W&T Offshore (WTI) 10-K 5 Mar 20 2019 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Feb. 28, 2020	Jun. 28, 2019
Document Information [Line Items]
Entity Registrant Name	W&T OFFSHORE INC
Entity Central Index Key	0001288403
Trading Symbol	wti
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Interactive Data Current	Yes
Entity Common Stock, Shares Outstanding (in shares)		141,668,942
Entity Public Float			$ 463,023
Entity Shell Company	false
Document Type	10-K
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false
Title of 12(b) Security	Common Stock, par value $0.00001

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 32,433	$ 33,293
Receivables:
Oil and natural gas sales	57,367	47,804
Joint interest, net	19,400	14,634
Income taxes	1,861	54,076
Total receivables	78,628	116,514
Prepaid expenses and other assets (Note 1)	30,691	76,406
Total current assets	141,752	226,213
Oil and natural gas properties and other, net – at cost: (Note 1)	748,798	515,421
Restricted deposits for asset retirement obligations	15,806	15,685
Deferred income taxes	63,916
Other assets (Note 1)	33,447	91,547
Total assets	1,003,719	848,866
Current liabilities:
Accounts payable	102,344	82,067
Undistributed oil and natural gas proceeds	29,450	28,995
Advances from joint interest partners	5,279	20,627
Asset retirement obligations	21,991	24,994
Accrued liabilities (Note 1)	30,896	29,611
Total current liabilities	189,960	186,294
Long-term debt: (Note 2)
Principal	730,000	646,000
Carrying value adjustments	(10,467)	(12,465)
Long-term debt – carrying value	719,533	633,535
Asset retirement obligations, less current portion	333,603	285,143
Other liabilities (Note 1)	9,988	68,690
Commitments and contingencies (Note 18)
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000 shares authorized; 0 issued at December 31, 2019 and December 31, 2018
Common stock, $0.00001 par value; 200,000 shares authorized; 144,538 issued and 141,669 outstanding at December 31, 2019 and 143,513 issued and 140,644 outstanding at December 31, 2018	1	1
Additional paid-in capital	547,050	545,705
Retained deficit	(772,249)	(846,335)
Treasury stock, at cost; 2,869 shares at December 31, 2019 and December 31, 2018	(24,167)	(24,167)
Total shareholders’ deficit	(249,365)	(324,796)
Total liabilities and shareholders’ deficit	$ 1,003,719	$ 848,866

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Preferred stock, par value (in dollars per share)	$ 0.00001	$ 0.00001
Preferred stock, shares authorized (in shares)	20,000,000	20,000,000
Preferred stock, shares issued (in shares)	0	0
Common stock, par value (in dollars per share)	$ 0.00001	$ 0.00001
Common stock, shares authorized (in shares)	200,000,000	200,000,000
Common stock, shares issued (in shares)	144,538,000	143,513,000
Common stock, shares outstanding (in shares)	141,669,000	140,644,000
Treasury stock, shares (in shares)	2,869,000	2,869,000

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Total revenues	$ 534,896	$ 580,706	$ 487,096
Operating costs and expenses:
Lease operating expenses	184,281	153,262	143,738
Production taxes	2,524	1,832	1,740
Gathering and transportation	25,950	22,382	20,441
Depreciation, depletion and amortization	129,038	131,423	138,510
Asset retirement obligations accretion	19,460	18,431	17,172
General and administrative expenses	55,107	60,147	59,744
Derivative loss (gain)	59,887	(53,798)	(4,199)
Total costs and expenses	476,247	333,679	377,146
Operating income	58,649	247,027	109,950
Interest expense, net	59,569	48,645	45,521
Gain on debt transactions		47,109	7,811
Other expense (income), net	188	(3,871)	5,127
(Loss) income before income tax (benefit) expense	(1,108)	249,362	67,113
Income tax (benefit) expense	(75,194)	535	(12,569)
Net income	$ 74,086	$ 248,827	$ 79,682
Basic and diluted earnings per common share (in dollars per share)	$ 0.52	$ 1.72	$ 0.56
Oil and Condensate [Member]
Revenues:
Total revenues	$ 399,790	$ 438,798	$ 340,010
Natural Gas Liquids [Member]
Revenues:
Total revenues	22,373	37,127	32,257
Natural Gas, Production [Member]
Revenues:
Total revenues	106,347	99,629	108,923
Product and Service, Other [Member]
Revenues:
Total revenues	$ 6,386	$ 5,152	$ 5,906

Consolidated Statements of Chan

Consolidated Statements of Changes in Shareholders' Equity (Deficit) - USD ($) shares in Thousands, $ in Thousands		Common Stock Outstanding [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Total
Balances (in shares) at Dec. 31, 2016		137,674			2,869
Balances at Dec. 31, 2016		$ 1	$ 539,973	$ (1,174,844)	$ (24,167)	$ (659,037)
Share-based compensation			7,191			7,191
Stock issued (in shares)		1,417
Stock issued
RSUs and shares surrendered for payroll taxes	[1]		(1,344)			(1,344)
Net income				79,682		79,682
Balances (in shares) at Dec. 31, 2017		139,091			2,869
Balances at Dec. 31, 2017		$ 1	545,820	(1,095,162)	$ (24,167)	(573,508)
Share-based compensation			3,540			3,540
Stock issued (in shares)		1,553
Stock issued
RSUs and shares surrendered for payroll taxes			(3,655)			(3,655)
Net income				248,827		248,827
Balances (in shares) at Dec. 31, 2018		140,644			2,869
Balances at Dec. 31, 2018		$ 1	545,705	(846,335)	$ (24,167)	(324,796)
Share-based compensation			3,690			3,690
Stock issued (in shares)		1,025
Stock issued
RSUs and shares surrendered for payroll taxes			(2,345)			(2,345)
Net income				74,086		74,086
Balances (in shares) at Dec. 31, 2019		141,669			2,869
Balances at Dec. 31, 2019		$ 1	$ 547,050	$ (772,249)	$ (24,167)	$ (249,365)
[1]	RSUs defined in Note 9

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities:
Net income	$ 74,086	$ 248,827	$ 79,682
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	148,498	149,854	155,682
Gain on debt transactions		(47,109)	(7,811)
Amortization of debt items and other items	5,514	2,850	1,715
Share-based compensation	3,690	3,540	7,191
Derivative loss (gain)	59,887	(53,798)	(4,199)
Derivatives cash receipts (payments), net	13,941	(28,164)	4,199
Deferred income taxes	(64,102)	500	217
Changes in operating assets and liabilities:
Oil and natural gas receivables	(9,563)	(2,361)	(2,370)
Joint interest receivables	(4,766)	5,120	2,131
Insurance reimbursements			31,740
Income taxes	52,214	11,028	(1,063)
Prepaid expenses and other assets	(9,346)	3,383	3,238
Escrow deposit - Apache lawsuit			(49,500)
Asset retirement obligation settlements	(11,443)	(28,617)	(72,409)
Cash advances from JV partners	(15,347)	16,629	(437)
Accounts payable, accrued liabilities and other	(11,036)	40,081	11,402
Net cash provided by operating activities	232,227	321,763	159,408
Investing activities:
Investment in oil and natural gas properties and equipment	(125,706)	(106,191)	(106,174)
Acquisition of property interests	(188,019)	(16,782)
Proceeds from sales of assets, net		56,588
Purchases of furniture, fixtures and other	(89)		(933)
Net cash used in investing activities	(313,814)	(66,385)	(107,107)
Financing activities:
Borrowings on credit facility	150,000	61,000
Repayments on credit facility	(66,000)	(40,000)
Issuance of Senior Second Lien Notes		625,000
Extinguishment of debt – principal		(903,194)
Extinguishment of debt – premiums		(21,850)
Payment of interest on 1.5 Lien Term Loan		(6,623)	(8,227)
Debt transactions costs	(939)	(17,457)	(421)
Other	(2,334)	(3,622)	(1,295)
Net cash provided by (used in) financing activities	80,727	(321,143)	(23,479)
(Decrease) increase in cash and cash equivalents	(860)	(65,765)	28,822
Cash and cash equivalents, beginning of period	33,293	99,058	70,236
Cash and cash equivalents, end of period	32,433	33,293	99,058
Second Lien PIK Toggle Notes [Member]
Financing activities:
Payment of interest on PIK Toggle Notes		(9,725)	(7,335)
Third Lien PIK Toggle Notes [Member]
Financing activities:
Payment of interest on PIK Toggle Notes		$ (4,672)	$ (6,201)

Note 1 - Significant Accounting

Note 1 - Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Significant Accounting Policies [Text Block]	1. Operations W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”, is an independent oil and natural gas producer with substantially all of its operations in the Gulf of Mexico. We are active in the exploration, development and acquisition of oil and natural gas properties. Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and our 100% 4. Basis of Presentation Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries. Our interests in oil and gas joint ventures are proportionately consolidated. All significant intercompany transactions and amounts have been eliminated for all years presented. Our consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). 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, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. Realized Prices The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital, proved reserves and future rate of growth. The average realized prices of these commodities decreased in 2 019 2018. Accounting Standard Updates Effective January 1, 2019 In February 2016, 2016 02, Topic 842 2016 02” 2016 02 not 2016 02 first 2019 January 1, 2019. no 7 Cash Equivalents We consider all highly liquid investments purchased with original or remaining maturities of three Revenue Recognition We recognize revenue from the sale of crude oil, NGLs, and natural gas when our performance obligations are satisfied. Our contracts with customers are primarily short-term (less than 12 We record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not not December 31, 2019 2018, $3.6 $4.1 Concentration of Credit Risk Our customers are primarily large integrated oil and natural gas companies and large commodity trading companies. The majority of our production is sold utilizing month-to-month contracts that are based on bid prices. We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third The following table identifies customers from whom we derived 10% Year Ended December 31, 2019 2018 2017 Customer Shell Trading (US) Co./ Shell Energy N.A. 11 % 30 % 46 % BP Products North America 40 % 20 % ** Vitol Inc. 12 % 14 % 15 % ** Less than 10% We believe that the loss of any of the customers above would not Accounts Receivables and Allowance for Bad Debts Our accounts receivables are recorded at their historical cost, less an allowance for doubtful accounts. The carrying value approximates fair value because of the short-term nature of such accounts. In addition to receivables from sales of our production to our customers, we also have receivables from joint interest owners on properties we operate. In certain arrangements, we have the ability to withhold future revenue disbursements to recover amounts due us from the joint interest partners. We use the specific identification method of determining if an allowance for doubtful accounts is needed and the amounts recorded relate to certain joint interest owners. The following table describes the balance and changes to the allowance for doubtful accounts (in thousands): 2019 2018 2017 Allowance for doubtful accounts, beginning of period $ 9,692 $ 9,114 $ 7,602 Additional provisions for the year 206 1,233 1,512 Uncollectible accounts written off — (655 ) — Allowance for doubtful accounts, end of period $ 9,898 $ 9,692 $ 9,114 Prepaid expenses and other assets Amounts recorded in Prepaid expenses and other assets one December 31, 2019 2018 Derivatives – current (1) $ 7,266 $ 60,687 Unamortized bonds/insurance premiums 4,357 5,197 Prepaid deposits related to royalties 7,980 8,872 Prepayment to vendors 10,202 864 Other 886 786 Prepaid expenses and other assets $ 30,691 $ 76,406 ( 1 Includes both open and closed contracts. Properties and Equipment We use the full-cost method of accounting for oil and natural gas properties and equipment, which are recorded at cost. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties. Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs. Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred. Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs related to proved reserves are not Sales of proved and unproved oil and natural gas properties, whether or not no Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five seven Oil and Natural Gas Properties and Other, Net – at cost Oil and natural gas properties and equipment are recorded at cost using the full cost method. There were no December 31, 2019 2018 Oil and natural gas properties and equipment $ 8,532,196 $ 8,169,871 Furniture, fixtures and other 20,317 20,228 Total property and equipment 8,552,513 8,190,099 Less accumulated depreciation, depletion and amortization 7,803,715 7,674,678 Oil and natural gas properties and other, net $ 748,798 $ 515,421 Ceiling Test Write-Down Under the full-cost method of accounting, we are required to perform a “ceiling test” calculation quarterly, which determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized ARO) net of related deferred income taxes exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed. Any such write downs are not 10%; not first twelve We did not 2019, 2018 2017. 2020 Asset Retirement Obligations We are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet. We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating such costs requires us to make judgments on both the costs and the timing of ARO. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. See Note 6 Oil and Natural Gas Reserve Information We use the unweighted average of first 12 12 may five 20 Derivative Financial Instruments We have exposure related to commodity prices and have used various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas. We do not 2019, 2018 2017, December 31, 2019, may 2019, 2018 2017, not Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value. We have elected not may may not Fair Value of Financial Instruments We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance. We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments. We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments. Income Taxes We use the liability method of accounting for income taxes in accordance with the Income Taxes not not not 13 Other Assets (long-term) The major categories recorded in Other assets December 31, 2019 2018 Appeal bond deposits $ 6,925 $ 6,925 Escrow deposit – Apache lawsuit (Note 18) — 49,500 Unamortized debt issuance costs 3,798 4,773 Investment in White Cap, LLC 2,590 2,586 Derivatives 2,653 21,275 Unamortized brokerage fee for Monza 3,423 2,277 Proportional consolidation of Monza's other assets (Note 4) 5,308 3,275 ROU assets (Note 7) 7,936 — Other 814 936 Total other assets $ 33,447 $ 91,547 Accrued Liabilities The major categories recorded in Accrued liabilities December 31, 2019 2018 Accrued interest $ 10,180 $ 12,385 Accrued salaries/payroll taxes/benefits 2,377 2,320 Incentive compensation plans 9,794 10,817 Litigation accruals 3,673 3,673 Lease liability (Note 7) 2,716 — Derivatives 1,785 — Other 371 416 Total accrued liabilities $ 30,896 $ 29,611 Debt Issued During 2016 We accounted for a debt exchange transaction in 2016, 2, 470 60, Troubled Debt Restructuring 470 60” 470 60, 2016 2 no 2016 January 1, 2017 October 18, 2018. 2016 470 60. 2 Debt Issuance Costs Debt issuance costs associated with the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) are amortized using the straight-line method over the scheduled maturity of the debt. Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method. Unamortized debt issuance costs associated with our Credit Agreement is reported within Other Assets Long-term debt – carrying value 2 Discounts Provided on Debt Issuance Discounts were recorded in Long-term debt – carrying value Gain on Debt Transactions During 2018, $47.1 2016, 2017, 2 Other Liabilities (long-term) The major categories recorded in Other liabilities December 31, 2019 2018 Dispute related to royalty deductions $ 4,687 $ 4,687 Dispute related to royalty-in-kind 250 2,235 Lease liability (Note 7) 4,419 — Apache lawsuit (Note 18) — 49,500 Uncertain tax positions including interest/penalties (Note 13) — 11,523 Other 632 745 Total other liabilities (long-term) $ 9,988 $ 68,690 Share-Based Compensation Compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award. The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant. We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award. Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 11 Other Expense (Income), Net For 2019, 4 2018, 2017, third one Earnings Per Share Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per share under the two 14 Recent Accounting Developments In June 2016, No. 2016 13, Financial Instruments – Credit Losses Topic 326 2016 13” 2016 13 December 15, 2019 December 15, 2018. not In August 2017, No. 2017 12, Derivatives and Hedging (Topic 815 2017 12” 2017 12 2017 12 December 15, 2019 December 15, 2020. not not

