the continued volatility of the oil and gas market, and the failure of OPEC and Russia to consistently and fully adhere to the quotas delineated in their agreement. Consequently, during the three months ended March 31, 2020, the Company recorded a $143.3 million non-cash charge for proved property impairment of its onshore properties related to the dramatic decline in commodity prices, the “PV-10” (present value, discounted at a 10% rate) of its proved reserves, and the associated change in its current development plans for its proved undeveloped locations. In the fourth quarter of 2020, the Company recorded an additional $21.1 million non-cash charge for proved property impairment, of which $15.6 million related to its offshore properties as a result of performance revisions in reserves and the decline in gas prices and production yield. The total non-cash proved property impairment recorded during the year ended December 31, 2020 was $164.4 million. For the year ended December 31, 2019, the Company recognized non-cash proved property impairment expense of $117.8 million due to reserve revisions which resulted from the negative impact of performance and price related revisions to the present value of the Company’s year-end proved reserves, and the relationship of that value to the historical carrying cost of its assets on the balance sheet. Included in the impairment charge was $34.5 million related to the Company’s proved offshore Gulf of Mexico properties, primarily a result of performance revisions associated with the re-evaluation of the projected field costs and recoverable condensate volumes. In addition, the Company recognized onshore proved property impairment expense of $83.3 million. The onshore impairment was due primarily to price and performance revisions, which led to the re-evaluation of the economics and future drilling plans for the proved undeveloped locations, which then resulted in the elimination of certain proved undeveloped locations due to the SEC’s five-year development rule for such locations. Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, with any such impairment charged to expense in the period. During the year ended December 31, 2020, the Company recorded a $4.3 million non-cash charge for unproved impairment expense related to undeveloped leases in its Central Oklahoma, Western Anadarko and Other Onshore regions. The Company recorded $2.6 million of this impairment expense in the first quarter of 2020, primarily related to leases the Company acquired from White Star and Will Energy in the fourth quarter of 2019, which were expiring in 2020, and the remaining $1.7 million of the impairment expense was recorded in the fourth quarter of 2020, due to leases expiring in 2021, all of which the Company has no plans to extend or develop as a result of the current commodity price environment and the Company’s continued focus on cost saving and production enhancing strategic initiatives. During the year ended December 31, 2019, the Company recognized impairment expense of approximately $9.2 million related primarily to lease expirations, and near-term expirations, in the Company’s West Texas region.
Asset Retirement Obligations	Asset Retirement Obligations Asset Retirement and Environmental Obligations (“ASC 410”) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records an asset retirement obligation (“ARO”) to reflect the Company’s legal obligation related to future plugging and abandonment of its oil and natural gas wells, platforms and associated pipelines and equipment. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis, the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, platforms, and associated pipelines and equipment as these obligations are incurred. The liability is accreted to its present value each period, and the capitalized cost is depleted over the useful life of the related asset. The accretion expense is included in DD&A expense. The estimated liability is based on historical experience in plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free rate, changes in the remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, the Company recognizes a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs. This gain or loss on abandonment is included in impairment and abandonment of oil and natural gas properties expense. See Note 12 – “Asset Retirement Obligation” for additional information.
Income Taxes	Income Taxes The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. The Company reviews its tax positions quarterly for tax uncertainties. The Company did not have significant uncertain tax positions as of December 31, 2020. As described in Note 16 – “Income Taxes” with respect to Section 382 Ownership Change, the amount of unrecognized tax benefits did not change materially from December 31, 2019 . The amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect the change to have a significant impact on its financial position or results of operations. The Company includes interest and penalties in interest income and general and administrative expenses, respectively, in its consolidated statements of operations. The Company files income tax returns in the United States and various state jurisdictions. The Company’s federal and state tax returns for 2009 – 2020 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed.
Concentration of Credit Risk	Concentration of Credit Risk Substantially all of the Company’s accounts receivable result from oil and natural gas sales or joint interest billings to a limited number of third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. See Note 3 – “Concentration of Credit Risk” for additional information.
Debt Issuance Costs	Debt Issuance Costs Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt. On September 17, 2019, the Company entered into the new revolving Credit Agreement with JPMorgan Chase Bank, N.A. and other lenders and incurred $1.8 million of arrangement and upfront fees in connection with the Credit Agreement. On November 1, 2019, the Credit Agreement was amended to add two additional lenders and increase the borrowing base thereunder, and the Company incurred an additional $1.6 million of debt issuance costs. On June 9, 2020, the Credit Agreement was amended to, among other things, reduce the borrowing base. No fees were incurred for the Second Amendment; however, during the three months ended June 30, 2020, the Company expensed $1.0 million of the debt issuance costs discussed above which originally were to be amortized over the life of the loan, due to the reduction in the borrowing base per the Second Amendment. On October 30, 2020, the Company entered into the Third Amendment to the Credit Agreement under which, among other things, increased the Company’s borrowing base from $75.0 million to $130.0 million, effective upon the closing of the Mid-Con Acquisition on January 21, 2021. The Company initially incurred $0.1 million in fees related to the Third Amendment during the three months ended December 31, 2020. During the year ended December 31, 2020, the Company amortized debt issuance costs of $1.6 million related to its Credit Agreement, including the $1.0 million mentioned above. As of December 31, 2020, the remaining balance of these debt issuance costs was $1.8 million, which will be amortized through September 17, 2024, with amortization expense included in the interest expense line item in the Company’s consolidated statements of operations. In January 2021, the Company incurred an additional $0.9 million in fees related to the Third Amendment becoming effective on January 21, 2021, in connection with the closing of the Mid-Con Acquisition. These fees will also be amortized over the remaining term of the loan.
Stock-Based Compensation	Stock-Based Compensation The Company applies the fair value based method to account for stock based compensation. Under this method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the requisite service period, which generally aligns with the award vesting period. The Company classifies the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) as financing cash flows. The fair value of each restricted stock award is estimated as of the date of grant. The fair value of the performance stock units is estimated as of the date of grant using the Monte Carlo simulation pricing model.
Inventory	Inventory Inventory consists primarily of casing and tubing stored temporarily, which will be used for drilling or completion of wells. Inventory is recorded at the lower of cost or market using specific identification method.
Derivatives Instruments and Hedging Activities	Derivative Instruments and Hedging Activities The Company accounts for its derivative activities under the provisions of ASC 815, Derivatives and Hedging (“ASC 815”). ASC 815 establishes accounting and reporting requirements that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, the Company hedges a portion of its forecasted oil and natural gas production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction using variable to fixed swaps and collars. The Company elected to not designate any of its derivative positions for hedge accounting. Accordingly, the net change in the mark-to-market valuation of these positions as well as all payments and receipts on settled derivative contracts are recognized in “Gain (loss) on derivatives, net” on the consolidated statements of operations for the years ended December 31, 2020 and 2019. Derivative instruments with settlement dates within one year are included in current assets or liabilities, whereas derivative instruments with settlement dates exceeding one year are included in non-current assets or liabilities. The Company calculates the asset or liability for current and non-current derivative instruments for each counterparty based on the settlement dates within the respective contracts. See Note 6 – “Derivative Instruments” for additional information.
Leases	Leases The Company recognizes a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term on the Company’s consolidated balance sheet. The Company does not include leases with an initial term of twelve months or less on the balance sheet. The Company recognizes payments on these leases within “Operating expenses” on its consolidated statements of operations. The Company accounts for lease and non-lease contract components as a lease. The Company has procedures to review any new or modified contracts which contain a physical asset on a quarterly basis and determine if an arrangement is, or contains, a lease and determines the proper treatment. See Note 9 – “Leases” for additional information.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In June 2016, the FASB issued ASU 2016-13 - Financial Instruments - Credit Losses (“Topic 326”): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint interest billing receivables. Allowances are to be measured using a current expected credit loss model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. Initially, ASU 2016-13 was effective for all public companies for fiscal years beginning after December 15, 2019. The FASB subsequently issued ASU 2019-04 (“ASU 2019-04”): Codification Improvements to Topic 326, Financial Instruments - Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments and ASU 2019-05 (“ASU 2019-05”): Financial Instruments - Credit Losses (Topic 326) - Targeted Transition Relief. ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to the implementation of ASU 2016-13 and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments. In November 2019, the FASB issued ASU 2019-10 - Financial Instruments - Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates. This amendment deferred the effective date of ASU 2016-13 from January 1, 2020 to January 1, 2023 for calendar year-end smaller reporting companies, which includes the Company. The Company plans to defer the implementation of ASU 2016-13, and the related updates. In November 2019, the FASB issued ASU 2019-12 - Income Taxes (“Topic 740”): Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The amendments in ASU 2019-12 are part of an initiative to reduce complexity in accounting standards and simplify the accounting for income taxes by removing certain exceptions from Topic 740 and making minor improvements to the codification. The amendments in this update are effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations. In March 2020, the FASB issued ASU 2020-04 - Reference Rate Reform (“Topic 848”): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional guidance, for a limited period of time, to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. The amendments in ASU 2020-04 provide optional expedients and exceptions for applying US GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this ASU apply only to contracts, hedging relationships and other transactions that reference LIBOR, or another reference rate, expected to be discontinued because of reference rate reform. The Company is currently assessing the potential impact of ASU 2020-04 on its consolidated financial statements.

Acquisitions and Dispositions (

Acquisitions and Dispositions (Tables)	12 Months Ended
	Dec. 31, 2020
Mid-Con [Member]
Schedule of assets acquired and liabilities assumed	Purchase Price Allocation (in thousands) Consideration: Cash $ 14,520 Exchange ratio of Contango shares for Mid-Con common units 1.75 Contango common stock to be issued to Mid-Con unitholders 25,409 Issue price 3.13 Total consideration $ 79,530 Liabilities Assumed: Accounts payable $ 5,596 Other current liabilities 457 Revolving credit facility 68,487 Asset retirement obligations 29,241 Total liabilities assumed $ 103,781 Assets acquired: Cash and cash equivalents $ 776 Accounts receivable 4,398 Current derivative asset 3,141 Prepaid expenses 162 Proved oil and natural gas properties 172,607 Other property and equipment 730 Other non-current assets 1,497 Total assets acquired $ 183,311
Schedule of pro forma information	(In thousands except for per share amounts) Year Ended December 31, 2020 Revenues $ 150,569 Net loss $ (188,178) Basic Earnings per share $ (1.02) Diluted earnings per share $ (1.02)
White Star [Member]
Schedule of assets acquired and liabilities assumed	Purchase Price Allocation (in thousands) Consideration: Cash $ 95,722 Total consideration $ 95,722 Liabilities Assumed: Accounts payable $ 6,618 Revenue and royalties payable 11,165 Suspended revenue and royalties 22,011 Lease liabilities 3,614 Total liabilities assumed $ 43,408 Assets acquired: Accounts receivable $ 18,037 Other current assets 1,413 Proved oil and natural gas properties 113,150 Unevaluated properties 2,611 Right-of-use lease assets 3,614 Other assets 305 Total assets acquired $ 139,130
Schedule of pro forma information	(In thousands except for per share amounts) Year Ended December 31, 2019 Revenues $ 207,530 Net loss $ (265,760) Basic Earnings per share $ (4.20) Diluted earnings per share $ (4.20)