Note 2 - Long-term Debt

Note 2 - Long-term Debt	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Long-term Debt [Text Block]	2. The components of our long-term debt are presented in the following tables (in thousands): December 31, 2019 2018 Credit Agreement borrowings $ 105,000 $ 21,000 Senior Second Lien Notes: Principal 625,000 625,000 Unamortized debt issuance costs (10,467 ) (12,465 ) Total Senior Second Lien Notes 614,533 612,535 Total long-term debt $ 719,533 $ 633,535 Aggregate annual maturities of amounts recorded for long-term debt as of December 31, 2019 2020–$0.0; 2021–$0.0; 2022–$105.0; 2023 $625.0. 9.75% 2023 On October 18, 2018, $625.0 9.75% 2023 9.75% November 1, 2023, October 18, 2018, 10.3%, May 1 November 1 Prior to November 1, 2020, may 100% November 1, 2020, may, one 35% not 109.750% On and after November 1, 2020, may 104.875% 12 November 1, 2020, 102.438% 12 November 1, 2021, 100.000% November 1, 2022 101.000% Certain entities controlled by Tracy W. Krohn, Chairman, Chief Executive Officer ("CEO") and President of the Company, and his family were invested in certain existing notes of the Company that were repurchased by the Company in connection with the Refinancing Transaction (defined below). The Krohn entities tendered their existing notes on the same terms as were made available to all other holders of the existing notes pursuant to the publicly disclosed Company offer to purchase any and all such notes and reinvested an amount approximately equal to the proceeds from such tenders by purchasing approximately $8.0 2018 $5.0 The Senior Second Lien Notes are secured by a second not no Credit Agreement Concurrently with the issuance of the Senior Second Lien Notes, we renewed our credit facility by entering into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”), dated as of October 18, 2018, October 18, 2022. ● The initial borrowing base is $250.0 ● Letters of credit may $30.0 ● The Leverage Ratio, as defined in the Credit Agreement, is limited to 3.00 1.00 December 31, 2019 3.50 1.00 two 5, ● The Current Ratio, as defined in the Credit Agreement, must be maintained at greater than 1.00 1.00. ● We are required to have deposit accounts only with banks under the Credit Agreement with certain exceptions. ● To the extent there are borrowings, the Applicable Margins, as defined in the Credit Agreement, for Eurodollar Loans range from 2.50% 3.50% 1.50% 2.50% ● The commitment fee is 37.5 50% 50 50% ● We were required to have derivative contracts for a minimum of 50% 18 December 2, 2018 may Availability under the Credit Agreement is subject to semi-annual redeterminations of our borrowing base to occur on or before May 15 November 14 may first Borrowings outstanding under the Credit Agreement are reported in the table above. As of December 31, 2019 2018, $5.8 $9.6 4.9%. As of December 31, 2019, For information about fair value measurements of our long-term debt, refer to Note 3. Refinancing Transaction in 2018 On October 18, 2018, $47.1 2018 $0.33 not 2018. Prior Debt Instruments The following debt instruments were repurchased and retired, repaid or redeemed, including interest and applicable premiums as part of the Refinancing Transaction on October 18, 2018: ● 11.00% 1.5 “1.5 November 15, 2019, $75.0 October 18, 2018. ● 9.00% May 15, 2020, $300.0 October 18, 2018 ( ● 9.00%/ 10.75% May 15, 2020, $177.5 October 18, 2018. ● 8.50%/ 10.00% June 15, 2021, $160.9 October 18, 2018. ● 8.500% June 15, 2019, $189.8 October 18, 2018. Exchange Transaction in 2016 On September 7, 2016, $710.2 79%, $159.8 $142.0 60.4 $75.0 1.5 470 60. 470 60, 1.5 “2016 no 2016 September 7, 2016 October 18, 2018. 2016 470 60, 2016 During the second 2017, $8.2 Gain on Debt Transactions 2017, $0.4 Gain on Debt Transactions 2017 $0.06 not

Note 3 - Fair Value Measurement

Note 3 - Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Fair Value Disclosures [Text Block]	3. Under GAAP, fair value is defined 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. The fair value of an asset should reflect its highest and best use by market participants, whether using an in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, the Company’s credit risk. Valuation techniques are generally classified into three one ● Level 1 ● Level 2 not ● Level 3 The following tables present the fair value of our derivatives and long-term debt (in thousands): December 31, 2019 2018 Assets: Derivatives instruments - open contracts, current $ 6,921 $ 74,580 Derivatives instruments - open contracts, long-term 2,653 — Liabilities: Derivatives instruments - open contracts, current 1,785 — December 31, 2019 December 31, 2018 Carrying Value Fair Value Carrying Value Fair Value Liabilities: Credit Agreement $ 105,000 $ 105,000 $ 21,000 $ 21,000 Senior Second Lien Notes 614,533 597,188 612,535 546,875 As of December 31, 2019 2018, 2 The fair value of our Senior Second Lien Notes is based on quoted prices, although the market is not 2.

Note 4 - Joint Venture Drilling

Note 4 - Joint Venture Drilling Program	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Joint Venture Drilling Program [Text Block]	4. Joint Venture Drilling Program In March 2018, two 2018 $361.4 December 31, 2019, nine eight December 31, 2019. 88.94% 11.06% 30.0% 20.0% seven nine December 31, 2019. The members of Monza are made up of third third 4.5% $14.5 Monza is an entity separate from any other entity with its own separate creditors who will be entitled, upon its liquidation, to be satisfied out of Monza’s assets prior to any value in Monza becoming available to holders of its equity. The assets of Monza are not Through December 31, 2019, $273.3 $30.2 December 31, 2019 $59.7 Consolidation and Carrying Amounts Our interest in Monza is considered to be a variable interest that we account for using proportional consolidation. Through December 31, 2019, no not not December 31, 2019, $16.1 Oil and natural gas properties and other, net , $5.3 Other assets, $0.1 $2.7 December 31, 2018, $8.8 Oil and natural gas properties and other, net , $3.3 Other assets and $0.7 2019 2018, December 31, 2019 2018 $5.3 $20.6 Advances from joint interest partners For 2019, $11.9 Total revenues and $7.4 Operating costs and expenses in connection with our proportional interest in Monza’s operations. For 2018, $4.3 Total revenues, $2.3 Operating costs and expenses and $0.2 Other expense (income), net in connection with our proportional interest in Monza’s operations.

Note 5 - Acquisitions and Dives

Note 5 - Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Business Combination Disclosure [Text Block]	5. Mobile Bay Properties In August 2019, January 1, 2019, $169.8 $150.0 not 2019 Oil and natural gas properties and other, net - at cost: $ 192,373 Other assets 4,838 Current liabilities 1,559 Asset retirement obligations 21,684 Other liabilities 4,132 Magnolia Field In December 2019, 783 784 October 1, 2019, $15.9 not 2019 Oil and natural gas properties and other, net - at cost: $ 23,791 Asset retirement obligations 7,842 Heidelberg Field On April 5, 2018, 9.375% 859, 903 904 January 1, 2018, $16.8 not $9.4 $3.6 2028 $19.6 Permian Basin On September 28, 2018, $56.6

Note 6 - Asset Retirement Oblig

Note 6 - Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Asset Retirement Obligation Disclosure [Text Block]	6. Asset retirement obligations associated with the retirement and decommissioning of tangible long-lived assets are required to be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset. The fair value of the ARO is measured using expected cash outflows associated with the ARO, discounted at our credit-adjusted risk-free rate when the liability is initially recorded. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The following table is a reconciliation of our ARO (in thousands): Year Ended December 31, 2019 2018 Asset retirement obligations, beginning of period $ 310,137 $ 300,446 Liabilities settled (11,443 ) (28,617 ) Accretion of discount 19,460 18,431 Liabilities incurred and assumed through acquisition 29,887 4,286 Revisions of estimated liabilities (1) (2) 7,553 15,591 Asset retirement obligations, end of period 355,594 310,137 Less current portion 21,991 24,994 Long-term $ 333,603 $ 285,143 ( 1 Revisions in 2019 ( 2 Revisions in 2018 2018. 2017

Note 7 - Leases

Note 7 - Leases	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Lessee, Operating Leases [Text Block]	7. ASU 2016 02 January 1, 2019 not As provided for in subsequent accounting standards updates related to ASU 2016 02, ● not 12 not ● not ● not January 1, 2019; ● use hindsight in determining the lease term and assessing impairment; and ● not During 2019, 10 ten 10 five 2085. 9.75% 10.75% Minimum future lease payments were estimated assuming expected terms of the leases and estimated inflation escalations of payments for certain leases. Undiscounted future minimum payments as of December 31, 2019 2020 - $2.9 2021 $0.3 2022 $0.3 2023 $0.5 2024 $11.0 2019, 2018 2017, $2.9 $3.4 $3.0 December 31, 2019 ROU assets $ 7,936 Lease liability: Accrued liabilities $ 2,716 Other liabilities 4,419 Total lease liability $ 7,135 During 2019, $22.2 Oil and natural gas properties, net

Note 8 - Insurance Claims

Note 8 - Insurance Claims	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Insurance Claims and Reimbursement [Text Block]	8. During 2017, $31.7 Net cash provided by operating activities Oil and natural gas properties and other, net Lease operating expense General and administrative expenses Other income (expense), net No 2019 2018, December 31, 2019, no

Note 9 - Restricted Deposits fo

Note 9 - Restricted Deposits for ARO	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Restricted Assets Disclosure [Text Block]	9. Restricted deposits as of December 31, 2019 2018 Pursuant to the Purchase and Sale Agreement with Total E&P USA Inc. (“Total E&P”), security for future plugging and abandonment of certain oil and natural gas properties is required either through surety bonds or payments to an escrow account or a combination thereof. Monthly payments are made to an escrow account and these funds are returned to us once verification is made that the security amount requirements have been met. See Note 16

Note 10 - Derivative Financial

Note 10 - Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Derivative Instruments and Hedging Activities Disclosure [Text Block]	10. Derivative Financial Instruments During 2019, 2018 2017, December 31, 2019 Crude Oil: Calls - Bought, Priced off WTI (NYMEX) Beginning Period Termination Period Notional Quantity (Bbls/day) (1) Notional Quantity (Bbls) (1) Strike Price January 2020 May 2020 10,000 1,520,000 $ 61.00 June 2020 December 2020 10,000 2,140,000 $ 67.50 Crude Oil: Swap, Priced off WTI (NYMEX) Beginning Period Termination Period Notional Quantity (Bbls/day) (1) Notional Quantity (Bbls) (1) Strike Price January 2020 May 2020 1,500 228,000 $ 60.80 January 2020 May 2020 5,000 760,000 $ 61.00 January 2020 May 2020 3,500 532,000 $ 60.85 Crude Oil: Collars - Bought, Priced off WTI (NYMEX) Beginning Period Termination Period Notional Quantity (Bbls/day) (1) Notional Quantity (Bbls) (1) Put Option Strike Price (Bought) Call Option Strike Price (Sold) June 2020 December 2020 9,000 1,926,000 $ 45.00 $ 63.50 June 2020 December 2020 1,000 214,000 $ 45.00 $ 63.60 ( 1 Bbls = Barrels Natural Gas Calls - Bought, Priced off Henry Hub (NYMEX) Beginning Period Termination Period Notional Quantity (MMBtu/day) (2) Notional Quantity (MMBtu) (2) Strike Price January 2020 December 2022 40,000 43,840,000 $ 3.00 ( 2 MMBtu = Million British Thermal Units The following amounts were recorded in the Consolidated Balance Sheets in the categories presented and include the fair value of open contracts and closed contracts, which had not December 31, 2019 2018 Prepaid and other assets – current $ 7,266 $ 60,687 Other assets – non-current 2,653 21,275 Accrued liabilities 1,785 — The amounts recorded on the Consolidated Balance Sheets are on a gross basis. If these were recorded on a net settlement basis, it would not Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands): Year Ended December 31, 2019 2018 2017 Derivative loss (gain) $ 59,887 $ (53,798 ) $ (4,199 ) Cash receipts (payments), net, on commodity derivative contract settlements, which include derivative premium payments, are included within Net cash provided by operating activities Year Ended December 31, 2019 2018 2017 Derivative cash receipts (payments), net $ 13,941 $ (28,164 ) $ 4,199

Note 11 - Share-based Awards an

Note 11 - Share-based Awards and Cash-based Awards	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Share-based Payment Arrangement [Text Block]	11. Incentive Compensation Plan The W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan, and subsequent amendments, (the “Plan”) was approved by our shareholders. The Plan covers the Company’s eligible employees and consultants and includes both cash and share-based compensation awards. The Plan grants the Compensation Committee of the Board of Directors administrative authority over all participants, and grants the CEO with authority over the administration of awards granted to participants that are not 16 Pursuant to the terms of the Plan, the Compensation Committee establishes the vesting or performance criteria applicable to the award and may may may may 10 90 Share-based Awards: Restricted Stock Units During 2019, 2018 2017, As of December 31, 2019, 10,874,043 one one 2019 2018, 2017, RSUs currently outstanding relate to the 2019 2018 December second We recognize compensation cost for share-based payments to employees over the period during which the recipient is required to provide service in exchange for the award. Compensation cost is based on the fair value of the equity instrument on the date of grant. The fair values for the RSUs granted during 2019, 2018 2017 All RSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period. During 2019, net income before net interest expense; income tax (benefit) expense; depreciation, depletion, amortization and accretion; unrealized commodity derivative gain or loss; amortization of derivative premiums; bad debt reserve; litigation; and other 2019 2019. 0% 100% 2019, During 2018, 2018 2018. 0% 100% 2018, During 2017, 2017 2017. 0% 100% 2017, A summary of activity related to RSUs is as follows: 2019 2018 2017 Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Nonvested, beginning of period 3,355,917 $ 3.90 5,765,251 $ 2.48 6,107,248 $ 2.73 Granted 994,698 4.51 988,955 6.90 2,128,879 2.76 Vested (1,475,373 ) 2.76 (2,261,665 ) 2.21 (2,108,553 ) 3.45 Forfeited (1,260,520 ) 3.37 (1,136,624 ) 2.68 (362,323 ) 2.87 Nonvested, end of period 1,614,722 $ 5.73 3,355,917 $ 3.90 5,765,251 $ 2.48 Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2019 Restricted Stock Units 2020 821,656 2021 793,066 Total 1,614,722 RSUs fair value at grant date - During 2019, 2018 2017, $4.5 $6.8 $5.9 RSUs fair value at vested date - The fair value of the RSUs that vested during 2019, 2018 2017 $7.0 $11.0 $5.5 Share-Based Awards: Restricted Stock Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2019, 2018 2017 one third three As of December 31, 2019, 82,620 A summary of activity related to Restricted Shares is as follows: 2019 2018 2017 Restricted Shares Weighted Average Grant Date Fair Value Per Share Restricted Shares Weighted Average Grant Date Fair Value Per Share Restricted Shares Weighted Average Grant Date Fair Value Per Share Nonvested, beginning of period 181,832 $ 3.08 246,528 $ 2.27 161,296 $ 3.47 Granted 46,360 6.04 41,544 6.74 147,372 1.90 Vested (105,012 ) 2.67 (106,240 ) 2.64 (62,140 ) 4.51 Nonvested, end of period 123,180 $ 4.55 181,832 $ 3.08 246,528 $ 2.27 Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2019 Restricted Shares 2020 78,428 2021 29,304 2022 15,448 Total 123,180 Restricted stock fair value at grant date - The grant date fair value of restricted stock granted during 2019, 2018 2017 $0.3 Restricted stock fair value at vested date - The fair value of the restricted stock that vested during 2019, 2018 2017 $0.5 $0.7 $0.1 Share-Based Compensation A summary of compensation expense under share-based payment arrangements is as follows (in thousands): Year Ended December 31, 2019 2018 2017 Share-based compensation expense from: Restricted stock units $ 3,410 $ 3,260 $ 7,785 Restricted stock 280 280 280 Total $ 3,690 $ 3,540 $ 8,065 As of December 31, 2019, $5.1 $0.4 November 2021 April 2022 Cash-based Awards In addition to share-based compensation, short-term, cash-based awards were granted under the Plan to substantially all eligible employees in 2019, 2018 2017. one three 2018, ● For the 2019 $200 four 2019 2019 March 2020 2019 ● In 2018, three ● For the 2018 2018 September 2018 November 2020 2018 December 14, 2020 ● For the 2018 2018 2018 January 2018 February 2019 2018 March 2019. ● For the 2017 2017 2017 January 2017 February 2018 2017 March 2018. Share-Based Awards and Cash-Based Awards Compensation Expense A summary of compensation expense related to share-based awards and cash-based awards is as follows (in thousands): Year Ended December 31, 2019 2018 2017 Share-based compensation included in: General and administrative $ 3,690 $ 3,540 $ 8,065 Cash-based incentive compensation included in: Lease operating expense 2,206 3,596 2,101 General and administrative 8,897 9,586 5,032 Total charged to operating income $ 14,793 $ 16,722 $ 15,198

Note 12 - Employee Benefit Plan

Note 12 - Employee Benefit Plan	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Pension and Other Postretirement Benefits Disclosure [Text Block]	12. We maintain a defined contribution benefit plan (the “401 401 401 March 5, 2016 March 1, 2017, 100% 6% 401 100% five 20% 401 $2.0 $2.0 $1.4 2019, 2018 2017,

Note 13 - Income Taxes

Note 13 - Income Taxes	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Income Tax Disclosure [Text Block]	13. Income Tax (Benefit) Expense Components of income tax (benefit) expense were as follows (in thousands): Year Ended December 31, 2019 2018 2017 Current $ (11,092 ) $ 35 $ (12,786 ) Deferred (64,102 ) 500 217 Total income tax (benefit) expense $ (75,194 ) $ 535 $ (12,569 ) Reconciliation The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax (benefit) expense is as follows (in thousands): Year Ended December 31, 2019 2018 2017 Income tax (benefit) expense at the federal statutory rate $ (233 ) $ 52,366 $ 23,490 Compensation adjustments 971 457 664 State income taxes (175 ) 560 63 Uncertain tax position (11,523 ) — — Impact of U.S. tax reform — 487 105,933 Gain on exchange of debt — — (24,981 ) Valuation allowance (64,704 ) (53,980 ) (118,643 ) Other 470 645 905 Total income tax (benefit) expense $ (75,194 ) $ 535 $ (12,569 ) Our effective tax rate for the years 2019, 2018 2017 21.0% 2019 2018 35.0% 2017 not Deferred Tax Assets and Liabilities Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities were as follows (in thousands): December 31, 2019 2018 Deferred tax liabilities: Property and equipment $ 21,647 $ — Derivatives — 11,139 Investment in non-consolidated entity 14,716 6,875 Other 2,283 812 Total deferred tax liabilities 38,646 18,826 Deferred tax assets: Property and equipment — 3,934 Derivatives 1,409 — Asset retirement obligations 76,924 65,811 Federal net operating losses 15,265 10,039 State net operating losses 7,393 7,133 Interest expense limitation carryover 48,458 41,814 Share-based compensation 965 583 Valuation allowance (54,436 ) (117,764 ) Other 6,584 7,091 Total deferred tax assets 102,562 18,641 Net deferred tax assets (liabilities) $ 63,916 $ (185 ) Income Taxes Receivable As of December 31, 2019, $1.9 2017 December 31, 2018, $54.1 2012, 2013 2014 2017 172 10 2019, $51.8 $0.1 $4.5 2019. 2018, $11.1 $0.1 2017, $11.9 $0.2 2019, 2018 2017 172 Net Operating Loss and Interest Expense Limitation Carryover The table below presents the details of our net operating loss and interest expense limitation carryover as of December 31, 2019 Amount Expiration Year Federal net operating loss $ 72,692 2037 State net operating loss 122,155 2026-2038 Interest expense limitation carryover 223,928 N/A Valuation Allowance During 2019 2018, $63.3 $53.8 not not Throughout 2019, twelve December 31, 2017, 2018 2019, not 2019, $64.1 2019. 163 December 31, 2019, $54.4 On December 22, 2017, No. 118 2018 2017. $105.9 December 31, 2017. 2017 not Uncertain Tax Positions The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits. The settlement of our net operating loss carryback claims with the IRS effectively allowed us to also settle our uncertain tax position which resulted in a change in our unrecognized tax benefits and materially impacted our income tax benefit. Reconciliation of the balances of our uncertain tax positions are as follows (in thousands): December 31, 2019 2018 Balance, beginning of period $ 9,482 $ 9,482 Decrease during the period (9,482 ) — Balance, end of period $ — $ 9,482 We recognize interest and penalties related to uncertain tax positions in income tax expense. For 2018 2017, Years open to examination The tax years from 2016 2019

Note 14 - Earnings Per Share

Note 14 - Earnings Per Share	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Earnings Per Share [Text Block]	14. The Company’s unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are deemed participating securities and are included in the computation of earnings per share under the two The following table presents the calculation of basic and diluted earnings per common share (in thousands, except per share amounts): Year Ended December 31, 2019 2018 2017 Net income $ 74,086 $ 248,827 $ 79,682 Less portion allocated to nonvested shares 1,371 9,727 3,244 Net income allocated to common shares $ 72,715 $ 239,100 $ 76,438 Weighted average common shares outstanding 140,583 139,002 137,617 Basic and diluted earnings per common share $ 0.52 $ 1.72 $ 0.56