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2020
Schedule Of Derivative Contracts	Commodity Period Derivative Volume/Month Price/Unit Fair Value Oil Jan 2021 - March 2021 Swap 19,000 Bbls $ 50.00 (1) 78 Oil April 2021 - July 2021 Swap 12,000 Bbls $ 50.00 (1) 71 Oil Aug 2021 - Sept 2021 Swap 10,000 Bbls $ 50.00 (1) 39 Oil Jan 2021 - July 2021 Swap 62,000 Bbls $ 52.00 (1) 1,490 Oil Aug 2021 - Sept 2021 Swap 55,000 Bbls $ 52.00 (1) 434 Oil Oct 2021 - Dec 2021 Swap 64,000 Bbls $ 52.00 (1) 840 Oil April 2022 - Oct 2022 Swap 25,000 Bbls $ 42.04 (1) (784) Natural Gas Jan 2021 - March 2021 Swap 185,000 MMBtus $ 2.505 (2) (1) Natural Gas April 2021 - July 2021 Swap 120,000 MMBtus $ 2.505 (2) (43) Natural Gas Aug 2021 - Sept 2021 Swap 10,000 MMBtus $ 2.505 (2) (4) Natural Gas Jan 2021 - March 2021 Swap 185,000 MMBtus $ 2.508 (2) (3) Natural Gas April 2021 - July 2021 Swap 120,000 MMBtus $ 2.508 (2) (44) Natural Gas Aug 2021 - Sept 2021 Swap 10,000 MMBtus $ 2.508 (2) (4) Natural Gas Jan 2021 - March 2021 Swap 650,000 MMBtus $ 2.508 (2) (6) Natural Gas April 2021 - Oct 2021 Swap 400,000 MMBtus $ 2.508 (2) (400) Natural Gas Nov 2021 - Dec 2021 Swap 580,000 MMBtus $ 2.508 (2) (402) Natural Gas April 2021 - Nov 2021 Swap 70,000 MMBtus $ 2.36 (2) (175) Natural Gas Dec 2021 Swap 350,000 MMBtus $ 2.36 (2) (195) Natural Gas Jan 2022 - March 2022 Swap 780,000 MMBtus $ 2.542 (2) (865) Natural Gas April 2022 - July 2022 Swap 650,000 MMBtus $ 2.515 (2) 252 Natural Gas Aug 2022 - Oct 2022 Swap 350,000 MMBtus $ 2.515 (2) 71 Natural Gas Jan 2022 - March 2022 Swap 250,000 MMBtus $ 3.149 (2) 179 Total net fair value of derivative instruments (in thousands) $ 528 (1) Based on West Texas Intermediate oil prices. (2) Based on Henry Hub NYMEX natural gas prices. The Company had the following financial derivative contracts in place as of December 31, 2019: Commodity Period Derivative Volume/Month Price/Unit Fair Value Oil Jan 2020 - June 2020 Swap 22,000 Bbls $ 57.74 (1) (289) Oil July 2020 - Dec 2020 Swap 15,000 Bbls $ 57.74 (1) 68 Oil Jan 2020 - March 2020 Swap 2,700 Bbls $ 54.33 (1) (51) Oil April 2020 - June 2020 Swap 2,500 Bbls $ 54.33 (1) (37) Oil July 2020 Swap 5,500 Bbls $ 54.33 (1) (21) Oil Aug 2020 - Oct 2020 Swap 2,500 Bbls $ 54.33 (1) (21) Oil Nov 2020 - Dec 2020 Swap 3,500 Bbls $ 54.33 (1) (12) Oil Jan 2020 - Feb 2020 Swap 42,500 Bbls $ 54.70 (1) (517) Oil March 2020 - July 2020 Swap 37,500 Bbls $ 54.70 (1) (842) Oil Aug 2020 - Dec 2020 Swap 35,000 Bbls $ 54.70 (1) (354) Oil Jan 2020 - Feb 2020 Swap 42,500 Bbls $ 54.58 (1) (527) Oil March 2020 - July 2020 Swap 37,500 Bbls $ 54.58 (1) (864) Oil Aug 2020 - Dec 2020 Swap 35,000 Bbls $ 54.58 (1) (373) Oil Jan 2020 - Oct 2020 Collar 3,442 Bbls $ 52.00 - 65.70 (1) 18 Oil Jan 2021 - March 2021 Swap 19,000 Bbls $ 50.00 (1) (291) Oil April 2021 - July 2021 Swap 12,000 Bbls $ 50.00 (1) (196) Oil Aug 2021 - Sept 2021 Swap 10,000 Bbls $ 50.00 (1) (67) Oil Jan 2021 - July 2021 Swap 62,000 Bbls $ 52.00 (1) (1,122) Oil Aug 2021 - Sept 2021 Swap 55,000 Bbls $ 52.00 (1) (157) Oil Oct 2021 - Dec 2021 Swap 64,000 Bbls $ 52.00 (1) (184) Natural Gas Jan 2020 - March 2020 Swap 425,000 MMBtus $ 2.841 (2) 856 Natural Gas Jan 2020 - March 2020 Collar 225,000 MMBtus $ 2.45 - 3.40 (2) 209 Natural Gas April 2020 - July 2020 Swap 400,000 MMBtus $ 2.532 (2) 493 Natural Gas Aug 2020 - Oct 2020 Swap 40,000 MMBtus $ 2.532 (2) 25 Natural Gas Nov 2020 - Dec 2020 Swap 375,000 MMBtus $ 2.696 (2) 134 Natural Gas Jan 2020 - March 2020 Swap 300,000 MMBtus $ 2.53 (2) 325 Natural Gas April 2020 - July 2020 Swap 400,000 MMBtus $ 2.53 (2) 490 Natural Gas Aug 2020 - Dec 2020 Swap 350,000 MMBtus $ 2.53 (2) 223 Natural Gas Jan 2020 - March 2020 Swap 300,000 MMBtus $ 2.532 (2) 327 Natural Gas April 2020 - July 2020 Swap 400,000 MMBtus $ 2.532 (2) 493 Natural Gas Aug 2020 - Dec 2020 Swap 350,000 MMBtus $ 2.532 (2) 226 Natural Gas Jan 2021 - March 2021 Swap 185,000 MMBtus $ 2.505 (2) (78) Natural Gas April 2021 - July 2021 Swap 120,000 MMBtus $ 2.505 (2) 99 Natural Gas Aug 2021 - Sept 2021 Swap 10,000 MMBtus $ 2.505 (2) 4 Natural Gas Jan 2021 - March 2021 Swap 185,000 MMBtus $ 2.508 (2) (75) Natural Gas April 2021 - July 2021 Swap 120,000 MMBtus $ 2.508 (2) 104 Natural Gas Aug 2021 - Sept 2021 Swap 10,000 MMBtus $ 2.508 (2) 4 Natural Gas Jan 2021 - March 2021 Swap 650,000 MMBtus $ 2.508 (2) (268) Natural Gas April 2021 - Oct 2021 Swap 400,000 MMBtus $ 2.508 (2) 544 Natural Gas Nov 2021 - Dec 2021 Swap 580,000 MMBtus $ 2.508 (2) 20 Total net fair value of derivative instruments (in thousands) $ (1,684) (1) Based on West Texas Intermediate oil prices. (2) Based on Henry Hub NYMEX natural gas prices.
Schedule Of Fair Value Of Commodity Derivatives	The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2020 (in thousands). Gross Netting (1) Total Assets $ 3,493 $ — $ 3,493 Liabilities $ (2,965) $ — $ (2,965) (1) Represents counterparty netting under agreements governing such derivatives. Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset or liability” on the Company’s consolidated balance sheet and include swaps that are carried at fair value. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2019 (in thousands). Gross Netting (1) Total Assets $ 4,176 $ — $ 4,176 Liabilities $ (5,971) $ — $ (5,971) (1) Represents counterparty netting under agreements governing such derivatives.
Schedule Of Derivative Contracts On Operations	The following table summarizes the effect of derivative contracts on the Consolidated Statements of Operations for the years ended December 31, 2020 and 2019 (in thousands): Year Ended December 31, Contract Type 2020 2019 Crude oil contracts $ 18,561 $ 1,614 Natural gas contracts 6,703 1,002 Realized gain $ 25,264 $ 2,616 Crude oil contracts $ 8,120 $ (10,012) Natural gas contracts (5,799) 4,039 Unrealized gain (loss) $ 2,321 $ (5,973) Gain (loss) on derivatives, net $ 27,585 $ (3,357)
Subsequent Derivative Contracts [Member]
Schedule Of Derivative Contracts	In the first quarter of 2021, the Company entered into the following additional derivative contracts: Commodity Period Derivative Volume/Month Price/Unit Oil March 2021 - Oct 2021 Swap 25,000 Bbls $ 54.77 (1) Oil Nov 2021 - Dec 2021 Swap 15,000 Bbls $ 54.77 (1) Oil March 2021 Swap 50,000 Bbls $ 63.31 (1) Oil April 2021 Swap 50,000 Bbls $ 63.13 (1) Oil May 2021 Swap 50,000 Bbls $ 62.71 (1) Oil June 2021 Swap 50,000 Bbls $ 62.17 (1) Oil July 2021 Swap 50,000 Bbls $ 61.50 (1) Oil Aug 2021 Swap 50,000 Bbls $ 60.94 (1) Oil Sep 2021 Swap 50,000 Bbls $ 60.38 (1) Oil Oct 2021 Swap 50,000 Bbls $ 59.89 (1) Oil Nov 2021 Swap 50,000 Bbls $ 59.46 (1) Oil Dec 2021 Swap 50,000 Bbls $ 59.01 (1) Oil Jan 2022 Swap 60,000 Bbls $ 52.94 (1) Oil Feb 2022 Swap 60,000 Bbls $ 52.65 (1) Oil March 2022 Swap 60,000 Bbls $ 52.29 (1) Oil April 2022 Swap 47,500 Bbls $ 51.98 (1) Oil May 2022 Swap 45,000 Bbls $ 51.71 (1) Oil June 2022 Swap 45,000 Bbls $ 51.41 (1) Oil July 2022 Swap 45,000 Bbls $ 51.13 (1) Oil Aug 2022 Swap 45,000 Bbls $ 50.89 (1) Oil Sep 2022 Swap 45,000 Bbls $ 50.65 (1) Oil Oct 2022 Swap 45,000 Bbls $ 50.45 (1) Oil Nov 2022 Swap 55,000 Bbls $ 50.26 (1) Oil Dec 2022 Swap 55,000 Bbls $ 50.22 (1) Oil Jan 2023 Swap 57,500 Bbls $ 49.81 (1) Oil Feb 2023 Swap 57,500 Bbls $ 49.63 (1) Oil Jan 2022 Swap 60,000 Bbls $ 52.96 (1) Oil Feb 2022 Swap 60,000 Bbls $ 52.66 (1) Oil March 2022 Swap 60,000 Bbls $ 52.27 (1) Oil April 2022 Swap 47,500 Bbls $ 51.96 (1) Oil May 2022 Swap 45,000 Bbls $ 51.72 (1) Oil June 2022 Swap 45,000 Bbls $ 51.42 (1) Oil July 2022 Swap 45,000 Bbls $ 51.13 (1) Oil Aug 2022 Swap 45,000 Bbls $ 50.90 (1) Oil Sep 2022 Swap 45,000 Bbls $ 50.66 (1) Oil Oct 2022 Swap 45,000 Bbls $ 50.47 (1) Oil Nov 2022 Swap 55,000 Bbls $ 50.26 (1) Oil Dec 2022 Swap 55,000 Bbls $ 50.01 (1) Oil Jan 2023 Swap 57,500 Bbls $ 49.79 (1) Oil Feb 2023 Swap 57,500 Bbls $ 49.62 (1) Natural Gas March 2021 Swap 100,000 MMBtus $ 2.96 (2) Natural Gas April 2021 - July 2021 Swap 350,000 MMBtus $ 2.96 (2) Natural Gas Aug 2021 - Oct 2021 Swap 500,000 MMBtus $ 2.96 (2) Natural Gas Nov 2021 Swap 450,000 MMBtus $ 2.96 (2) Natural Gas April 2022 Swap 175,000 MMBtus $ 2.51 (2) Natural Gas May 2022 - July 2022 Swap 150,000 MMBtus $ 2.51 (2) Natural Gas Aug 2022 - Oct 2022 Swap 400,000 MMBtus $ 2.51 (2) Natural Gas Nov 2022 - Feb 2023 Swap 750,000 MMBtus $ 2.72 (2) (1) Based on West Texas Intermediate oil prices. Based on Henry Hub NYMEX natural gas prices
Mid-Con [Member]
Schedule Of Derivative Contracts	In conjunction with the closing of the Mid-Con Acquisition in January 2021, the Company acquired the following additional derivative contracts via novation from Mid-Con: Commodity Period Derivative Volume/Month Price/Unit Oil Jan 2021 Swap 20,883 Bbls $ 55.78 (1) Oil Feb 2021 Swap 20,804 Bbls $ 55.78 (1) Oil March 2021 Swap 20,725 Bbls $ 55.78 (1) Oil April 2021 Swap 20,647 Bbls $ 55.78 (1) Oil May 2021 Swap 20,563 Bbls $ 55.78 (1) Oil June 2021 Swap 20,487 Bbls $ 55.78 (1) Oil July 2021 Swap 20,412 Bbls $ 55.78 (1) Oil Aug 2021 Swap 20,301 Bbls $ 55.78 (1) Oil Sept 2021 Swap 20,228 Bbls $ 55.78 (1) Oil Oct 2021 Swap 20,155 Bbls $ 55.78 (1) Oil Nov 2021 Swap 20,084 Bbls $ 55.78 (1) Oil Dec 2021 Swap 20,012 Bbls $ 55.78 (1) Oil Jan 2021 Collar 20,883 Bbls $ 52.00 - 58.80 (1) Oil Feb 2021 Collar 20,804 Bbls $ 52.00 - 58.80 (1) Oil March 2021 Collar 20,725 Bbls $ 52.00 - 58.80 (1) Oil April 2021 Collar 20,647 Bbls $ 52.00 - 58.80 (1) Oil May 2021 Collar 20,563 Bbls $ 52.00 - 58.80 (1) Oil June 2021 Collar 20,487 Bbls $ 52.00 - 58.80 (1) Oil July 2021 Collar 20,412 Bbls $ 52.00 - 58.80 (1) Oil Aug 2021 Collar 20,301 Bbls $ 52.00 - 58.80 (1) Oil Sept 2021 Collar 20,228 Bbls $ 52.00 - 58.80 (1) Oil Oct 2021 Collar 20,155 Bbls $ 52.00 - 58.80 (1) Oil Nov 2021 Collar 20,084 Bbls $ 52.00 - 58.80 (1) Oil Dec 2021 Collar 20,012 Bbls $ 52.00 - 58.80 (1) (1) Based on West Texas Intermediate oil prices.