Note 15 - Supplemental Cash Flo

Note 15 - Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Cash Flow, Supplemental Disclosures [Text Block]	15. The following table reflects our supplemental cash flow information (in thousands): Year Ended December 31, 2019 2018 2017 Supplemental cash items: Cash paid for interest (1) $ 66,720 $ 61,501 $ 65,873 Cash paid for income taxes 51 138 185 Cash refunds received for income taxes 51,833 11,126 11,906 Cash paid for share-based compensation (2) — 1,130 874 Cash received for interest income 7,720 2,385 315 Non-cash investing activities: Accruals of property and equipment 29,662 18,575 33,003 ARO - additions, dispositions and revisions, net 37,440 19,877 21,245 ( 1 During 2018 2017, 2016, 470 60 financing activities No ( 2 During 2019, 2018 2017,

Note 16 - Commitments

Note 16 - Commitments	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Commitments Disclosure [Text Block]	16. See Note 7 Pursuant to the Purchase and Sale Agreement with Total E&P, we may December 31, 2019, $90.7 no $103.0 2023 $3.0 Pursuant to the Purchase and Sale Agreement with Shell Offshore Inc. (“Shell”) related to ARO for certain properties, we have surety bonds that are subject to re-appraisal by either party. As of December 31, 2019, $64.0 $94.0 Pursuant to the Purchase and Sale Agreement with Exxon related to ARO for certain properties, we were required to obtain $27.3 June 1 $30.0 2020; $33.0 2021; $36.3 2022; $40.0 2023; $44.0 2024, $4.0 $9.0 $114.0 2034. may two Pursuant to the Purchase and Sale Agreement with Conoco related to ARO for certain properties, we were required to obtain $49.0 During 2019, 2018 2017, $4.7 $5.9 $5.7 2019, 2018 2017, 2065. 20 20–$4.6 2021–$4.6 2022–$4.6 2023 $4.7 2024 $4.7 thereafter–$52.0 may As of December 31, 2019, $6.9 In conjunction with the purchase of an interest in the Heidelberg field, we assumed contracts with certain pipeline companies that contain minimum quantities obligations that extend to 2028. 2019 2018, $4.5 $2.3 December 31, 2019, 2020–$3.7 2021–$2.2 2022–$1.6 2023–$1.2 2024 $0.8 thereafter–$1.3 We have no December 31, 2019.

Note 17 - Related Parties

Note 17 - Related Parties	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Related Party Transactions Disclosure [Text Block]	17. During 2019, 2018 2017, ly $1.2 $1.3 $1.2 2019, 2018 2017, third led $22.8 $21.0 $22.8 2019, 2018 2017, $0.2 2019, 2018 2017. 2018, $8.0 4

Note 18 - Contingencies

Note 18 - Contingencies	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Commitments and Contingencies Disclosure [Text Block]	18. Apache Lawsuit On December 15, 2014, Apache Deepwater, L.L.C. vs. W&T Offshore, Inc three May 31, 2017 $49.5 $49.5 June 2017 2019 Due to funds being distributed during 2019, $49.5 Other assets ( $49.5 Other liabilities December 31, 2018 2019 $1.9 Interest expense, net 2019. Appeal with ONRR In 2009, 2010, 2010, $4.7 2010 May 2014. June 17, 2014, January 27, 2017, $4.7 March 27, 2017. July 25, 2017 $7.2 $6.9 December 4, 2018, February 4, 2019, first July 9, 2019, July 31, 2019, December 18, 2019, in camera Royalties-In-Kind (“RIK”) Under a program of the Minerals Management Service (“MMS”) (a Department of Interior ("DOI") agency and predecessor to the ONRR), royalties must be paid “in-kind” rather than in value from federal leases in the program. The MMS added to the RIK program our lease at the East Cameron 373 November 2001, October 2008, May 29, 2018. July 24, 2018. December 23, 2019, no $0.25 December 31, 2019 Notices of Proposed Civil Penalty Assessment During 2019 2018, not nine not 10 July 2012 January 2018. $7.7 December 31, 2019 December 31, 2018, $3.5 Royalties – “Unbundling” Initiative The ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases. The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 second 2015, not 10 not 2019, 2018 2017, $0.4 $0.6 $1.6 not Supplemental Bonding Requirements by the BOEM The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to satisfy lease obligations, including decommissioning activities on the OCS. As of the filing date of this Form 10 no may Surety Bond Issuers’ Collateral Requirements The issuers of surety bonds in some cases have requested and received additional collateral related to surety bonds for plugging and abandonment activities. We may not 2019 2018. Other Claims We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business. In addition, claims or contingencies may no may not not

Note 19 - Selected Quarterly Fi

Note 19 - Selected Quarterly Financial Data - Unaudited	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Quarterly Financial Information [Text Block]	19. Unaudited quarterly financial data are as follows (in thousands, except per share amounts): 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended December 31, 2019 Revenues $ 116,080 $ 134,701 $ 132,221 $ 151,894 Operating (loss) income (30,976 ) 37,379 35,399 16,847 Net (loss) income (1) (47,761 ) 36,389 75,899 9,559 Basic and diluted (loss) earnings per common share (0.34 ) 0.25 0.53 0.07 Year Ended December 31, 2018 Revenues $ 134,213 $ 149,612 $ 153,459 $ 143,422 Operating income 38,739 48,467 57,147 102,674 Net income (1) 27,640 36,083 46,260 138,844 Basic and diluted earnings per common share 0.19 0.25 0.32 0.96 ( 1 During 2019, $48.9 $1.8 $5.9 $18.7 third fourth 2019, $0.2 $11.7 $55.5 $8.2 third fourth fourth 2018, $47.1 $59.7 2, 9 13 ( 2 The sum of the individual quarterly earnings (loss) per common share may not

Note 20 - Supplemental Oil and

Note 20 - Supplemental Oil and Gas Disclosures - Unaudited	12 Months Ended
	Dec. 31, 2019
Notes to Financial Statements
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	20. Geographic Area of Operation All of our proved reserves are located within the United States in the Gulf of Mexico. Therefore, the following disclosures about our costs incurred, results of operations and proved reserves are on a total-company basis. Capitalized Costs Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions): December 31, 2019 2018 2017 Net capitalized cost: Proved oil and natural gas properties and equipment $ 8,532.2 $ 8,169.9 $ 8,102.0 Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities (7,793.3 ) (7,665.1 ) (7,525.0 ) Net capitalized costs related to producing activities $ 738.9 $ 504.8 $ 577.0 Costs Incurred In Oil and Gas Property Acquisition, Exploration and Development Activities The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions): Year Ended December 31, 2019 2018 2017 Costs incurred: (1) Proved properties acquisitions $ 223.8 $ 24.1 $ 1.1 Exploration (2) (3) 30.6 49.9 62.0 Development 114.5 56.2 92.5 Total costs incurred in oil and gas property acquisition, exploration and development activities $ 368.9 $ 130.2 $ 155.6 ( 1 Includes net additions from capitalized ARO of $37.5 $20.3 $21.3 2019, 2018 2017, ( 2 Includes seismic costs of $7.8 $1.5 $0.5 2019, 2018 2017, ( 3 Includes geological and geophysical costs charged to expense of $5.7 $5.4 $4.2 2019, 2018 2017, Depreciation, depletion, amortization and accretion expense The following table presents our depreciation, depletion, amortization and accretion expense per barrel equivalent (“Boe”) of products sold: Year Ended December 31, 2019 2018 2017 Depreciation, depletion, amortization and accretion per Boe $ 10.01 $ 11.24 $ 10.68 Oil and Natural Gas Reserve Information There are numerous uncertainties in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve information represents estimates only and are inherently imprecise and may not 10.7% December 31, 2019 may not December 31, 2019. not The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, NGLs and natural gas reserves. All of the reserves are located in the United States with all located in state and federal waters in the Gulf of Mexico. The reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. In addition to other criteria, estimated reserves are assessed for economic viability based on the unweighted average of first January December not may Standardized Measure of Discounted Future Net Cash Flows”. Total Energy Equivalent Reserves (1) Oil (MMBbls) NGLs (MMBbls) Natural Gas (Bcf) Oil Equivalent (MMBoe) Natural Gas Equivalent (Bcfe) Proved reserves as of Dec. 31, 2016 32.9 8.2 197.8 74.0 444.0 Revisions of previous estimates (2) 4.5 0.7 25.8 9.6 57.4 Extensions and discoveries (3) 4.1 0.3 5.4 5.2 31.3 Production (7.1 ) (1.4 ) (36.8 ) (14.6 ) (87.4 ) Proved reserves as of Dec. 31, 2017 34.4 7.8 192.2 74.2 445.3 Revisions of previous estimates (4) 11.6 2.8 40.4 21.1 126.7 Extensions and discoveries (5) 0.5 0.3 7.7 2.1 12.6 Purchase of minerals in place (6) 1.5 0.4 9.4 3.4 20.7 Sales of minerals in place (7) (2.2 ) (0.2 ) (7.2 ) (3.5 ) (21.2 ) Production (6.7 ) (1.3 ) (32.0 ) (13.3 ) (80.0 ) Proved reserves as of Dec. 31, 2018 39.1 9.8 210.5 84.0 504.1 Revisions of previous estimates (8) 1.4 (1.5 ) (16.9 ) (3.0 ) (18.2 ) Extensions and discoveries (9) 0.9 0.1 1.2 1.1 6.7 Purchase of minerals in place (10) 3.1 17.4 417.6 90.1 540.9 Production (6.7 ) (1.3 ) (41.3 ) (14.8 ) (89.0 ) Proved reserves as of Dec. 31, 2019 37.8 24.5 571.1 157.4 944.5 Year-end proved developed reserves: 2019 28.0 21.7 504.9 133.8 802.9 2018 31.5 7.8 166.8 67.0 402.2 2017 26.1 7.2 173.5 62.2 373.3 Year-end proved undeveloped reserves: 2019 (11) 9.8 2.8 66.2 23.6 141.6 2018 7.6 2.0 43.7 17.0 101.9 2017 8.3 0.6 18.7 12.0 72.0 Volume measurements: MMBbls – million barrels for crude oil, condensate or NGLs Bcf – billion cubic feet MMBoe – million barrels of oil equivalent Bcfe – billion cubic feet of gas equivalent ( 1 The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six one may not not may ( 2 Primarily related to upward revisions at our Mississippi Canyon 698 910 783 3.4 ( 3 Primarily related to extensions and discoveries at our Ship Shoal 349 3.5 286 1.5 ( 4 Primarily related to upward revisions at our Mahogany field and our Ship Shoal 028 2.3 ( 5 Primarily related to extensions and discoveries of 1.3 823 0.7 910 ( 6 Primarily related to our Ship Shoal 028 859 ( 7 Primarily related to conveyance of interest in properties related to the JV Drilling Program. ( 8 Increases primarily related to upward revisions to our Ship Shoal 028 108 10.0 December 31, 2019. ( 9 Primarily related to extensions and discoveries of 0.9 800 ( 10 Primarily related to the Mobile Bay Properties and Magnolia acquisitions ( 11 We believe that we will be able to develop all but 2.5 11% 23.6 December 31, 2019, five 243 one 2021 2022. Standardized Measure of Discounted Future Net Cash Flows The following presents the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves together with changes therein. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first December 31, 2019 2018 2017 2016 Oil - per barrel $ 58.11 $ 65.21 $ 46.58 $ 36.28 NGLs per barrel 18.72 29.73 22.65 16.82 Natural gas per Mcf 2.63 3.13 2.86 2.47 Future production, development costs and ARO are based on costs in effect at the end of each of the respective years with no 10% The standardized measure of discounted future net cash flows does not 2019 Year Ended December 31, 2019 2018 2017 Standardized Measure of Discounted Future Net Cash Flows Future cash inflows $ 4,153.8 $ 3,500.9 $ 2,328.8 Future costs: Production (1,901.1 ) (958.5 ) (813.8 ) Development (297.3 ) (272.4 ) (157.4 ) Dismantlement and abandonment (497.4 ) (355.9 ) (361.9 ) Income taxes (170.5 ) (293.9 ) (74.8 ) Future net cash inflows before 10% discount 1,287.5 1,620.2 920.9 10% annual discount factor (300.6 ) (553.2 ) (180.3 ) Total $ 986.9 $ 1,067.0 $ 740.6 The change in the standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions): Year Ended December 31, 2019 2018 2017 Changes in Standardized Measure Standardized measure, beginning of year $ 1,067.0 $ 740.6 $ 478.3 Increases (decreases): Sales and transfers of oil and gas produced, net of production costs (315.8 ) (398.1 ) (315.3 ) Net changes in price, net of future production costs (376.4 ) 571.5 288.0 Extensions and discoveries, net of future production and development costs 27.0 53.6 119.3 Changes in estimated future development costs (6.0 ) (114.7 ) (38.9 ) Previously estimated development costs incurred 19.3 48.4 102.8 Revisions of quantity estimates 116.4 307.6 106.4 Accretion of discount 107.4 50.5 30.2 Net change in income taxes 62.9 (133.4 ) (54.7 ) Purchases of reserves in-place 298.3 27.8 — Sales of reserves in-place — (54.1 ) — Changes in production rates due to timing and other (13.2 ) (32.7 ) 24.5 Net (decrease) increase (80.1 ) 326.4 262.3 Standardized measure, end of year $ 986.9 $ 1,067.0 $ 740.6