Stock Based Compensation (Table

Stock Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2020
Stock-Based Compensation [Abstract]
Summary Of Stock Options Granted	A summary of stock options as of and for the years ended December 31, 2020 and 2019 is presented in the table below (dollars in thousands, except per share data): Year Ended December 31, 2020 2019 Weighted Weighted Shares Average Shares Average Under Exercise Under Exercise Options Price Options Price Outstanding, beginning of the period 20,964 $ 58.53 33,637 $ 55.82 Exercised — $ — — $ — Expired / Forfeited (1,117) $ 39.00 (12,673) $ 51.34 Outstanding, end of year 19,847 $ 59.62 20,964 $ 58.53 Aggregate intrinsic value $ — $ — Exercisable, end of year 19,847 $ 59.62 20,964 $ 58.53 Aggregate intrinsic value $ — $ — Available for grant, end of the period * 6,240,312 1,480,389 Weighted average fair value of options granted during the period $ — $ — * Assumes performance stock units are settled at 100% of target.
Summary Of Restricted Stock Activity	Restricted stock activity as of December 31, 2020 and 2019 and for the years then ended is presented in the table below (dollars in thousands, except per share data): 2020 2019 Weighted Aggregate Weighted Aggregate Restricted Average Intrinsic Restricted Average Intrinsic Shares Fair Value Value Shares Fair Value Value Outstanding, beginning of the period 403,221 $ 3.66 $ 214 459,621 $ 7.26 $ 662 Granted 1,244,527 2.22 65 388,060 2.91 — Vested (289,636) 3.48 700 (353,114) 7.41 1,171 Canceled / Forfeited (55,064) 2.45 16 (91,346) 4.08 41 Not vested, end of the period 1,303,048 2.38 228 403,221 3.66 214

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Leases
Summary of balance sheet information related to the leases	The following table summarizes the balance sheet information related to the Company’s leases as of December 31, 2020 and December 31, 2019 (in thousands): December 31, 2020 December 31, 2019 Operating lease right of use asset (1) $ 2,452 $ 4,316 Operating lease liability - current (2) $ (1,832) $ (2,597) Operating lease liability - long-term (3) (522) (1,738) Total operating lease liability $ (2,354) $ (4,335) Financing lease right of use asset (1) $ 2,996 $ 1,569 Financing lease liability - current (2) $ (940) $ (524) Financing lease liability - long-term (3) (2,102) (1,051) Total financing lease liability $ (3,042) $ (1,575) (1) Included in “Right-of-use lease assets” on the consolidated balance sheet. (2) Included in “Accounts payable and accrued liabilities” on the consolidated balance sheet. (3) Included in “Lease liabilities” on the consolidated balance sheet.
Summary of weighted average remaining lease terms and weighted average discount rates	The table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of December 31, 2020 and December 31, 2019: December 31, 2020 December 31, 2019 Weighted Average Remaining Lease Terms (in years): Operating leases Financing leases Weighted Average Discount Rate: Operating leases Financing leases
Summary of operating lease maturities	Maturities for the Company’s lease liabilities on the consolidated balance sheet as of December 31, 2020, were as follows (in thousands): December 31, 2020 Operating Leases Financing Leases 2021 $ 1,906 $ 1,094 2022 240 980 2023 170 823 2024 158 459 Total future minimum lease payments 2,474 3,356 Less: imputed interest (120) (314) Present value of lease liabilities $ 2,354 $ 3,042
Summary of finance lease maturities	December 31, 2020 Operating Leases Financing Leases 2021 $ 1,906 $ 1,094 2022 240 980 2023 170 823 2024 158 459 Total future minimum lease payments 2,474 3,356 Less: imputed interest (120) (314) Present value of lease liabilities $ 2,354 $ 3,042
Summary of lease costs	The following table summarizes expenses related to the Company’s leases for the three months ended December 31, 2020 and December 31, 2019 (in thousands): Three Months Ended December 31, 2020 Three Months Ended December 31, 2019 Operating lease cost (1) (2) $ 843 $ 542 Financing lease cost - amortization of right-of-use assets 231 87 Financing lease cost - interest on lease liabilities 47 17 Administrative lease cost (3) 19 19 Short-term lease cost (1) (4) 360 741 Total lease cost $ 1,500 $ 1,406 (1) This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. (2) Costs related to office leases and compressors with lease terms of twelve months of more. (3) Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year. (4) Costs related primarily to drilling rigs, generators and compressor agreements with lease terms of more than one month and less than one year. The following table summarizes expenses related to the Company’s leases for the years ended December 31, 2020 and December 31, 2019 (in thousands): Year Ended December 31, 2020 Year Ended December 31, 2019 Operating lease cost (1) (2) $ 3,055 $ 742 Financing lease cost - amortization of right-of-use assets 642 92 Financing lease cost - interest on lease liabilities 131 18 Administrative lease cost (3) 75 75 Short-term lease cost (1) (4) 1,974 4,101 Total lease cost $ 5,877 $ 5,028 (1) This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. (2) Costs related to office leases and compressors with lease terms of twelve months of more. Higher costs in 2020 due to additional leases related to the properties acquired from Will Energy and White Star during the three months ended December 31, 2019. (3) Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year. Costs related primarily to drilling rigs, generators and compressor agreements with lease terms of more than one month and less than one year.

Other Financial Information (Ta

Other Financial Information (Tables)	12 Months Ended
	Dec. 31, 2020
Other Financial Information [Abstract]
Schedule Of Additional Financial Details	December 31, December 31, 2020 2019 Accounts receivable: Trade receivables $ 20,306 $ 21,110 Receivable for Alta Resources distribution 1,712 1,712 Joint interest billings 15,637 13,104 Income taxes receivable 268 509 Other receivables 2,209 4,126 Allowance for doubtful accounts (1) (2,270) (994) Total accounts receivable $ 37,862 $ 39,567 Prepaid Expenses: Prepaid insurance $ 2,825 $ 683 Other (2) 535 508 Total Prepaid Expenses $ 3,360 $ 1,191 Accounts payable and accrued liabilities: Royalties and revenue payable $ 23,701 $ 15,905 Legal suspense related to revenues (3) 27,983 33,739 Advances from partners (4) 76 6,733 Accrued exploration and development (4) 490 8,210 Trade payables 14,273 14,086 Accrued general and administrative expenses (5) 6,191 12,037 Accrued operating expenses 5,755 5,794 Accrued operating and finance leases 2,772 3,120 Other accounts payable and accrued liabilities 2,729 4,969 Total accounts payable and accrued liabilities $ 83,970 $ 104,593 (1) Increase in 2020 primarily due to the additional properties acquired from Will Energy and White Star. (2) Other prepaids primarily includes software licenses. (3) Suspended revenues primarily relate to amounts for which there is some question as to valid ownership, unknown addresses of payees or some other payment dispute. (4) Decrease in 2020 due to a decrease in drilling and completion activity. In response to the dramatic decline in commodity prices in the first quarter of 2020, the Company suspended further operated drilling in its West Texas area, and in its other onshore areas. (5) The December 31, 2019 balance includes an accrual of $6.3 million for a legal judgment that was paid in April 2020. See Note 14 – “Commitment and Contingencies” for further information.
Schedule Of Supplemental Disclosures	Year Ended December 31, 2020 2019 Cash payments: Interest payments $ 3,592 $ 7,761 Income tax payments, net of cash refunds 293 668 Non-cash items excluded from investing activities in the consolidated statements of cash flows: Increase (decrease) in accrued capital expenditures (7,615) 1,841

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation	Activities related to the Company’s ARO during the years ended December 31, 2020 and 2019 were as follows (in thousands): Year Ended December 31, 2020 2019 Balance as of the beginning of the period $ 51,665 $ 13,497 Liabilities incurred during period 5 256 Liabilities settled during period (338) (1,380) Accretion 2,702 1,062 Sales (5,239) (816) Acquisitions — 37,596 Change in estimate 3,978 1,450 Balance as of the end of the period $ 52,773 $ 51,665

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
Commitments And Contingencies [Abstract]
Schedule of future operating and finance lease payments and other commitments	As of December 31, 2020, minimum future operating and finance lease payments and other commitments listed above for Contango’s fiscal years are as follows (in thousands): Fiscal years ending December 31, 2021 $ 3,941 2022 2,163 2023 1,872 2024 1,496 2025 and thereafter 879 Total $ 10,351

Net Loss Per Common Share (Tabl

Net Loss Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2020
Net Loss Per Common Share
Components Of Basic And Diluted Net Loss Per Share Of Common Stock	A reconciliation of the components of basic and diluted net loss per common share for the years ended December 31, 2020 and 2019 is presented below (in thousands): Year Ended December 31, 2020 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (165,342) 137,522 $ (1.20) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $ (165,342) 137,522 $ (1.20) Year Ended December 31, 2019 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (159,796) 54,136 $ (2.95) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $ (159,796) 54,136 $ (2.95)

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Taxes [Abstract]
Schedule Of Effective Income Tax Rate Reconciliation	Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate rate of 21 percent for the years ended December 31, 2020 and 2019, respectively, to pretax income as follows (dollars in thousands): Year Ended December 31, 2020 2019 Benefit at statutory tax rate $ (34,663) 21.00 % $ (33,561) 21.00 % State income tax provision, net of federal benefit 467 (0.28) % 555 (0.35) % State deferred tax benefit (5,553) 3.36 % — — % Permanent differences 26 (0.02) % 30 (0.02) % Stock based compensation 81 (0.05) % 979 (0.61) % Valuation allowance 40,059 (24.27) % 34,239 (21.42) % Other 330 (0.20) % (2,022) 1.26 % Income tax provision $ 747 (0.46) % $ 220 (0.14) %
Components Of Income Tax Provision	The provision (benefit) for income taxes for the periods indicated are comprised of the following (in thousands): Year Ended December 31, 2020 2019 Current tax provision (benefit): Federal $ 275 $ (335) State 472 555 Total $ 747 $ 220 Deferred tax benefit: Federal $ — $ — State — — Total $ — $ — Total tax provision (benefit): Federal $ 275 $ (335) State 472 555 Total $ 747 $ 220 Included in gain from investment in affiliates $ — $ — Total income tax provision $ 747 $ 220
Schedule Of Net Deferred Tax Liability	The Federal income tax expense results from an adjustment in the previous period of the credit for Alternative Minimum Tax (“AMT”) paid in prior years. As a result of the tax reform in 2017, the corporate AMT was repealed, and any AMT credit was made refundable. The first half of the credit was refunded when the Company filed its 2018 federal income tax return, and the second half of the credit was refunded when the Company filed its 2019 federal tax return. The CARES Act modified the timing of these refunds, allowing the Company to request an expedited refund of $0.3 million during the quarter ended June 30, 2020. This amount was previously accounted for as an income tax benefit when the corporate AMT was repealed. State income tax expense relates to income taxes for the quarter and the nine months which are expected to be owed to the states of Louisiana and Oklahoma resulting from activities within those states and, in each case, that are not shielded by existing Federal tax attributes. Additionally, under the CARES Act, the Company will benefit from an amendment to Internal Revenue Code Section 163(j) that temporarily increases deductible interest expense limitations. Specifically, the CARES Act increases the 30% Adjusted Taxable Income (“ATI”) limitation to 50% of ATI for taxable years beginning in each of 2019 and 2020. This will have the effect of allowing the Company to use a Section 163(j) carryover from the prior year that was not limited by Section 382 (discussed below). The Company does not expect to benefit from any other income tax-related provisions of the CARES Act. The net deferred tax is comprised of the following (in thousands): December 31, 2020 2019 Deferred tax assets: Net operating loss carryforward $ 84,982 $ 80,617 Deferred compensation 447 — Derivative instruments — 377 State deferred tax assets 6,507 954 Oil and gas properties 39,081 11,436 Investment in affiliates 752 2,799 Recognized built in loss carryforward 9,987 6,718 163(j) Carryforward 1,828 1,585 Other 1,796 964 Total deferred tax assets before valuation allowance $ 145,380 $ 105,450 Valuation allowance (145,269) (105,212) Net deferred tax assets $ 111 $ 238 Deferred tax liability: Deferred compensation $ — $ (238) Derivative instruments (111) — Deferred tax liability $ (111) $ (238) Total net deferred tax $ — $ —
Schedule Of Unrecognized Tax Benefits	A reconciliation of the beginning and ending amount of unrecognized income tax benefits is as follows (in thousands): Unrecognized Tax Benefits Balance at December 31, 2019 $ — Additions based on tax positions related to the current year — Additions based on tax positions related to prior years — Additions due to acquisitions — Reductions due to a lapse of the applicable statute of limitations — Change in rate due to remeasurement — Balance at December 31, 2020 $ —

Organization and Business (Deta

Organization and Business (Details)	Feb. 01, 2021USD ($)	Jan. 21, 2021USD ($)shares	Dec. 01, 2020USD ($)shares	Nov. 27, 2020USD ($)	Oct. 30, 2020USD ($)Lender	Oct. 27, 2020USD ($)shares	Jun. 24, 2020USD ($)shares	Jun. 08, 2020$ / sharesshares	Dec. 23, 2019USD ($)itemshares	Nov. 01, 2019USD ($)item	Sep. 30, 2019USD ($)	Nov. 19, 2018shares	Sep. 30, 2020USD ($)	Jun. 30, 2020USD ($)	Dec. 31, 2019USD ($)a$ / sharesshares	Nov. 30, 2019USD ($)shares	Sep. 30, 2019USD ($)shares	Dec. 31, 2020USD ($)a$ / sharesshares	Sep. 30, 2020shares	Jun. 30, 2020shares	Dec. 31, 2019a$ / sharesshares	Sep. 30, 2019shares	Dec. 31, 2020USD ($)aitem$ / sharesshares	Dec. 31, 2019USD ($)aitem$ / sharesshares	Oct. 29, 2020USD ($)	Jun. 09, 2020USD ($)	Jun. 07, 2020shares	Jun. 05, 2020USD ($)	Sep. 17, 2019USD ($)	Dec. 31, 2018a
Gross acres | a																		16,200					16,200
Net acres | a																		7,500					7,500
Number of wells | item																							18
Property management annual revenue																												$ 4,000,000
Deferred fees, monthly																												166,666
Deferred fee, annual																		$ 2,000,000					$ 2,000,000					$ 2,000,000
Revenues																							$ 112,920,000	$ 76,512,000
Common stock, par value (in dollars per share) | $ / shares								$ 0.04							$ 0.04			$ 0.04			$ 0.04		$ 0.04	$ 0.04
Common stock, shares authorized | shares								400,000,000							200,000,000	100,000,000		400,000,000			200,000,000		400,000,000	200,000,000			200,000,000
Stock converted (in shares) | shares								2,700,000
Equity offering-common stock, shares | shares			14,193,903			26,451,988	163,929					8,600,000
Proceeds from stock issued			$ 21,700,000			$ 38,800,000	$ 500,000																$ 60,919,000	$ 125,710,000
Maximum [Member]
Proceeds from stock issued							$ 100,000,000
Series A Contingent Convertible Preferred Stock [Member]
Equity offering-common stock, shares | shares																	789,474
Net proceeds from equity offerings																	$ 7,500,000
Conversion of preferred stock to common stock | shares															7,894,740						7,894,740			7,894,740
Series B Contingent Convertible Preferred Stock [Member]
Equity offering-common stock, shares | shares																1,102,838
Net proceeds from equity offerings																$ 21,000,000
Conversion of preferred stock to common stock | shares															11,028,380						11,028,380			11,028,380
Series C Contingent Convertible Preferred Stock [Member]
Equity offering-common stock, shares | shares															2,340,000
Net proceeds from equity offerings															$ 5,600,000
Conversion of preferred stock to common stock | shares								2,700,000
Consideration for service (in shares) | shares															360,000
Common Stock [Member]
Treasury shares reissuance, shares | shares																	5,524,498					(25,748)
Equity offering-common stock, shares | shares															19,000,000		51,447,368	40,645,891	8,900	155,029	19,000,000	45,922,870
Net proceeds from equity offerings															$ 45,700,000		$ 46,200,000
Common stock issued for acquisition (in shares) | shares																					5,225,000
Oil and condensate sales [Member]
Revenues																							62,461,000	$ 44,705,000
Natural gas sales [Member]
Revenues																							31,381,000	22,380,000
Natural gas liquids sales [Member]
Revenues																							17,078,000	$ 9,427,000
Fee for service revenues [Member]
Revenues																							2,000,000
JPMorgan Chase Bank [Member]
Borrowing capacity		$ 130,000,000								$ 145,000,000								$ 75,000,000					$ 75,000,000		$ 75,000,000	$ 95,000,000			$ 65,000,000
Periodic borrowing base reduction					$ 10,000,000								$ 10,000,000	$ 10,000,000
Number Of Additional Lenders					3					2
JPMorgan Chase Bank [Member] | Subsequent Event [Member]
Borrowing capacity		$ 130,000,000
Bullseye
Net acres position development | a															6,500						6,500			6,500
Wells previously drilled | item																								1
Number of wells | item																								3
White Star [Member]
Acquired properties percentage of total production																							70.00%
Acquisition consideration										$ 139,100,000	$ 132,500,000
Cash consideration for acquisition										$ 95,722,000
Juneau
Number of exploratory prospects acquired | item									6
Common stock issued for acquisition (in shares) | shares									1,725,000
Acquisition consideration									$ 6,000,000
Cash consideration for acquisition									$ 1,690,000
NE Bullseye
Gross acres - additional operated | a																														4,200
Net acres - additional operated | a																														1,700
Gross non-operated acres | a																														4,000
Net non-operated acres | a																														200
Mid-Con [Member]
Common stock issued for acquisition (in shares) | shares		25,409,000
Cash consideration for acquisition		$ 14,520,000
Mid-Con [Member] | Subsequent Event [Member]
Common stock issued for acquisition (in shares) | shares		25,409,164
Silvertip Acquisition [Member]
Acquisition consideration				$ 58,000,000
Acquisition deposit				$ 7,000,000														$ 7,000,000
Silvertip Acquisition [Member] | Subsequent Event [Member]
Acquisition consideration	$ 58,000,000
Acquisition deposit	7,000,000
Business Combination, Contingent Consideration, Liability	53,200,000
Cash consideration for acquisition	$ 46,200,000