Significant Accounting Policies

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of Accounting, Policy [Policy Text Block]	Basis of Presentation Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries. Our interests in oil and gas joint ventures are proportionately consolidated. All significant intercompany transactions and amounts have been eliminated for all years presented. Our consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”).
Use of Estimates, Policy [Policy Text Block]	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, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.
Realized Prices [Policy Text Block]	Realized Prices The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital, proved reserves and future rate of growth. The average realized prices of these commodities decreased in 2 019 2018.
New Accounting Pronouncements, Adopted [Policy Text Block]	Accounting Standard Updates Effective January 1, 2019 In February 2016, 2016 02, Topic 842 2016 02” 2016 02 not 2016 02 first 2019 January 1, 2019. no 7
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash Equivalents We consider all highly liquid investments purchased with original or remaining maturities of three
Revenue from Contract with Customer [Policy Text Block]	Revenue Recognition We recognize revenue from the sale of crude oil, NGLs, and natural gas when our performance obligations are satisfied. Our contracts with customers are primarily short-term (less than 12 We record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not not December 31, 2019 2018, $3.6 $4.1
Concentration Risk, Credit Risk, Policy [Policy Text Block]	Concentration of Credit Risk Our customers are primarily large integrated oil and natural gas companies and large commodity trading companies. The majority of our production is sold utilizing month-to-month contracts that are based on bid prices. We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third The following table identifies customers from whom we derived 10% Year Ended December 31, 2019 2018 2017 Customer Shell Trading (US) Co./ Shell Energy N.A. 11 % 30 % 46 % BP Products North America 40 % 20 % ** Vitol Inc. 12 % 14 % 15 % ** Less than 10% We believe that the loss of any of the customers above would not
Accounts Receivable [Policy Text Block]	Accounts Receivables and Allowance for Bad Debts Our accounts receivables are recorded at their historical cost, less an allowance for doubtful accounts. The carrying value approximates fair value because of the short-term nature of such accounts. In addition to receivables from sales of our production to our customers, we also have receivables from joint interest owners on properties we operate. In certain arrangements, we have the ability to withhold future revenue disbursements to recover amounts due us from the joint interest partners. We use the specific identification method of determining if an allowance for doubtful accounts is needed and the amounts recorded relate to certain joint interest owners. The following table describes the balance and changes to the allowance for doubtful accounts (in thousands): 2019 2018 2017 Allowance for doubtful accounts, beginning of period $ 9,692 $ 9,114 $ 7,602 Additional provisions for the year 206 1,233 1,512 Uncollectible accounts written off — (655 ) — Allowance for doubtful accounts, end of period $ 9,898 $ 9,692 $ 9,114
Prepaid Expenses and Other Assets [Policy Text Block]	Prepaid expenses and other assets Amounts recorded in Prepaid expenses and other assets one December 31, 2019 2018 Derivatives – current (1) $ 7,266 $ 60,687 Unamortized bonds/insurance premiums 4,357 5,197 Prepaid deposits related to royalties 7,980 8,872 Prepayment to vendors 10,202 864 Other 886 786 Prepaid expenses and other assets $ 30,691 $ 76,406 ( 1 Includes both open and closed contracts.
Property, Plant and Equipment, Policy [Policy Text Block]	Properties and Equipment We use the full-cost method of accounting for oil and natural gas properties and equipment, which are recorded at cost. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties. Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs. Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred. Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs related to proved reserves are not Sales of proved and unproved oil and natural gas properties, whether or not no Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five seven Oil and Natural Gas Properties and Other, Net – at cost Oil and natural gas properties and equipment are recorded at cost using the full cost method. There were no December 31, 2019 2018 Oil and natural gas properties and equipment $ 8,532,196 $ 8,169,871 Furniture, fixtures and other 20,317 20,228 Total property and equipment 8,552,513 8,190,099 Less accumulated depreciation, depletion and amortization 7,803,715 7,674,678 Oil and natural gas properties and other, net $ 748,798 $ 515,421
Oil and Gas Properties Policy [Policy Text Block]	Ceiling Test Write-Down Under the full-cost method of accounting, we are required to perform a “ceiling test” calculation quarterly, which determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized ARO) net of related deferred income taxes exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed. Any such write downs are not 10%; not first twelve We did not 2019, 2018 2017. 2020
Asset Retirement Obligation [Policy Text Block]	Asset Retirement Obligations We are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet. We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating such costs requires us to make judgments on both the costs and the timing of ARO. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. See Note 6
Industry Specific Policies, Oil and Gas [Policy Text Block]	Oil and Natural Gas Reserve Information We use the unweighted average of first 12 12 may five 20
Derivatives, Reporting of Derivative Activity [Policy Text Block]	Derivative Financial Instruments We have exposure related to commodity prices and have used various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas. We do not 2019, 2018 2017, December 31, 2019, may 2019, 2018 2017, not Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value. We have elected not may may not
Fair Value of Financial Instruments, Policy [Policy Text Block]	Fair Value of Financial Instruments We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance. We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments. We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments.
Income Tax, Policy [Policy Text Block]	Income Taxes We use the liability method of accounting for income taxes in accordance with the Income Taxes not not not 13
Other Noncurrent Assets [Policy Text Block]	Other Assets (long-term) The major categories recorded in Other assets December 31, 2019 2018 Appeal bond deposits $ 6,925 $ 6,925 Escrow deposit – Apache lawsuit (Note 18) — 49,500 Unamortized debt issuance costs 3,798 4,773 Investment in White Cap, LLC 2,590 2,586 Derivatives 2,653 21,275 Unamortized brokerage fee for Monza 3,423 2,277 Proportional consolidation of Monza's other assets (Note 4) 5,308 3,275 ROU assets (Note 7) 7,936 — Other 814 936 Total other assets $ 33,447 $ 91,547
Accrued Liabilities Policy [Policy Text Block]	Accrued Liabilities The major categories recorded in Accrued liabilities December 31, 2019 2018 Accrued interest $ 10,180 $ 12,385 Accrued salaries/payroll taxes/benefits 2,377 2,320 Incentive compensation plans 9,794 10,817 Litigation accruals 3,673 3,673 Lease liability (Note 7) 2,716 — Derivatives 1,785 — Other 371 416 Total accrued liabilities $ 30,896 $ 29,611
Debt, Policy [Policy Text Block]	Debt Issued During 2016 We accounted for a debt exchange transaction in 2016, 2, 470 60, Troubled Debt Restructuring 470 60” 470 60, 2016 2 no 2016 January 1, 2017 October 18, 2018. 2016 470 60. 2 Debt Issuance Costs Debt issuance costs associated with the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) are amortized using the straight-line method over the scheduled maturity of the debt. Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method. Unamortized debt issuance costs associated with our Credit Agreement is reported within Other Assets Long-term debt – carrying value 2 Discounts Provided on Debt Issuance Discounts were recorded in Long-term debt – carrying value Gain on Debt Transactions During 2018, $47.1 2016, 2017, 2
Other Noncurrent Liabilities [Policy Text Block]	Other Liabilities (long-term) The major categories recorded in Other liabilities December 31, 2019 2018 Dispute related to royalty deductions $ 4,687 $ 4,687 Dispute related to royalty-in-kind 250 2,235 Lease liability (Note 7) 4,419 — Apache lawsuit (Note 18) — 49,500 Uncertain tax positions including interest/penalties (Note 13) — 11,523 Other 632 745 Total other liabilities (long-term) $ 9,988 $ 68,690
Share-based Payment Arrangement [Policy Text Block]	Share-Based Compensation Compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award. The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant. We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award. Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 11
Other Income (Expense), Net [Policy Text Block]	Other Expense (Income), Net For 2019, 4 2018, 2017, third one
Earnings Per Share, Policy [Policy Text Block]	Earnings Per Share Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per share under the two 14
New Accounting Pronouncements, Policy [Policy Text Block]	Recent Accounting Developments In June 2016, No. 2016 13, Financial Instruments – Credit Losses Topic 326 2016 13” 2016 13 December 15, 2019 December 15, 2018. not In August 2017, No. 2017 12, Derivatives and Hedging (Topic 815 2017 12” 2017 12 2017 12 December 15, 2019 December 15, 2020. not not

Note 1 - Significant Accounti_2

Note 1 - Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Tables
Schedules of Concentration of Risk, by Risk Factor [Table Text Block]	Year Ended December 31, 2019 2018 2017 Customer Shell Trading (US) Co./ Shell Energy N.A. 11 % 30 % 46 % BP Products North America 40 % 20 % ** Vitol Inc. 12 % 14 % 15 %
Accounts Receivable, Allowance for Credit Loss [Table Text Block]	2019 2018 2017 Allowance for doubtful accounts, beginning of period $ 9,692 $ 9,114 $ 7,602 Additional provisions for the year 206 1,233 1,512 Uncollectible accounts written off — (655 ) — Allowance for doubtful accounts, end of period $ 9,898 $ 9,692 $ 9,114
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Table Text Block]	December 31, 2019 2018 Derivatives – current (1) $ 7,266 $ 60,687 Unamortized bonds/insurance premiums 4,357 5,197 Prepaid deposits related to royalties 7,980 8,872 Prepayment to vendors 10,202 864 Other 886 786 Prepaid expenses and other assets $ 30,691 $ 76,406
Property, Plant and Equipment [Table Text Block]	December 31, 2019 2018 Oil and natural gas properties and equipment $ 8,532,196 $ 8,169,871 Furniture, fixtures and other 20,317 20,228 Total property and equipment 8,552,513 8,190,099 Less accumulated depreciation, depletion and amortization 7,803,715 7,674,678 Oil and natural gas properties and other, net $ 748,798 $ 515,421
Schedule of Other Assets, Noncurrent [Table Text Block]	December 31, 2019 2018 Appeal bond deposits $ 6,925 $ 6,925 Escrow deposit – Apache lawsuit (Note 18) — 49,500 Unamortized debt issuance costs 3,798 4,773 Investment in White Cap, LLC 2,590 2,586 Derivatives 2,653 21,275 Unamortized brokerage fee for Monza 3,423 2,277 Proportional consolidation of Monza's other assets (Note 4) 5,308 3,275 ROU assets (Note 7) 7,936 — Other 814 936 Total other assets $ 33,447 $ 91,547
Schedule of Accrued Liabilities [Table Text Block]	December 31, 2019 2018 Accrued interest $ 10,180 $ 12,385 Accrued salaries/payroll taxes/benefits 2,377 2,320 Incentive compensation plans 9,794 10,817 Litigation accruals 3,673 3,673 Lease liability (Note 7) 2,716 — Derivatives 1,785 — Other 371 416 Total accrued liabilities $ 30,896 $ 29,611
Other Noncurrent Liabilities [Table Text Block]	December 31, 2019 2018 Dispute related to royalty deductions $ 4,687 $ 4,687 Dispute related to royalty-in-kind 250 2,235 Lease liability (Note 7) 4,419 — Apache lawsuit (Note 18) — 49,500 Uncertain tax positions including interest/penalties (Note 13) — 11,523 Other 632 745 Total other liabilities (long-term) $ 9,988 $ 68,690

Note 2 - Long-term Debt (Tables

Note 2 - Long-term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Tables
Schedule of Long-term Debt Instruments [Table Text Block]	December 31, 2019 2018 Credit Agreement borrowings $ 105,000 $ 21,000 Senior Second Lien Notes: Principal 625,000 625,000 Unamortized debt issuance costs (10,467 ) (12,465 ) Total Senior Second Lien Notes 614,533 612,535 Total long-term debt $ 719,533 $ 633,535

Note 3 - Fair Value Measureme_2

Note 3 - Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Tables
Schedule of Derivative Assets at Fair Value [Table Text Block]	December 31, 2019 2018 Assets: Derivatives instruments - open contracts, current $ 6,921 $ 74,580 Derivatives instruments - open contracts, long-term 2,653 — Liabilities: Derivatives instruments - open contracts, current 1,785 —
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]	December 31, 2019 December 31, 2018 Carrying Value Fair Value Carrying Value Fair Value Liabilities: Credit Agreement $ 105,000 $ 105,000 $ 21,000 $ 21,000 Senior Second Lien Notes 614,533 597,188 612,535 546,875

Note 5 - Acquisitions and Div_2

Note 5 - Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Tables
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	2019 Oil and natural gas properties and other, net - at cost: $ 192,373 Other assets 4,838 Current liabilities 1,559 Asset retirement obligations 21,684 Other liabilities 4,132 2019 Oil and natural gas properties and other, net - at cost: $ 23,791 Asset retirement obligations 7,842

Note 6 - Asset Retirement Obl_2

Note 6 - Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Tables
Schedule of Change in Asset Retirement Obligation [Table Text Block]	Year Ended December 31, 2019 2018 Asset retirement obligations, beginning of period $ 310,137 $ 300,446 Liabilities settled (11,443 ) (28,617 ) Accretion of discount 19,460 18,431 Liabilities incurred and assumed through acquisition 29,887 4,286 Revisions of estimated liabilities (1) (2) 7,553 15,591 Asset retirement obligations, end of period 355,594 310,137 Less current portion 21,991 24,994 Long-term $ 333,603 $ 285,143

Note 7 - Leases (Tables)

Note 7 - Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Tables
Operating Lease, Lessee, Assets and Liabilities [Table Text Block]	December 31, 2019 ROU assets $ 7,936 Lease liability: Accrued liabilities $ 2,716 Other liabilities 4,419 Total lease liability $ 7,135

Note 10 - Derivative Financia_2

Note 10 - Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Tables
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]	Crude Oil: Calls - Bought, Priced off WTI (NYMEX) Beginning Period Termination Period Notional Quantity (Bbls/day) (1) Notional Quantity (Bbls) (1) Strike Price January 2020 May 2020 10,000 1,520,000 $ 61.00 June 2020 December 2020 10,000 2,140,000 $ 67.50 Crude Oil: Swap, Priced off WTI (NYMEX) Beginning Period Termination Period Notional Quantity (Bbls/day) (1) Notional Quantity (Bbls) (1) Strike Price January 2020 May 2020 1,500 228,000 $ 60.80 January 2020 May 2020 5,000 760,000 $ 61.00 January 2020 May 2020 3,500 532,000 $ 60.85 Crude Oil: Collars - Bought, Priced off WTI (NYMEX) Beginning Period Termination Period Notional Quantity (Bbls/day) (1) Notional Quantity (Bbls) (1) Put Option Strike Price (Bought) Call Option Strike Price (Sold) June 2020 December 2020 9,000 1,926,000 $ 45.00 $ 63.50 June 2020 December 2020 1,000 214,000 $ 45.00 $ 63.60 Natural Gas Calls - Bought, Priced off Henry Hub (NYMEX) Beginning Period Termination Period Notional Quantity (MMBtu/day) (2) Notional Quantity (MMBtu) (2) Strike Price January 2020 December 2022 40,000 43,840,000 $ 3.00
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location [Table Text Block]	December 31, 2019 2018 Prepaid and other assets – current $ 7,266 $ 60,687 Other assets – non-current 2,653 21,275 Accrued liabilities 1,785 — Year Ended December 31, 2019 2018 2017 Derivative loss (gain) $ 59,887 $ (53,798 ) $ (4,199 )
Schedule of Cash Receipts and Payments on Commodity Derivative Contract Settlements [Table Text Block]	Year Ended December 31, 2019 2018 2017 Derivative cash receipts (payments), net $ 13,941 $ (28,164 ) $ 4,199

Note 11 - Share-based Awards _2

Note 11 - Share-based Awards and Cash-based Awards (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Tables
Schedule of Unvested Restricted Stock Units Roll Forward [Table Text Block]	2019 2018 2017 Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Nonvested, beginning of period 3,355,917 $ 3.90 5,765,251 $ 2.48 6,107,248 $ 2.73 Granted 994,698 4.51 988,955 6.90 2,128,879 2.76 Vested (1,475,373 ) 2.76 (2,261,665 ) 2.21 (2,108,553 ) 3.45 Forfeited (1,260,520 ) 3.37 (1,136,624 ) 2.68 (362,323 ) 2.87 Nonvested, end of period 1,614,722 $ 5.73 3,355,917 $ 3.90 5,765,251 $ 2.48
Schedule of Nonvested Restricted Stock Units, Vesting Schedule [Table Text Block]	Restricted Stock Units 2020 821,656 2021 793,066 Total 1,614,722
Share-based Payment Arrangement, Nonemployee Director Award Plan, Activity [Table Text Block]	2019 2018 2017 Restricted Shares Weighted Average Grant Date Fair Value Per Share Restricted Shares Weighted Average Grant Date Fair Value Per Share Restricted Shares Weighted Average Grant Date Fair Value Per Share Nonvested, beginning of period 181,832 $ 3.08 246,528 $ 2.27 161,296 $ 3.47 Granted 46,360 6.04 41,544 6.74 147,372 1.90 Vested (105,012 ) 2.67 (106,240 ) 2.64 (62,140 ) 4.51 Nonvested, end of period 123,180 $ 4.55 181,832 $ 3.08 246,528 $ 2.27
Schedule of Nonvested Restricted Stock, Vesting Schedule [Table Text Block]	Restricted Shares 2020 78,428 2021 29,304 2022 15,448 Total 123,180
Share-based Payment Arrangement, Cost by Plan [Table Text Block]	Year Ended December 31, 2019 2018 2017 Share-based compensation expense from: Restricted stock units $ 3,410 $ 3,260 $ 7,785 Restricted stock 280 280 280 Total $ 3,690 $ 3,540 $ 8,065
Schedule of Incentive Compensation Expense [Table Text Block]	Year Ended December 31, 2019 2018 2017 Share-based compensation included in: General and administrative $ 3,690 $ 3,540 $ 8,065 Cash-based incentive compensation included in: Lease operating expense 2,206 3,596 2,101 General and administrative 8,897 9,586 5,032 Total charged to operating income $ 14,793 $ 16,722 $ 15,198

Note 13 - Income Taxes (Tables)

Note 13 - Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Tables
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	Year Ended December 31, 2019 2018 2017 Current $ (11,092 ) $ 35 $ (12,786 ) Deferred (64,102 ) 500 217 Total income tax (benefit) expense $ (75,194 ) $ 535 $ (12,569 )
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Year Ended December 31, 2019 2018 2017 Income tax (benefit) expense at the federal statutory rate $ (233 ) $ 52,366 $ 23,490 Compensation adjustments 971 457 664 State income taxes (175 ) 560 63 Uncertain tax position (11,523 ) — — Impact of U.S. tax reform — 487 105,933 Gain on exchange of debt — — (24,981 ) Valuation allowance (64,704 ) (53,980 ) (118,643 ) Other 470 645 905 Total income tax (benefit) expense $ (75,194 ) $ 535 $ (12,569 )
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	December 31, 2019 2018 Deferred tax liabilities: Property and equipment $ 21,647 $ — Derivatives — 11,139 Investment in non-consolidated entity 14,716 6,875 Other 2,283 812 Total deferred tax liabilities 38,646 18,826 Deferred tax assets: Property and equipment — 3,934 Derivatives 1,409 — Asset retirement obligations 76,924 65,811 Federal net operating losses 15,265 10,039 State net operating losses 7,393 7,133 Interest expense limitation carryover 48,458 41,814 Share-based compensation 965 583 Valuation allowance (54,436 ) (117,764 ) Other 6,584 7,091 Total deferred tax assets 102,562 18,641 Net deferred tax assets (liabilities) $ 63,916 $ (185 )
Summary of Operating Loss Carryforwards [Table Text Block]	Amount Expiration Year Federal net operating loss $ 72,692 2037 State net operating loss 122,155 2026-2038 Interest expense limitation carryover 223,928 N/A
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	December 31, 2019 2018 Balance, beginning of period $ 9,482 $ 9,482 Decrease during the period (9,482 ) — Balance, end of period $ — $ 9,482

Note 14 - Earnings Per Share (T

Note 14 - Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Tables
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	Year Ended December 31, 2019 2018 2017 Net income $ 74,086 $ 248,827 $ 79,682 Less portion allocated to nonvested shares 1,371 9,727 3,244 Net income allocated to common shares $ 72,715 $ 239,100 $ 76,438 Weighted average common shares outstanding 140,583 139,002 137,617 Basic and diluted earnings per common share $ 0.52 $ 1.72 $ 0.56

Note 15 - Supplemental Cash F_2

Note 15 - Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Tables
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	Year Ended December 31, 2019 2018 2017 Supplemental cash items: Cash paid for interest (1) $ 66,720 $ 61,501 $ 65,873 Cash paid for income taxes 51 138 185 Cash refunds received for income taxes 51,833 11,126 11,906 Cash paid for share-based compensation (2) — 1,130 874 Cash received for interest income 7,720 2,385 315 Non-cash investing activities: Accruals of property and equipment 29,662 18,575 33,003 ARO - additions, dispositions and revisions, net 37,440 19,877 21,245

Note 19 - Selected Quarterly _2

Note 19 - Selected Quarterly Financial Data - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Tables
Quarterly Financial Information [Table Text Block]	1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended December 31, 2019 Revenues $ 116,080 $ 134,701 $ 132,221 $ 151,894 Operating (loss) income (30,976 ) 37,379 35,399 16,847 Net (loss) income (1) (47,761 ) 36,389 75,899 9,559 Basic and diluted (loss) earnings per common share (0.34 ) 0.25 0.53 0.07 Year Ended December 31, 2018 Revenues $ 134,213 $ 149,612 $ 153,459 $ 143,422 Operating income 38,739 48,467 57,147 102,674 Net income (1) 27,640 36,083 46,260 138,844 Basic and diluted earnings per common share 0.19 0.25 0.32 0.96

Note 20 - Supplemental Oil an_2

Note 20 - Supplemental Oil and Gas Disclosures - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Tables
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]	December 31, 2019 2018 2017 Net capitalized cost: Proved oil and natural gas properties and equipment $ 8,532.2 $ 8,169.9 $ 8,102.0 Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities (7,793.3 ) (7,665.1 ) (7,525.0 ) Net capitalized costs related to producing activities $ 738.9 $ 504.8 $ 577.0
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]	Year Ended December 31, 2019 2018 2017 Costs incurred: (1) Proved properties acquisitions $ 223.8 $ 24.1 $ 1.1 Exploration (2) (3) 30.6 49.9 62.0 Development 114.5 56.2 92.5 Total costs incurred in oil and gas property acquisition, exploration and development activities $ 368.9 $ 130.2 $ 155.6
Schedule of Amortization Expense Per Unit of Production [Table Text Block]	Year Ended December 31, 2019 2018 2017 Depreciation, depletion, amortization and accretion per Boe $ 10.01 $ 11.24 $ 10.68
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]	Total Energy Equivalent Reserves (1) Oil (MMBbls) NGLs (MMBbls) Natural Gas (Bcf) Oil Equivalent (MMBoe) Natural Gas Equivalent (Bcfe) Proved reserves as of Dec. 31, 2016 32.9 8.2 197.8 74.0 444.0 Revisions of previous estimates (2) 4.5 0.7 25.8 9.6 57.4 Extensions and discoveries (3) 4.1 0.3 5.4 5.2 31.3 Production (7.1 ) (1.4 ) (36.8 ) (14.6 ) (87.4 ) Proved reserves as of Dec. 31, 2017 34.4 7.8 192.2 74.2 445.3 Revisions of previous estimates (4) 11.6 2.8 40.4 21.1 126.7 Extensions and discoveries (5) 0.5 0.3 7.7 2.1 12.6 Purchase of minerals in place (6) 1.5 0.4 9.4 3.4 20.7 Sales of minerals in place (7) (2.2 ) (0.2 ) (7.2 ) (3.5 ) (21.2 ) Production (6.7 ) (1.3 ) (32.0 ) (13.3 ) (80.0 ) Proved reserves as of Dec. 31, 2018 39.1 9.8 210.5 84.0 504.1 Revisions of previous estimates (8) 1.4 (1.5 ) (16.9 ) (3.0 ) (18.2 ) Extensions and discoveries (9) 0.9 0.1 1.2 1.1 6.7 Purchase of minerals in place (10) 3.1 17.4 417.6 90.1 540.9 Production (6.7 ) (1.3 ) (41.3 ) (14.8 ) (89.0 ) Proved reserves as of Dec. 31, 2019 37.8 24.5 571.1 157.4 944.5 Year-end proved developed reserves: 2019 28.0 21.7 504.9 133.8 802.9 2018 31.5 7.8 166.8 67.0 402.2 2017 26.1 7.2 173.5 62.2 373.3 Year-end proved undeveloped reserves: 2019 (11) 9.8 2.8 66.2 23.6 141.6 2018 7.6 2.0 43.7 17.0 101.9 2017 8.3 0.6 18.7 12.0 72.0
Schedule Of Prices Weighted By Field Production Related To The Proved Reserves [Table Text Block]	December 31, 2019 2018 2017 2016 Oil - per barrel $ 58.11 $ 65.21 $ 46.58 $ 36.28 NGLs per barrel 18.72 29.73 22.65 16.82 Natural gas per Mcf 2.63 3.13 2.86 2.47
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]	Year Ended December 31, 2019 2018 2017 Standardized Measure of Discounted Future Net Cash Flows Future cash inflows $ 4,153.8 $ 3,500.9 $ 2,328.8 Future costs: Production (1,901.1 ) (958.5 ) (813.8 ) Development (297.3 ) (272.4 ) (157.4 ) Dismantlement and abandonment (497.4 ) (355.9 ) (361.9 ) Income taxes (170.5 ) (293.9 ) (74.8 ) Future net cash inflows before 10% discount 1,287.5 1,620.2 920.9 10% annual discount factor (300.6 ) (553.2 ) (180.3 ) Total $ 986.9 $ 1,067.0 $ 740.6
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]	Year Ended December 31, 2019 2018 2017 Changes in Standardized Measure Standardized measure, beginning of year $ 1,067.0 $ 740.6 $ 478.3 Increases (decreases): Sales and transfers of oil and gas produced, net of production costs (315.8 ) (398.1 ) (315.3 ) Net changes in price, net of future production costs (376.4 ) 571.5 288.0 Extensions and discoveries, net of future production and development costs 27.0 53.6 119.3 Changes in estimated future development costs (6.0 ) (114.7 ) (38.9 ) Previously estimated development costs incurred 19.3 48.4 102.8 Revisions of quantity estimates 116.4 307.6 106.4 Accretion of discount 107.4 50.5 30.2 Net change in income taxes 62.9 (133.4 ) (54.7 ) Purchases of reserves in-place 298.3 27.8 — Sales of reserves in-place — (54.1 ) — Changes in production rates due to timing and other (13.2 ) (32.7 ) 24.5 Net (decrease) increase (80.1 ) 326.4 262.3 Standardized measure, end of year $ 986.9 $ 1,067.0 $ 740.6