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)item	Dec. 31, 2019USD ($)
Policies
Term of contract	1 year
Cash and cash equivalents	$ 1,383	$ 1,624
Outstanding checks in accounts payable that have not yet been presented for payment	2,900	6,100
Allowance for doubtful accounts receivable	$ 2,300	$ 1,000
Minimum [Member]
Policies
Period settlement statements are received	30 days
Maximum [Member]
Policies
Period settlement statements are received	90 days
Exaro Energy III LLC [Member]
Policies
Number of seats on Board of Directors | item	2
Equity method investment, ownership percentage	37.00%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Properties (Details) - USD ($) $ in Thousands	Oct. 30, 2020	Jun. 09, 2020	Nov. 01, 2019	Sep. 17, 2019	Jan. 31, 2021	Dec. 31, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Jan. 21, 2021	Oct. 29, 2020
Significant Accounting Policies [Line Items]
Dry hole costs									$ 10,500
Impairment of oil and natural gas properties									168,732	$ 126,964
Debt issuance costs incurred									74	3,455
Amortization of debt issuance costs									$ 1,603	144
Restricted assets, percent of net assets						25.00%			25.00%
Minimum [Member]
Significant Accounting Policies [Line Items]
Property and equipment depreciation, estimated useful life									3 years
Maximum [Member]
Significant Accounting Policies [Line Items]
Property and equipment depreciation, estimated useful life									10 years
JPMorgan Chase Bank [Member]
Significant Accounting Policies [Line Items]
Debt issuance costs incurred	$ 100	$ 0	$ 1,600	$ 1,800	$ 900	$ 100
Amortization of debt issuance costs							$ 1,000		$ 1,600
Borrowing capacity		$ 95,000	$ 145,000	$ 65,000		75,000			75,000		$ 130,000	$ 75,000
Remaining balance debt issue costs						1,800			1,800
JPMorgan Chase Bank [Member] | Subsequent Event [Member]
Significant Accounting Policies [Line Items]
Debt issuance costs incurred					$ 900
Borrowing capacity											$ 130,000
Proved property [Member]
Significant Accounting Policies [Line Items]
Impairment of oil and natural gas properties						21,100		$ 143,300	164,400	117,800
Proved property [Member] | Offshore Properties [Member]
Significant Accounting Policies [Line Items]
Impairment of oil and natural gas properties						15,600				34,500
Proved property [Member] | Onshore Properties [Member]
Significant Accounting Policies [Line Items]
Impairment of oil and natural gas properties										83,300
Unproved property [Member]
Significant Accounting Policies [Line Items]
Impairment of oil and natural gas properties						$ 1,700		$ 2,600	$ 4,300	$ 9,200

Concentration of Credit Risk (D

Concentration of Credit Risk (Details) - Sales Revenue, Goods, Net [Member] - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2020item
Concentration Risk [Line Items]
Number of purchasers	3
Concentration risk, percentage	36.00%
Number of months of potential revenue loss	2 months

Acquisitions and Dispositions -

Acquisitions and Dispositions - Acquisitions (Details) $ in Thousands	Feb. 01, 2021USD ($)	Jan. 21, 2021USD ($)shares	Nov. 27, 2020USD ($)	Dec. 23, 2019USD ($)itemshares	Nov. 01, 2019USD ($)a	Oct. 25, 2019USD ($)shares	Sep. 30, 2019USD ($)	Dec. 31, 2020USD ($)	Sep. 12, 2019a	Dec. 31, 2018a
Mid-Con [Member]
Acquisition
Right to receive shares (in shares) | shares		1.75
Common stock issued for acquisition (in shares) | shares		25,409,000
Cash consideration for acquisition		$ 14,520
Mid-Con [Member] | Subsequent Event [Member]
Acquisition
Right to receive shares (in shares) | shares		1.75
Common stock issued for acquisition (in shares) | shares		25,409,164
Mid-Con [Member] | Subsequent Event [Member] | Mid-Con [Member] | John C Goff [Member]
Acquisition
Equity method investment, ownership percentage		56.40%
Silvertip Acquisition [Member]
Acquisition
Acquisition consideration			$ 58,000
Acquisition deposit			$ 7,000					$ 7,000
Silvertip Acquisition [Member] | Subsequent Event [Member]
Acquisition
Acquisition consideration	$ 58,000
Acquisition deposit	7,000
Cash consideration for acquisition	$ 46,200
Juneau
Acquisition
Common stock issued for acquisition (in shares) | shares				1,725,000
Acquisition consideration				$ 6,000
Cash consideration for acquisition				$ 1,690
Number of exploratory prospects acquired | item				6
White Star [Member]
Acquisition
Acquisition consideration					$ 139,100		$ 132,500
Cash consideration for acquisition					$ 95,722
Net acres | a					306,000
Will Energy [Member]
Acquisition
Common stock issued for acquisition (in shares) | shares						3,500,000
Acquisition consideration						$ 23,000
Cash consideration for acquisition						$ 14,000
Net acres | a									155,900
Will Energy [Member] | North Louisiana [Member]
Acquisition
Net acres | a									8,000
Will Energy [Member] | Western Anadarko [Member]
Acquisition
Net acres | a									147,900
NE Bullseye
Acquisition
Gross acres - additional operated | a										4,200
Net acres - additional operated | a										1,700
Gross non-operated acres | a										4,000
Net non-operated acres | a										200

Acquisitions and Dispositions_2

Acquisitions and Dispositions - Consideration Allocation (Details) - USD ($) $ / shares in Units, $ in Thousands	Jan. 21, 2021	Nov. 01, 2019	Sep. 30, 2019
Mid-Con [Member]
Consideration:
Cash	$ 14,520
Exchange ratio of Contango shares for Mid-Con common units (in shares)	1.75
Contango common stock to be issued to Mid-Con unitholders (in shares)	25,409,000
Issued price (in dollars per share)	$ 3.13
Equity issued for acquisition consideration (in dollars)	$ 79,530
Liabilities Assumed:
Accounts payable	5,596
Other and revenue and royalties payable	457
Revolving credit facility	68,487
Asset retirement obligations	29,241
Total liabilities assumed	103,781
Assets Acquired:
Cash and cash equivalents	776
Accounts receivable	4,398
Derivative and other current assets	3,141
Prepaid expenses	162
Proved oil and natural gas properties	172,607
Other property and equipment	730
Other assets	1,497
Total assets acquired	$ 183,311
White Star [Member]
Consideration:
Cash		$ 95,722
Liabilities Assumed:
Accounts payable		6,618
Other and revenue and royalties payable		11,165
Suspended revenue and royalties		22,011
Lease liabilities		3,614
Total liabilities assumed		43,408
Assets Acquired:
Accounts receivable		18,037
Derivative and other current assets		1,413
Proved oil and natural gas properties		113,150
Unevaluated properties		2,611
Right-of-use lease assets		3,614
Other assets		305
Total assets acquired		139,130
Acquisition consideration		139,100	$ 132,500
Purchase price adjustment, inventory		1,000
Purchase price adjustment, property		(400)
White Star [Member] | Previously Reported [Member]
Assets Acquired:
Acquisition consideration		$ 138,500

Acquisitions and Dispositions_3

Acquisitions and Dispositions - Pro Forma (Details) - USD ($) $ / shares in Units, $ in Thousands	2 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Mid-Con [Member]
Pro forma information
Revenue		$ 150,569
Net loss		$ (188,178)
Basic earnings per share (in dollars per share)		$ (1.02)
Diluted earnings per share (in dollars per share)		$ (1.02)
White Star [Member]
Pro forma information
Revenue since acquisition	$ 21,400
Direct operating expenses since acquisition	16,300
Acquisition-related costs	$ 1,900		$ 1,900
Revenue			207,530
Net loss			$ (265,760)
Basic earnings per share (in dollars per share)			$ (4.20)
Diluted earnings per share (in dollars per share)			$ (4.20)

Acquisitions and Dispositions_4

Acquisitions and Dispositions - Dispositions (Details) - USD ($) $ in Thousands	Jun. 01, 2020	Apr. 01, 2020	Jul. 01, 2019	Jun. 10, 2019	Dec. 31, 2020	Dec. 31, 2019
Disposals
Gain from sale of assets					$ 4,501	$ 518
Proceeds from sale					$ 349	$ 10
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member]
Disposals
Gain from sale of assets	$ 4,200	$ 200	$ 200	$ 400
Proceeds from sale		$ 500

Fair Value Measurements (Detail

Fair Value Measurements (Details)	12 Months Ended
	Dec. 31, 2020
Fair Value Measurements
Maximum period of interest rate on floating-rate debt	3 months

Derivative Instruments - Deriva

Derivative Instruments - Derivative Contracts (Details) $ in Thousands	Mar. 31, 2021MMBTUitem$ / item	Jan. 31, 2021item$ / item	Dec. 31, 2020USD ($)MMBblsBcfitem$ / item	Dec. 31, 2019USD ($)item$ / item
Derivative [Line Items]
Fair Value | $			$ 528	$ (1,684)
Oil [Member] | Derivative Contract Period 2021 [Member]
Derivative [Line Items]
Average floor price			54.85
Commodity Derivative Flow Rate | MMBbls			2.1
Oil [Member] | Derivative Contract Period 2022 [Member]
Derivative [Line Items]
Average floor price			50.24
Commodity Derivative Flow Rate | MMBbls			1.4
Oil [Member] | Collar Options [Member] | Derivative Contract Period January To October 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				3,442
Price/Unit-Floor				52
Price/Unit-Cap				65.70
Fair Value | $				$ 18
Oil [Member] | Collar Options [Member] | Mid-Con [Member] | Derivative Contract Period January 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,883
Price/Unit-Floor		52
Price/Unit-Cap		58.80
Oil [Member] | Collar Options [Member] | Mid-Con [Member] | Derivative Contract Period February 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,804
Price/Unit-Floor		52
Price/Unit-Cap		58.80
Oil [Member] | Collar Options [Member] | Mid-Con [Member] | Derivative Contract Period March 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,725
Price/Unit-Floor		52
Price/Unit-Cap		58.80
Oil [Member] | Collar Options [Member] | Mid-Con [Member] | Derivative Contract Period April 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,647
Price/Unit-Floor		52
Price/Unit-Cap		58.80
Oil [Member] | Collar Options [Member] | Mid-Con [Member] | Derivative Contract Period May 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,563
Price/Unit-Floor		52
Price/Unit-Cap		58.80
Oil [Member] | Collar Options [Member] | Mid-Con [Member] | Derivative Contract Period June 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,487
Price/Unit-Floor		52
Price/Unit-Cap		58.80
Oil [Member] | Collar Options [Member] | Mid-Con [Member] | Derivative Contract Period July 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,412
Price/Unit-Floor		52
Price/Unit-Cap		58.80
Oil [Member] | Collar Options [Member] | Mid-Con [Member] | Derivative Contract Period August 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,301
Price/Unit-Floor		52
Price/Unit-Cap		58.80
Oil [Member] | Collar Options [Member] | Mid-Con [Member] | Derivative Contract Period September 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,228
Price/Unit-Floor		52
Price/Unit-Cap		58.80
Oil [Member] | Collar Options [Member] | Mid-Con [Member] | Derivative Contract Period October 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,155
Price/Unit-Floor		52
Price/Unit-Cap		58.80
Oil [Member] | Collar Options [Member] | Mid-Con [Member] | Derivative Contract Period November 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,084
Price/Unit-Floor		52
Price/Unit-Cap		58.80
Oil [Member] | Collar Options [Member] | Mid-Con [Member] | Derivative Contract Period December 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,012
Price/Unit-Floor		52
Price/Unit-Cap		58.80
Oil [Member] | Swap [Member] | Derivative Contract Period January To February 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				42,500
Price/Unit-Swap				54.70
Fair Value | $				$ (517)
Oil [Member] | Swap [Member] | Derivative Contract 2 Period January To February 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				42,500
Price/Unit-Swap				54.58
Fair Value | $				$ (527)
Oil [Member] | Swap [Member] | Derivative Contract Period January To March 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				2,700
Price/Unit-Swap				54.33
Fair Value | $				$ (51)
Oil [Member] | Swap [Member] | Derivative Contract Period January To June 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				22,000
Price/Unit-Swap				57.74
Fair Value | $				$ (289)
Oil [Member] | Swap [Member] | Derivative Contract Period March To July 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				37,500
Price/Unit-Swap				54.70
Fair Value | $				$ (842)
Oil [Member] | Swap [Member] | Derivative Contract 2 Period March To July 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				37,500
Price/Unit-Swap				54.58
Fair Value | $				$ (864)
Oil [Member] | Swap [Member] | Derivative Contract Period April To June 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				2,500
Price/Unit-Swap				54.33
Fair Value | $				$ (37)
Oil [Member] | Swap [Member] | Derivative Contract Period July 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				5,500
Price/Unit-Swap				54.33
Fair Value | $				$ (21)
Oil [Member] | Swap [Member] | Derivative Contract Period July To December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				15,000
Price/Unit-Swap				57.74
Fair Value | $				$ 68
Oil [Member] | Swap [Member] | Derivative Contract Period August to October 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				2,500
Price/Unit-Swap				54.33
Fair Value | $				$ (21)
Oil [Member] | Swap [Member] | Derivative Contract Period August to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				35,000
Price/Unit-Swap				54.70
Fair Value | $				$ (354)
Oil [Member] | Swap [Member] | Derivative Contract 2 Period August to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				35,000
Price/Unit-Swap				54.58
Fair Value | $				$ (373)
Oil [Member] | Swap [Member] | Derivative Contract Period November To December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				3,500
Price/Unit-Swap				54.33
Fair Value | $				$ (12)
Oil [Member] | Swap [Member] | Derivative Contract Period January to March 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			19,000	19,000
Price/Unit-Swap			50	50
Fair Value | $			$ 78	$ (291)
Oil [Member] | Swap [Member] | Derivative Contract January To March 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	50,000
Price/Unit-Swap	63.31
Oil [Member] | Swap [Member] | Derivative Contract Period January to July 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			62,000	62,000
Price/Unit-Swap			52	52
Fair Value | $			$ 1,490	$ (1,122)
Oil [Member] | Swap [Member] | Derivative Contract Period March to October 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	25,000
Price/Unit-Swap	54.77
Oil [Member] | Swap [Member] | Derivative Contract Period April 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	50,000
Price/Unit-Swap	63.13
Oil [Member] | Swap [Member] | Derivative Contract Period April to July 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			12,000	12,000
Price/Unit-Swap			50	50
Fair Value | $			$ 71	$ (196)
Oil [Member] | Swap [Member] | Derivative Contract Period May 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	50,000
Price/Unit-Swap	62.71
Oil [Member] | Swap [Member] | Derivative Contract Period June 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	50,000
Price/Unit-Swap	62.17
Oil [Member] | Swap [Member] | Derivative Contract Period July 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	50,000
Price/Unit-Swap	61.50
Oil [Member] | Swap [Member] | Derivative Contract Period August 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	50,000
Price/Unit-Swap	60.94
Oil [Member] | Swap [Member] | Derivative Contract Period August to September 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			10,000	10,000
Price/Unit-Swap			50	50
Fair Value | $			$ 39	$ (67)
Oil [Member] | Swap [Member] | Derivative Contract 2 Period August to September 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			55,000	55,000
Price/Unit-Swap			52	52
Fair Value | $			$ 434	$ (157)
Oil [Member] | Swap [Member] | Derivative Contract Period September 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	50,000
Price/Unit-Swap	60.38
Oil [Member] | Swap [Member] | Derivative Contract Period October 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	50,000
Price/Unit-Swap	59.89
Oil [Member] | Swap [Member] | Derivative Contract Period October to December 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			64,000	64,000
Price/Unit-Swap			52	52
Fair Value | $			$ 840	$ (184)
Oil [Member] | Swap [Member] | Derivative Contract Period November 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	50,000
Price/Unit-Swap	59.46
Oil [Member] | Swap [Member] | Derivative Contract Period November to December 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	15,000
Price/Unit-Swap	54.77
Oil [Member] | Swap [Member] | Derivative Contract Period December 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	50,000
Price/Unit-Swap	59.01
Oil [Member] | Swap [Member] | Derivative Contract Period January 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	60,000
Price/Unit-Swap	52.94
Oil [Member] | Swap [Member] | Derivative Contract 2 Period January 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	60,000
Price/Unit-Swap	52.96
Oil [Member] | Swap [Member] | Derivative Contract Period February 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	60,000
Price/Unit-Swap	52.65
Oil [Member] | Swap [Member] | Derivative Contract 2 Period February 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	60,000
Price/Unit-Swap	52.66
Oil [Member] | Swap [Member] | Derivative Contract Period March 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	60,000
Price/Unit-Swap	52.29
Oil [Member] | Swap [Member] | Derivative Contract 2 Period March 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	60,000
Price/Unit-Swap	52.27
Oil [Member] | Swap [Member] | Derivative Contract Period April 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	47,500
Price/Unit-Swap	51.98
Oil [Member] | Swap [Member] | Derivative Contract 2 Period April 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	47,500
Price/Unit-Swap	51.96
Oil [Member] | Swap [Member] | Derivative Contract Period May 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	45,000
Price/Unit-Swap	51.71
Oil [Member] | Swap [Member] | Derivative Contract 2 Period May 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	45,000
Price/Unit-Swap	51.72
Oil [Member] | Swap [Member] | Derivative Contract Period June 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	45,000
Price/Unit-Swap	51.41
Oil [Member] | Swap [Member] | Derivative Contract 2 Period June 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	45,000
Price/Unit-Swap	51.42
Oil [Member] | Swap [Member] | Derivative Contract Period July 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	45,000
Price/Unit-Swap	51.13
Oil [Member] | Swap [Member] | Derivative Contract 2 Period July 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	45,000
Price/Unit-Swap	51.13
Oil [Member] | Swap [Member] | Derivative Contract Period August To October 2022 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			25,000
Price/Unit-Swap			42.04
Fair Value | $			$ (784)
Oil [Member] | Swap [Member] | Derivative Contract Period August 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	45,000
Price/Unit-Swap	50.89
Oil [Member] | Swap [Member] | Derivative Contract 2 Period August 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	45,000
Price/Unit-Swap	50.90
Oil [Member] | Swap [Member] | Derivative Contract Period September 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	45,000
Price/Unit-Swap	50.65
Oil [Member] | Swap [Member] | Derivative Contract 2 Period September 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	45,000
Price/Unit-Swap	50.66
Oil [Member] | Swap [Member] | Derivative Contract Period October 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	45,000
Price/Unit-Swap	50.45
Oil [Member] | Swap [Member] | Derivative Contract 2 Period October 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	45,000
Price/Unit-Swap	50.47
Oil [Member] | Swap [Member] | Derivative Contract Period November 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	55,000
Price/Unit-Swap	50.26
Oil [Member] | Swap [Member] | Derivative Contract 2 Period November 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	55,000
Price/Unit-Swap	50.26
Oil [Member] | Swap [Member] | Derivative Contract Period December 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	55,000
Price/Unit-Swap	50.22
Oil [Member] | Swap [Member] | Derivative Contract 2 Period December 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	55,000
Price/Unit-Swap	50.01
Oil [Member] | Swap [Member] | Derivative Contract Period January 2023 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	57,500
Price/Unit-Swap	49.81
Oil [Member] | Swap [Member] | Derivative Contract 2 Period January 2023 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	57,500
Price/Unit-Swap	49.79
Oil [Member] | Swap [Member] | Derivative Contract Period February 2023 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	57,500
Price/Unit-Swap	49.63
Oil [Member] | Swap [Member] | Derivative Contract 2 Period February 2023 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	57,500
Price/Unit-Swap	49.62
Oil [Member] | Swap [Member] | Mid-Con [Member] | Derivative Contract Period January 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,883
Price/Unit-Swap		55.78
Price/Unit-Floor		55.78
Oil [Member] | Swap [Member] | Mid-Con [Member] | Derivative Contract Period February 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,804
Price/Unit-Swap		55.78
Price/Unit-Floor		55.78
Oil [Member] | Swap [Member] | Mid-Con [Member] | Derivative Contract Period March 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,725
Price/Unit-Swap		55.78
Price/Unit-Floor		55.78
Oil [Member] | Swap [Member] | Mid-Con [Member] | Derivative Contract Period April 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,647
Price/Unit-Swap		55.78
Price/Unit-Floor		55.78
Oil [Member] | Swap [Member] | Mid-Con [Member] | Derivative Contract Period May 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,563
Price/Unit-Swap		55.78
Price/Unit-Floor		55.78
Oil [Member] | Swap [Member] | Mid-Con [Member] | Derivative Contract Period June 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,487
Price/Unit-Swap		55.78
Price/Unit-Floor		55.78
Oil [Member] | Swap [Member] | Mid-Con [Member] | Derivative Contract Period July 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,412
Price/Unit-Swap		55.78
Price/Unit-Floor		55.78
Oil [Member] | Swap [Member] | Mid-Con [Member] | Derivative Contract Period August 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,301
Price/Unit-Swap		55.78
Price/Unit-Floor		55.78
Oil [Member] | Swap [Member] | Mid-Con [Member] | Derivative Contract Period September 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,228
Price/Unit-Swap		55.78
Price/Unit-Floor		55.78
Oil [Member] | Swap [Member] | Mid-Con [Member] | Derivative Contract Period October 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,155
Price/Unit-Swap		55.78
Price/Unit-Floor		55.78
Oil [Member] | Swap [Member] | Mid-Con [Member] | Derivative Contract Period November 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,084
Price/Unit-Swap		55.78
Price/Unit-Floor		55.78
Oil [Member] | Swap [Member] | Mid-Con [Member] | Derivative Contract Period December 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item		20,012
Price/Unit-Swap		55.78
Price/Unit-Floor		55.78
Oil [Member] | Costless Swap [Member]
Derivative [Line Items]
Price/Unit-Swap			0.05
Fair Value | $				$ (100)
Oil [Member] | Costless Swap [Member] | Derivative Contract Period January To June 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			12,000
Oil [Member] | Costless Swap [Member] | Derivative Contract Period July To December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			10,000
Natural Gas [Member] | Derivative Contract Period 2021 [Member]
Derivative [Line Items]
Average floor price			2.62
Commodity Derivative Flow Rate | Bcf			12.4
Natural Gas [Member] | Derivative Contract Period 2022 [Member]
Derivative [Line Items]
Average floor price			2.60
Commodity Derivative Flow Rate | Bcf			10.1
Natural Gas [Member] | Collar Options [Member] | Derivative Contract Period January To March 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				225,000
Price/Unit-Floor				2.45
Price/Unit-Cap				3.40
Fair Value | $				$ 209
Natural Gas [Member] | Swap [Member] | Derivative Contract Period January To March 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				425,000
Price/Unit-Swap				2.841
Fair Value | $				$ 856
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 January Period to March 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				300,000
Price/Unit-Swap				2.53
Fair Value | $				$ 325
Natural Gas [Member] | Swap [Member] | Derivative Contract 3 Period January To March 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				300,000
Price/Unit-Swap				2.532
Fair Value | $				$ 327
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April To July 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				400,000
Price/Unit-Swap				2.532
Fair Value | $				$ 493
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period April To July 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				400,000
Price/Unit-Swap				2.53
Fair Value | $				$ 490
Natural Gas [Member] | Swap [Member] | Derivative Contract 3 April Period to July 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				400,000
Price/Unit-Swap				2.532
Fair Value | $				$ 493
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August to October 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				40,000
Price/Unit-Swap				2.532
Fair Value | $				$ 25
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				350,000
Price/Unit-Swap				2.53
Fair Value | $				$ 223
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period August to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				350,000
Price/Unit-Swap				2.532
Fair Value | $				$ 226
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November To December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item				375,000
Price/Unit-Swap				2.696
Fair Value | $				$ 134
Natural Gas [Member] | Swap [Member] | Derivative Contract Period January to March 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			185,000	185,000
Price/Unit-Swap			2.505	2.505
Fair Value | $			$ (1)	$ (78)
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period January to March 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			185,000	185,000
Price/Unit-Swap			2.508	2.508
Fair Value | $			$ (3)	$ (75)
Natural Gas [Member] | Swap [Member] | Derivative Contract 3 Period January To March 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			650,000	650,000
Price/Unit-Swap			2.508	2.508
Fair Value | $			$ (6)	$ (268)
Natural Gas [Member] | Swap [Member] | Derivative Contract Period March 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | MMBTU	100,000
Price/Unit-Swap	2.96
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April to July 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			120,000	120,000
Price/Unit-Swap			2.505	2.505
Fair Value | $			$ (43)	$ 99
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April to July 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | MMBTU	350,000
Price/Unit-Swap	2.96
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period April to July 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			120,000	120,000
Price/Unit-Swap			2.508	2.508
Fair Value | $			$ (44)	$ 104
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April to October 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			400,000	400,000
Price/Unit-Swap			2.508	2.508
Fair Value | $			$ (400)	$ 544
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April to November 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			70,000
Price/Unit-Swap			2.36
Fair Value | $			$ (175)
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August to September 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			10,000	10,000
Price/Unit-Swap			2.505	2.505
Fair Value | $			$ (4)	$ 4
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period August to September 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			10,000	10,000
Price/Unit-Swap			2.508	2.508
Fair Value | $			$ (4)	$ 4
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August to October 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | MMBTU	500,000
Price/Unit-Swap	2.96
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November 2021 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | MMBTU	450,000
Price/Unit-Swap	2.96
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November to December 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			580,000	580,000
Price/Unit-Swap			2.508	2.508
Fair Value | $			$ (402)	$ 20
Natural Gas [Member] | Swap [Member] | Derivative Contract Period December 2021 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			350,000
Price/Unit-Swap			2.36
Fair Value | $			$ (195)
Natural Gas [Member] | Swap [Member] | Derivative Contract Period January to March 2022 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			780,000
Price/Unit-Swap			2.542
Fair Value | $			$ (865)
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period January To March 2022 Member
Derivative [Line Items]
Commodity Derivative Flow Rate | item			250,000
Price/Unit-Swap			3.149
Fair Value | $			$ 179
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | MMBTU	175,000
Price/Unit-Swap	2.51
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April To July 2022 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			650,000
Price/Unit-Swap			2.515
Fair Value | $			$ 252
Natural Gas [Member] | Swap [Member] | Derivative Contract Period May To July 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | MMBTU	150,000
Price/Unit-Swap	2.51
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August to October 2022 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | MMBTU	400,000
Price/Unit-Swap	2.51
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August To October 2022 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item			350,000
Price/Unit-Swap			2.515
Fair Value | $			$ 71
Natural Gas [Member] | Swap [Member] | Derivative Contract November 2022 Period to February 2023 [Member] | Subsequent Event [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | MMBTU	750,000
Price/Unit-Swap	2.72