Note 1 - Significant Accounti_3

Note 1 - Significant Accounting Policies (Details Textual) xbrli-pure in Thousands, $ in Thousands	Oct. 18, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Gas Balancing Asset (Liability)		$ (4,100)	$ (3,600)	$ (4,100)
Impairment of Oil and Gas Properties			$ 0	0	$ 0
Proved Undeveloped Reserves Classification, Period to be Drilled			5 years
Gain (Loss) on Extinguishment of Debt, Total		$ 47,100		47,109	$ 7,811
Refinancing Transaction [Member]
Gain (Loss) on Extinguishment of Debt, Total	$ 47,100			$ 47,100
11.00% 1.5 Lien Term Loan Due November 2019 [Member]
Interest Expense, Debt, Total						$ 0
Interest Rate Contract [Member]
Derivative, Number of Instruments Held, Total		0	0	0	0
Furniture, Fixtures and Non-oil and Natural Gas Property and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment, Useful Life			5 years
Furniture, Fixtures and Non-oil and Natural Gas Property and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment, Useful Life			7 years

Note 1 - Significant Accounti_4

Note 1 - Significant Accounting Policies - Percentage of Revenue by Major Customers (Details) - Revenue from Contract with Customer Benchmark [Member] - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Shell Trading (US) Co. [Member]
Concentration risk percentage	11.00%	30.00%	46.00%
BP Products North America [Member]
Concentration risk percentage	40.00%	20.00%		[1]
Vitol Inc. [Member]
Concentration risk percentage	12.00%	14.00%	15.00%
[1]	Less than 10%

Note 1 - Significant Accounti_5

Note 1 - Significant Accounting Policies - Changes to the Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Allowance for doubtful accounts	$ 9,692	$ 9,114	$ 7,602
Additional provisions for the year	206	1,233	1,512
Uncollectible accounts written off		(655)
Allowance for doubtful accounts	$ 9,898	$ 9,692	$ 9,114

Note 1 - Significant Accounti_6

Note 1 - Significant Accounting Policies - Schedule of Amounts Recorded in Prepaid Expenses and Other Assets (Details) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018
Derivatives – current (1)	[1]	$ 7,266	$ 60,687
Unamortized bonds/insurance premiums		4,357	5,197
Prepaid deposits related to royalties		7,980	8,872
Prepayment to vendors		10,202	864
Other		886	786
Prepaid expenses and other assets		$ 30,691	$ 76,406
[1]	Includes both open and closed contracts.

Note 1 - Significant Accounti_7

Note 1 - Significant Accounting Policies - Schedule of Oil and Natural Gas Properties and Other, Net at Cost (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and natural gas properties and equipment	$ 8,532,196	$ 8,169,871
Furniture, fixtures and other	20,317	20,228
Total property and equipment	8,552,513	8,190,099
Less accumulated depreciation, depletion and amortization	7,803,715	7,674,678
Oil and natural gas properties and other, net	$ 748,798	$ 515,421

Note 1 - Significant Accounti_8

Note 1 - Significant Accounting Policies - Schedule of Other Assets (Long-term) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Appeal bond deposits	$ 6,925	$ 6,925
Escrow deposit – Apache lawsuit (Note 18)		49,500
Unamortized debt issuance costs	3,798	4,773
Investment in White Cap, LLC	2,590	2,586
Derivatives	2,653	21,275
Unamortized brokerage fee for Monza	3,423	2,277
Proportional consolidation of Monza's other assets (Note 4)	5,308	3,275
ROU assets (Note 7)	7,936
Other assets, long-term	814	936
Total other assets	$ 33,447	$ 91,547

Note 1 - Significant Accounti_9

Note 1 - Significant Accounting Policies - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Total accrued liabilities	$ 30,896	$ 29,611
Accrued Liabilities [Member]
Accrued interest	10,180	12,385
Accrued salaries/payroll taxes/benefits	2,377	2,320
Incentive compensation plans	9,794	10,817
Litigation accruals	3,673	3,673
Accrued liabilities	2,716
Derivatives	1,785
Other	$ 371	$ 416

Note 1 - Significant Account_10

Note 1 - Significant Accounting Policies - Schedule of Other Liabilities (Long-term) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Total other liabilities (long-term)	$ 9,988	$ 68,690
Other Noncurrent Liabilities [Member]
Dispute related to royalty deductions	4,687	4,687
Dispute related to royalty-in-kind	250	2,235
Lease liability (Note 7)	4,419
Apache lawsuit (Note 18)		49,500
Uncertain tax positions including interest/penalties (Note 13)		11,523
Other liabilities, long-term	$ 632	$ 745

Note 2 - Long-term Debt (Detail

Note 2 - Long-term Debt (Details Textual) $ / shares in Units, $ in Thousands, shares in Millions	Oct. 18, 2018USD ($)$ / shares	Sep. 07, 2016USD ($)shares	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)$ / shares	Dec. 31, 2016USD ($)	Oct. 18, 2018USD ($)
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months			$ 0			$ 0
Long-term Debt, Maturities, Repayments of Principal in Year Two			0			0
Long-term Debt, Maturities, Repayments of Principal in Year Three			105,000			105,000
Long-term Debt, Maturities, Repayments of Principal in Year Four			625,000			625,000
Proceeds from Issuance of Senior Long-term Debt							$ 625,000
Gain (Loss) on Extinguishment of Debt, Total				$ 47,100			47,109	7,811
Refinancing Transaction [Member]
Gain (Loss) on Extinguishment of Debt, Total	$ 47,100						47,100
Basic Earnings Per Share Adjustment, Pro Forma | $ / shares	$ 0.33
Debt Exchange Transaction [Member]
Debt Conversion, Converted Instrument, Shares Issued | shares		60.4
Interest Expense, Debt, Total										$ 0
Senior Second Lien Notes Due November 2023 [Member]
Debt Instrument, Face Amount	$ 625,000		$ 625,000	625,000		625,000	625,000			$ 625,000
Debt Instrument, Interest Rate, Stated Percentage	9.75%									9.75%
Debt Instrument, Interest Rate, Effective Percentage	10.30%									10.30%
Debt Instrument, Covenant, Repurchase Percent	101.00%
Senior Second Lien Notes Due November 2023 [Member] | The Krohn Entity [Member]
Proceeds from Issuance of Senior Long-term Debt	$ 8,000
Senior Second Lien Notes Due November 2023 [Member] | Debt Instrument, Redemption, Period One [Member]
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	100.00%
Senior Second Lien Notes Due November 2023 [Member] | Debt Instrument, Redemption, Period Two [Member]
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	104.875%
Debt Instrument, Redemption Price, Percentage	35.00%
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed Upon Proceeds from Equity Offering	109.75%
Senior Second Lien Notes Due November 2023 [Member] | Debt Instrument, Redemption, Period Three [Member]
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	102.438%
Senior Second Lien Notes Due November 2023 [Member] | Debt Instrument, Redemption, Period Four [Member]
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	100.00%
Unsecured Senior Notes [Member] | Refinancing Transaction [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.50%									8.50%
Extinguishment of Debt, Amount	$ 189,800
Unsecured Senior Notes [Member] | Debt Exchange Transaction [Member]
Debt Conversion, Original Debt, Amount		$ 710,200
Debt Conversion, Original Debt, Percent of Outstanding Debt		79.00%
Unsecured Senior Notes [Member] | The Krohn Entity [Member]
Repayments of Unsecured Debt	5,000
Credit Agreement [Member]
Line of Credit Facility, Maximum Borrowing Capacity	$ 250,000									$ 250,000
Credit Agreement, Maximum Leverage Ratio			3
Credit Agreement, Maximum Leverage Ratio Following Material Acquisition	3.5									3.5
Credit Agreement, Minimum Current Ratio	1
Commitment Fee if Borrowing Base Utilization Percentage is Below 50%	0.375%									0.375%
Commitment Fee is the Borrowing Base Utilization Percentage is 50% or Greater	0.50%									0.50%
Debt Instrument, Covenant, Minimum Percentage of Derivative Contracts	50.00%
Letters of Credit Outstanding, Amount			$ 5,800	$ 9,600		$ 5,800	$ 9,600
Line of Credit Facility, Interest Rate During Period						4.90%
Credit Agreement [Member] | Minimum [Member] | Eurodollar [Member]
Debt Instrument, Basis Spread on Variable Rate	2.50%
Credit Agreement [Member] | Minimum [Member] | Base Rate [Member]
Debt Instrument, Basis Spread on Variable Rate	1.50%
Credit Agreement [Member] | Maximum [Member] | Eurodollar [Member]
Debt Instrument, Basis Spread on Variable Rate	3.50%
Credit Agreement [Member] | Maximum [Member] | Base Rate [Member]
Debt Instrument, Basis Spread on Variable Rate	2.50%
Credit Agreement [Member] | Letter of Credit [Member]
Line of Credit Facility, Maximum Borrowing Capacity	$ 30,000									$ 30,000
11.00% 1.5 Lien Term Loan Due November 2019 [Member]
Debt Instrument, Face Amount		$ 75,000
Interest Expense, Debt, Total									$ 0
11.00% 1.5 Lien Term Loan Due November 2019 [Member] | Refinancing Transaction [Member]
Extinguishment of Debt, Amount	$ 75,000
11.00% 1.5 Lien Term Loan Due November 2019 [Member] | Refinancing Transaction [Member]
Debt Instrument, Interest Rate, Stated Percentage	11.00%									11.00%
The Nine Percent Term Loan, due May 15, 2020 [Member] | Refinancing Transaction [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%									9.00%
Extinguishment of Debt, Amount	$ 300,000
Second Lien PIK Toggle Notes [Member] | Refinancing Transaction [Member]
Extinguishment of Debt, Amount	$ 177,500
Second Lien PIK Toggle Notes [Member] | Debt Exchange Transaction [Member]
Debt Conversion, Converted Instrument, Amount		159,800
Second Lien PIK Toggle Notes [Member] | Minimum [Member] | Refinancing Transaction [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%									9.00%
Second Lien PIK Toggle Notes [Member] | Maximum [Member] | Refinancing Transaction [Member]
Debt Instrument, Interest Rate, Stated Percentage	10.75%									10.75%
Third Lien PIK Toggle Notes [Member] | Refinancing Transaction [Member]
Extinguishment of Debt, Amount	$ 160,900
Third Lien PIK Toggle Notes [Member] | Debt Exchange Transaction [Member]
Debt Conversion, Converted Instrument, Amount		$ 142,000
Third Lien PIK Toggle Notes [Member] | Minimum [Member] | Refinancing Transaction [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.50%									8.50%
Third Lien PIK Toggle Notes [Member] | Maximum [Member] | Refinancing Transaction [Member]
Debt Instrument, Interest Rate, Stated Percentage	10.00%									10.00%
Second and Third Lien PIK Toggle Notes [Member] | Long-term Debt [Member]
Gain (Loss) on Extinguishment of Debt, Total								$ (400)
Basic Earnings Per Share Adjustment, Pro Forma | $ / shares								$ 0.06
Interest Paid, Excluding Capitalized Interest, Operating Activities					$ 8,200