Derivative Instruments - Fair V

Derivative Instruments - Fair Value (Details) - Commodity Derivatives [Member] - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Assets
Gross	$ 3,493	$ 4,176
Total	3,493	4,176
Liabilities:
Gross	(2,965)	(5,971)
Total	$ (2,965)	$ (5,971)

Derivative Instruments (Operati

Derivative Instruments (Operations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain	$ 25,264	$ 2,616
Unrealized gain (loss)	2,321	(5,973)
Gain (loss) on derivatives, net	27,585	(3,357)
Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain	18,561	1,614
Unrealized gain (loss)	8,120	(10,012)
Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain	6,703	1,002
Unrealized gain (loss)	$ (5,799)	$ 4,039

Stock Based Compensation (Detai

Stock Based Compensation (Details) - shares	Jun. 08, 2020	Jun. 07, 2020	Dec. 31, 2020	Dec. 31, 2019	Feb. 25, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock authorized for grants increase (in shares)	9,000,000
Maximum shares to an individual	1,000,000	250,000
Shares available for grant			6,240,312	1,480,389
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			3 years
Stock Incentive Plan 2005 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for grant					0
Employee Stock Options [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration term			5 years
Employee Stock Options [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration term			10 years
Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			3 years
Target (as a percent)			100.00%
Performance Stock Units [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target (as a percent)			0.00%
Performance Stock Units [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target (as a percent)			300.00%

Stock Based Compensation (Optio

Stock Based Compensation (Options) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Option roll forward
Outstanding, beginning of year (in shares)	20,964	33,637
Expired / Forfeited (in shares)	(1,117)	(12,673)
Outstanding, end of year (in shares)	19,847	20,964
Exercisable, end of year (in shares)	19,847	20,964
Option roll forward per share
Outstanding, beginning of year (in dollars per share)	$ 58.53	$ 55.82
Expired / Forfeited (in dollars per share)	39	51.34
Outstanding, end of year (in dollars per share)	59.62	58.53
Exercisable, end of year (in dollars per share)	$ 59.62	$ 58.53
Stock-based compensation
Aggregate intrinsic value of exercises during period	$ 0	$ 0
Shares available for grant	6,240,312	1,480,389
Options exercise price, minimum (in dollars per share)	$ 28.96
Options exercise price, maximum (in dollars per share)	$ 60.33
Granted vested options, remaining contractual term	2 months 12 days
Excess tax benefit from exercise/cancellation of stock options	$ 0	$ 0

Stock Based Compensation (NonOp

Stock Based Compensation (NonOptions) (Details) $ / shares in Units, $ in Thousands	1 Months Ended		12 Months Ended
	Dec. 31, 2020USD ($)$ / sharesshares	Jan. 31, 2020USD ($)$ / sharesshares	Dec. 31, 2020USD ($)$ / sharesshares	Dec. 31, 2019USD ($)$ / sharesshares
Maximum [Member]
Stock-based compensation
Vesting period			3 years
Restricted Stock [Member]
Activity, shares
Outstanding, beginning of the period (in shares)		403,221	403,221	459,621
Granted (in shares)			1,244,527	388,060
Vested (in shares)			(289,636)	(353,114)
Canceled/Forfeited (in shares)			(55,064)	(91,346)
Not vested, end of the period (in shares)	1,303,048		1,303,048	403,221
Activity, weighted average fair value
Outstanding, beginning of the period (in dollars per share) | $ / shares		$ 3.66	$ 3.66	$ 7.26
Granted (in dollars per share) | $ / shares			2.22	2.91
Vested (in dollars per share) | $ / shares			3.48	7.41
Canceled/Forfeited (in dollars per share) | $ / shares			2.45	4.08
Not vested, end of the period (in dollars per share) | $ / shares	$ 2.38		$ 2.38	$ 3.66
Activity, intrinsic value
Outstanding, beginning of the period | $		$ 214	$ 214	$ 662
Granted | $			65
Vested | $			700	1,171
Canceled/Forfeited | $			16	41
Not vested, end of the period | $	$ 228		228	214
Stock-based compensation
Value of issued stock | $			$ 2,800	$ 1,100
Weighted average forfeiture rate			0	0
Stock-based compensation expense | $			$ 1,300	$ 1,900
Compensation expense not yet recognized | $	$ 2,300		$ 2,300
Remaining period to recognize compensation expense			2 years 1 month 6 days
Restricted Stock [Member] | New And Existing Employees [Member]
Activity, shares
Granted (in shares)			1,041,365	307,650
Stock-based compensation
Vesting period			3 years	3 years
Restricted Stock [Member] | Board of Directors [Member]
Activity, shares
Granted (in shares)			152,248	80,410
Stock-based compensation
Vesting period			1 year	1 year
Stock granted in lieu of cash fee			50,914
Performance Stock Units [Member]
Activity, shares
Granted (in shares)			2,846,140	117,105
Vested (in shares)	(68,476)	(77,485)
Canceled/Forfeited (in shares)			0	(71,945)
Activity, weighted average fair value
Granted (in dollars per share) | $ / shares			$ 4.90	$ 6.42
Stock-based compensation
Vesting period			3 years
Stock-based compensation expense | $			$ 3,000	$ 500
Compensation expense not yet recognized | $	$ 11,700		$ 11,700
Remaining period to recognize compensation expense			2 years 3 months 18 days
Target (as a percent)			100.00%
Withheld for taxes (in shares)	18,284	22,972
Performance Stock Units [Member] | Minimum [Member]
Stock-based compensation
Target (as a percent)			0.00%
Performance Stock Units [Member] | Maximum [Member]
Stock-based compensation
Target (as a percent)			300.00%
Performance Stock Units [Member] | Former Senior Vice President [Member]
Activity, shares
Canceled/Forfeited (in shares)				(49,773)

Share Repurchase Programs (Deta

Share Repurchase Programs (Details) - $50 Million Share Repurchase Program [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Sep. 30, 2011
Equity, Class of Treasury Stock [Line Items]
Approved share repurchase program value			$ 50
Treasury shares at cost (in shares)	0	0
Value of repurchase program available for future purchases	$ 31.8

Leases - Balance sheet (Details

Leases - Balance sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Balance sheet information
Operating lease right of use asset	$ 2,452	$ 4,316
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	mcf:OperatingAndFinanceLeaseRightOfUseAsset	mcf:OperatingAndFinanceLeaseRightOfUseAsset
Operating lease liability - current	$ (1,832)	$ (2,597)
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:AccountsPayableAndAccruedLiabilitiesCurrent	us-gaap:AccountsPayableAndAccruedLiabilitiesCurrent
Operating lease liability - long-term	$ (522)	$ (1,738)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	mcf:OperatingAndFinanceLeaseLiabilityNoncurrent	mcf:OperatingAndFinanceLeaseLiabilityNoncurrent
Total operating lease liability	$ (2,354)	$ (4,335)
Financing lease right of use asset	$ 2,996	$ 1,569
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	mcf:OperatingAndFinanceLeaseRightOfUseAsset	mcf:OperatingAndFinanceLeaseRightOfUseAsset
Financing lease liability - current	$ (940)	$ (524)
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:AccountsPayableAndAccruedLiabilitiesCurrent	us-gaap:AccountsPayableAndAccruedLiabilitiesCurrent
Financing lease liability - long-term	$ (2,102)	$ (1,051)
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	mcf:OperatingAndFinanceLeaseLiabilityNoncurrent	mcf:OperatingAndFinanceLeaseLiabilityNoncurrent
Total financing lease liability	$ (3,042)	$ (1,575)

Leases - Lease Terms and Discou

Leases - Lease Terms and Discount (Details)	Dec. 31, 2020	Dec. 31, 2019
Leases
Weighted Average Remaining Lease Terms (in years): Operating leases	1 year 5 months 19 days	2 years 1 month 28 days
Weighted Average Remaining Lease Terms (in years): Financing leases	3 years 2 months 27 days	3 years 1 month 21 days
Weighted Average Discount Rate: Operating leases	5.72%	6.04%
Weighted Average Discount Rate: Financing leases	5.92%	6.24%

Leases - Future Maturities (Det

Leases - Future Maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Operating lease maturities
2021	$ 1,906
2022	240
2023	170
2024	158
Total operating lease liability	2,474
Less: imputed interest	(120)
Present value of lease liabilities	2,354	$ 4,335
Finance lease maturities
2021	1,094
2022	980
2023	823
2024	459
Total financing lease liability	3,356
Less: imputed interest	(314)
Present value of lease liabilities	$ 3,042	$ 1,575

Leases - Costs (Details)

Leases - Costs (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Leases
Operating lease cost	$ 843	$ 542	$ 3,055	$ 742
Financing lease cost - amortization of right-of-use assets	231	87	642	92
Financing lease cost - interest on lease liabilities	47	17	131	18
Administrative lease cost	19	19	75	75
Short-term lease cost	360	741	1,974	4,101
Total lease cost	$ 1,500	$ 1,406	5,877	5,028
Cash payments relating to operating leases			3,200	800
Cash payments relating to finance leases			$ 900	$ 100

Other Financial Information (Ba

Other Financial Information (Balance Sheet) (Details) - USD ($) $ in Thousands	1 Months Ended
	Apr. 30, 2020	Dec. 31, 2020	Dec. 31, 2019
Accounts receivable:
Trade receivables		$ 20,306	$ 21,110
Receivable for Alta Resources distribution		1,712	1,712
Joint interest billings		15,637	13,104
Income taxes receivable		268	509
Other receivables		2,209	4,126
Allowance for doubtful accounts		(2,270)	(994)
Total accounts receivable		37,862	39,567
Prepaid Expenses
Prepaid insurance		2,825	683
Other		535	508
Total prepaid expenses		3,360	1,191
Accounts payable and accrued liabilities:
Royalties and revenue payable		23,701	15,905
Legal Suspense Related To Revenue		27,983	33,739
Advances from partners		76	6,733
Accrued exploration and development		490	8,210
Trade payables		14,273	14,086
Accrued general and administrative expenses		6,191	12,037
Accrued operating expenses		5,755	5,794
Accrued operating and finance leases		2,772	3,120
Other accounts payable and accrued liabilities		2,729	4,969
Total accounts payable and accrued liabilities		$ 83,970	$ 104,593
Loss contingent payment	$ 6,300

Other Financial Information (Su

Other Financial Information (Supplemental CFS) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cash payments:
Interest payments	$ 3,592	$ 7,761
Income tax payments	293	668
Non-cash items excluded from investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$ (7,615)	$ 1,841

Investment in Exaro Energy II_2

Investment in Exaro Energy III LLC (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments Financials
Gain (loss) from investment in affiliates, net of income taxes	$ 27,000	$ 742,000
Exaro Energy III LLC [Member]
Schedule of Equity Method Investments Financials
Investment in affiliate	$ 46,900,000
Equity method investment, ownership percentage	37.00%
Total Investment Commitment In Affiliates With Other Parties	$ 183,000,000
Share of equity in investment	6,800,000
Gain (loss) from investment in affiliates, net of income taxes	27,000	1,000,000
Tax (expense) benefit from equity investment	0	$ 0
Exaro Energy III LLC [Member] | Maximum [Member]
Schedule of Equity Method Investments Financials
Investment in affiliate	$ 67,500,000

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation [Abstract]
Balance as of the beginning of the period	$ 51,665	$ 13,497
Liabilities incurred during period	5	256
Liabilities settled during period	(338)	(1,380)
Accretion	2,702	1,062
Sales	(5,239)	(816)
Acquisitions		37,596
Change in estimate	3,978	1,450
Balance as of the end of the period	$ 52,773	$ 51,665

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands	Oct. 30, 2020USD ($)Lender	Oct. 01, 2020	Sep. 17, 2020USD ($)	Jun. 09, 2020USD ($)	Apr. 10, 2020USD ($)	Apr. 01, 2020	Nov. 01, 2019USD ($)item	Sep. 17, 2019USD ($)	Jan. 31, 2021USD ($)	Sep. 30, 2020USD ($)	Jun. 30, 2020USD ($)	Dec. 31, 2020USD ($)	Jun. 30, 2020USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Jan. 21, 2021USD ($)	Oct. 29, 2020USD ($)
Debt Instrument [Line Items]
Debt issuance costs incurred														$ 74	$ 3,455
Amortization of debt issuance costs														1,603	144
Interest expense														5,022	8,596
Paycheck Protection Program, CARES Act [Member]
Debt Instrument [Line Items]
Loan amount					$ 3,400
Original term of loan					2 years
Stated interest rate (as a percent)					1.00%
JPMorgan Chase Bank [Member]
Debt Instrument [Line Items]
Borrowing capacity				$ 95,000			$ 145,000	$ 65,000				$ 75,000		75,000		$ 130,000	$ 75,000
Number of additional lenders	3						2
Periodic borrowing base reduction	$ 10,000									$ 10,000	$ 10,000
Margin rate	25.00%		50.00%
Hedging requirement percentage	75.00%
Hedging requirement period		30 days				24 months
Debt issuance costs incurred	$ 100			$ 0			$ 1,600	$ 1,800	$ 900			100
Amortization of debt issuance costs													$ 1,000	1,600
Remaining balance debt issue costs												1,800		1,800
Credit facility amount outstanding												9,000		9,000	72,800
Letters of credit amount outstanding												1,900		1,900	1,900
Line of credit, available												$ 64,100		64,100
Interest expense														$ 5,000	$ 8,600
Weighted average interest rate (as a percent)												2.90%		2.90%	4.30%
Current ratio, minimum								1
Leverage ratio, maximum								3.50
Maximum cash balance			$ 5,000
JPMorgan Chase Bank [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Borrowing capacity																$ 130,000
Debt issuance costs incurred									$ 900
JPMorgan Chase Bank [Member] | Minimum [Member]
Debt Instrument [Line Items]
Variable interest rate (as a percent)														1.75%
JPMorgan Chase Bank [Member] | Maximum [Member]
Debt Instrument [Line Items]
Variable interest rate (as a percent)														3.75%

Commitments and Contingencies -

Commitments and Contingencies - Maturities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Future future operating and finance lease payments and other commitments
2021	$ 3,941
2022	2,163
2023	1,872
2024	1,496
2025 and thereafter	879
Total	10,351
Lease commitment	$ 4,300	$ 1,500

Commitments and Contingencies_2

Commitments and Contingencies (Details) $ in Thousands	Nov. 16, 2010USD ($)item	Dec. 31, 2019USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Sep. 30, 2019USD ($)
Loss Contingency
Accounts payable and accrued liabilities		$ 104,593	$ 83,970	$ 104,593
Throughput commitment
Loss Contingency
Loss contingency provision accrual increase				1,000
Fees incurred			0	$ 1,000
Lavaca County Case [Member]
Loss Contingency
Loss contingency provision accrual increase		$ 6,300
Number of wells involved in litigation | item	2
Damages sought by plaintiffs	$ 5,300
Accounts payable and accrued liabilities			3,500
Litigation Case Harris County [Member]
Loss Contingency
Loss contingency provision accrual increase			$ 2,100
Accounts payable					$ 1,100

Net Loss Per Common Share (Deta

Net Loss Per Common Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Net Loss Per Common Share
Net loss attributable to common stock	$ (25,248)	$ (6,805)	$ (28,034)	$ (105,255)	$ (138,379)	$ (7,838)	$ (4,961)	$ (8,618)	$ (165,342)	$ (159,796)
Net loss attributable to common stock									$ (165,342)	$ (159,796)
Weighted average shares, basic (in shares)									137,522,000	54,136,000
Diluted (in shares)									137,522,000	54,136,000
Basic									$ (1.20)	$ (2.95)
Diluted									$ (1.20)	$ (2.95)
Potentially dilutive (in shares)									529,508	613,506

Income Taxes - Rate Reconciliat

Income Taxes - Rate Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Income Taxes [Abstract]
Benefit at statutory tax rate	21.00%	21.00%
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Benefit at statutory tax rate	$ (34,663)	$ (33,561)
State income tax provision, net of federal benefit	467	555
State deferred tax benefit	(5,553)
Permanent differences	26	30
Stock based compensation	81	979
Valuation allowance	40,059	34,239
Other	330	(2,022)
Income tax provision	$ 747	$ 220
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Benefit at statutory tax rate	21.00%	21.00%
State income tax provision, net of federal benefit	(0.28%)	(0.35%)
State deferred tax benefit	3.36%
Permanent differences	(0.02%)	(0.02%)
Stock based compensation	(0.05%)	(0.61%)
Valuation allowance	(24.27%)	(21.42%)
Other	(0.20%)	1.26%
Income tax provision /(benefit)	(0.46%)	(0.14%)

Income Taxes - Provision (Benef

Income Taxes - Provision (Benefit) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2020	Dec. 31, 2020	Dec. 31, 2019
Current tax provision (benefit):
Federal		$ 275	$ (335)
State		472	555
Total		747	220
Total tax provision (benefit):
Federal		275	(335)
State		472	555
Income tax provision		747	220
Total		747	220
Increase in income taxes receivable	$ 300	$ (281)	$ 85

Income Taxes - Deferred Tax (De

Income Taxes - Deferred Tax (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred tax assets:
Net operating loss carryforward	$ 84,982	$ 80,617
Deferred compensation	447
Derivative instruments		377
State deferred tax assets	6,507	954
Oil and gas properties	39,081	11,436
Investment in affiliates	752	2,799
Recognized built in loss carryforward	9,987	6,718
163(j) Carryforward	1,828	1,585
Other	1,796	964
Total deferred tax assets before valuation allowance	145,380	105,450
Valuation allowance	(145,269)	(105,212)
Net deferred tax assets	111	238
Deferred tax liability:
Deferred compensation		(238)
Derivative instruments	(111)
Deferred tax liability	$ (111)	$ (238)

Income Taxes - NOL (Details)

Income Taxes - NOL (Details) - USD ($) $ in Thousands	Dec. 01, 2020	Oct. 27, 2020	Jun. 24, 2020	Nov. 19, 2018	Dec. 31, 2020	Dec. 31, 2019	Sep. 12, 2019
Operating Loss Carryforwards [Line Items]
Valuation allowance					$ 145,269	$ 105,212
Equity offering-common stock, shares	14,193,903	26,451,988	163,929	8,600,000
Annual carryover limitation				$ 2,400			$ 700,000
Built in gains carryover limitation period				5 years
Carryover limitation period				20 years
Interest deduction limitation					2,400
NOLs not subject to expiration					132,700
Interest and penalties related to unrecognized tax benefits					0
Unrecognized tax benefits that would impact effective tax rate					0
Follow On Offering [Member]
Operating Loss Carryforwards [Line Items]
Equity offering-common stock, shares				7,500,000
Over-Allotment Option [Member]
Operating Loss Carryforwards [Line Items]
Equity offering-common stock, shares				1,100,000
Federal [Member]
Operating Loss Carryforwards [Line Items]
Valuation allowance					138,800
Operating loss carryforwards					404,700
State [Member]
Operating Loss Carryforwards [Line Items]
Valuation allowance					6,500
Operating loss carryforwards					$ 26,400

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) $ in Thousands	Feb. 01, 2021	Jan. 21, 2021	Nov. 27, 2020	Dec. 31, 2020
Mid-Con [Member]
Subsequent Event [Line Items]
Right to receive shares (in shares)		1.75
Common stock issued for acquisition (in shares)		25,409,000
Cash consideration for acquisition		$ 14,520
Silvertip Acquisition [Member]
Subsequent Event [Line Items]
Aggregate consideration			$ 58,000
Acquisition deposit			$ 7,000	$ 7,000
Subsequent Event [Member] | Mid-Con [Member]
Subsequent Event [Line Items]
Right to receive shares (in shares)		1.75
Common stock issued for acquisition (in shares)		25,409,164
Subsequent Event [Member] | Silvertip Acquisition [Member]
Subsequent Event [Line Items]
Aggregate consideration	$ 58,000
Acquisition deposit	7,000
Cash consideration for acquisition	$ 46,200