Note 2 - Long-term Debt - Compo

Note 2 - Long-term Debt - Components of Long-term Debt (Details) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018	Oct. 18, 2018
Debt instrument		$ 730,000	$ 646,000
Total long-term debt		719,533	633,535
Credit Agreement [Member]
Debt instrument	[1]	105,000	21,000
Total long-term debt		105,000	21,000
Senior Second Lien Notes Due November 2023 [Member]
Debt instrument	[1]	614,533	612,535
Principal		625,000	625,000	$ 625,000
Unamortized debt issuance costs		(10,467)	(12,465)
Total long-term debt		$ 614,533	$ 612,535
[1]	Defined below

Note 3 - Fair Value Measureme_3

Note 3 - Fair Value Measurements - Fair Value of Open Derivative Financial Instruments (Details) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018
Derivatives instruments - open contracts, current	[1]	$ 7,266	$ 60,687
Derivatives		2,653	21,275
Open Contracts [Member]
Derivatives instruments - open contracts, current		6,921	74,580
Derivatives		2,653
Derivatives instruments - open contracts, current		$ 1,785
[1]	Includes both open and closed contracts.

Note 3 - Fair Value Measureme_4

Note 3 - Fair Value Measurements - Carrying Value and Fair Value of Long-term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Long-term debt, carrying value	$ 719,533	$ 633,535
Credit Agreement [Member]
Long-term debt, carrying value	105,000	21,000
Long-term debt, fair value	105,000	21,000
Senior Second Lien Notes Due November 2023 [Member]
Long-term debt, carrying value	614,533	612,535
Long-term debt, fair value	$ 597,188	$ 546,875

Note 4 - Joint Venture Drilli_2

Note 4 - Joint Venture Drilling Program (Details Textual) - USD ($) $ in Thousands	Mar. 12, 2018	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment, Net, Ending Balance		$ 748,798				$ 515,421				$ 748,798	$ 515,421
Other Assets, Noncurrent, Total		33,447				91,547				33,447	91,547
Asset Retirement Obligation, Ending Balance		355,594				310,137				355,594	310,137	$ 300,446
Revenue from Contract with Customer, Excluding Assessed Tax, Total		$ 151,894	$ 132,221	$ 134,701	$ 116,080	143,422	$ 153,459	$ 149,612	$ 134,213	534,896	580,706	487,096
Other Nonoperating Income (Expense), Total										$ (188)	3,871	$ (5,127)
JV Drilling Program [Member] | Mr. Tracy W. Krohn [Member]
Minority Interest Ownership Percentage By Joint Venture		4.50%								4.50%
Monza Energy, LLC [Member]
Property, Plant and Equipment, Net, Ending Balance		$ 16,100				8,800				$ 16,100	8,800
Other Assets, Noncurrent, Total		5,300				3,300				5,300	3,300
Asset Retirement Obligation, Ending Balance		100								100
Increase (Decrease) in Working Capital										2,700	700
Cash Call Balance		5,300				$ 20,600				5,300	20,600
Revenue from Contract with Customer, Excluding Assessed Tax, Total										11,900	4,300
Operating Costs and Expenses, Total										7,400	2,300
Other Nonoperating Income (Expense), Total											$ 200
Monza Energy, LLC [Member] | JV Drilling Program [Member]
Amount Committed by Investors	$ 361,400
Joint Venture Working Interest Percentage Contributed to Related Party	88.94%
Joint Venture Working Interest Percent	11.06%
Oil and Gas Revenue, Percent	30.00%
Well Cost, Percent	20.00%
Capital Contribution Payments from Related Party		273,300								273,300
Capital Contributions from Related Party During Period										30,200
Capital Contribution Payments to Related Party, Net		59,700								59,700
Monza Energy, LLC [Member] | JV Drilling Program [Member] | Mr. Tracy W. Krohn [Member]
Capital Commitment to Joint Venture		$ 14,500								$ 14,500

Note 5 - Acquisitions and Div_3

Note 5 - Acquisitions and Divestitures (Details Textual) - USD ($) $ in Thousands	Sep. 28, 2018	Apr. 05, 2018	Dec. 31, 2019	Aug. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Payments to Acquire Oil and Gas Property and Equipment, Total					$ 188,019	$ 16,782
Permian Basin [Member]
Proceeds from Sale of Productive Assets, Total	$ 56,600
Mobile Bay Properties [Member]
Payments to Acquire Businesses, Net of Cash Acquired, Total				$ 169,800
Payments to Acquire Oil and Gas Property and Equipment, Cash from Long-term Lines of Credit				$ 150,000
Magnolia Field Acquisition [Member]
Payments to Acquire Businesses, Net of Cash Acquired, Total			$ 15,900
Heidelberg Field [Member]
Payments to Acquire Businesses, Net of Cash Acquired, Total		$ 16,800
Payments to Acquire Oil and Gas Property and Equipment, Cash from Long-term Lines of Credit		$ 9,400
Percentage of Non-operated Working Interest Acquired		9.375%
Oil and Gas, Asset Acquisition, Amounts Included in Asset Retirement Obligations, Noncurrent, Total		$ 3,600
Payments to Acquire Oil and Gas Property and Equipment, Total		$ 19,600

Note 5 - Acquisitions and Div_4

Note 5 - Acquisitions and Divestitures - Purchase Price Allocation (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Aug. 31, 2019
Mobile Bay Properties [Member]
Oil and natural gas properties and other, net - at cost:		$ 192,373
Other assets		4,838
Current liabilities		1,559
Asset retirement obligations		21,684
Other liabilities		$ 4,132
Magnolia Field Acquisition [Member]
Oil and natural gas properties and other, net - at cost:	$ 23,791
Asset retirement obligations	$ 7,842

Note 6 - Asset Retirement Obl_3

Note 6 - Asset Retirement Obligations - Changes to Asset Retirement Obligation (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Asset retirement obligations		$ 310,137	$ 300,446
Liabilities settled		(11,443)	(28,617)
Asset retirement obligations accretion		19,460	18,431	$ 17,172
Liabilities incurred and assumed through acquisition		29,887	4,286
Revisions of estimated liabilities (1) (2)	[1],[2]	7,553	15,591
Asset retirement obligations		355,594	310,137	$ 300,446
Less current portion		21,991	24,994
Long-term		$ 333,603	$ 285,143
[1]	Revisions in 2018 reflect cost estimate increases as a result of new data on the required scope of work becoming available to us through 2018. This new data included data realized during the planning phase of the projects, and as the projects proceeded through the execution phase. This new data indicated that the scope was larger and more difficult than the scope used for end of 2017 estimates. As an example, larger heavy lift vessels would be needed for certain platform removals, and certain wells needed additional well plugging operations to complete the decommissioning per agency requirements.
[2]	Revisions in 2019

Note 7 - Leases (Details Textua

Note 7 - Leases (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 2.9
Lessee, Operating Lease, Liability, Payments, Due Year Two	0.3
Lessee, Operating Lease, Liability, Payments, Due Year Three	0.3
Lessee, Operating Lease, Liability, Payments, Due Year Four	0.5
Lessee, Operating Lease, Liability, Payments, Due Year Five	11
Right of Way Office Lease Expense	2.9	$ 3.4	$ 3
Short-term Lease, Cost	$ 22.2
Pipeline Right-of-way Contracts [Member]
Lessee, Operating Lease, Term of Contract	10 years
Lessee, Operating Lease, Renewal Term	10 years
Land Acquired in Mobile Bay Properties Acquisition [Member]
Lessee, Operating Lease, Renewal Term	5 years
Office Lease [Member]
Lessee, Operating Lease, Discount Rate	9.75%
Other Leases [Member]
Lessee, Operating Lease, Discount Rate	10.75%

Note 7 - Leases - Lessee Assets

Note 7 - Leases - Lessee Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
ROU assets	$ 7,936
Other Noncurrent Assets [Member]
ROU assets	7,936
Accrued Liabilities [Member]
Accrued liabilities	2,716
Other Noncurrent Liabilities [Member]
Other liabilities	4,419
Accrued Liabilities and Other Noncurrent Liabilities [Member]
Total lease liability	$ 7,135

Note 8 - Insurance Claims (Deta

Note 8 - Insurance Claims (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Proceeds from Insurance Settlement, Operating Activities			$ 31,700
Insurance Recoveries	$ 0	$ 0
Accrued Insurance	$ 0

Note 10 - Derivative Financia_3

Note 10 - Derivative Financial Instruments - Summary of Open Commodity Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2019$ / sharesbbl
NYMEX Crude Oil Calls [Member] | Open Crude Oil Derivative Contracts 1 [Member] | Long [Member]
Termination Period	May 2020
Notional Quantity (Bbls/day) (Barrel of Oil) | bbl	10,000	[1]
Notional Quantity (Bbls)	1,520,000	[1]
Strike Price (in dollars per share)	$ 61
NYMEX Crude Oil Calls [Member] | Open Crude Oil Derivative Contracts 2 [Member] | Long [Member]
Termination Period	December 2020
Notional Quantity (Bbls/day) (Barrel of Oil) | bbl	10,000	[1]
Notional Quantity (Bbls)	2,140,000	[1]
Strike Price (in dollars per share)	$ 67.50
NYMEX Crude Oil Swap [Member] | Open Crude Oil Derivative Contracts 1 [Member]
Termination Period	May 2020
Notional Quantity (Bbls/day) (Barrel of Oil) | bbl	1,500	[1]
Notional Quantity (Bbls)	228,000	[1]
Strike Price (in dollars per share)	$ 60.80
NYMEX Crude Oil Swap [Member] | Open Crude Oil Derivative Contracts 2 [Member]
Termination Period	May 2020
Notional Quantity (Bbls/day) (Barrel of Oil) | bbl	5,000	[1]
Notional Quantity (Bbls)	760,000	[1]
Strike Price (in dollars per share)	$ 61
NYMEX Crude Oil Swap [Member] | Open Crude Oil Derivative Contracts 3 [Member]
Termination Period	May 2020
Notional Quantity (Bbls/day) (Barrel of Oil) | bbl	3,500	[1]
Notional Quantity (Bbls)	532,000	[1]
Strike Price (in dollars per share)	$ 60.85
NYMEX Crude Oil Collars [Member] | Open Crude Oil Derivative Contracts 1 [Member]
Termination Period	December 2020
Notional Quantity (Bbls/day) (Barrel of Oil) | bbl	9,000	[1]
Notional Quantity (Bbls)	1,926,000	[1]
NYMEX Crude Oil Collars [Member] | Open Crude Oil Derivative Contracts 1 [Member] | Long [Member] | Put Option [Member]
Strike Price (in dollars per share)	$ 45
NYMEX Crude Oil Collars [Member] | Open Crude Oil Derivative Contracts 1 [Member] | Short [Member] | Call Option [Member]
Strike Price (in dollars per share)	$ 63.50
NYMEX Crude Oil Collars [Member] | Open Crude Oil Derivative Contracts 2 [Member]
Termination Period	December 2020
Notional Quantity (Bbls/day) (Barrel of Oil) | bbl	1,000	[1]
Notional Quantity (Bbls)	214,000	[1]
NYMEX Crude Oil Collars [Member] | Open Crude Oil Derivative Contracts 2 [Member] | Long [Member] | Put Option [Member]
Strike Price (in dollars per share)	$ 45
NYMEX Crude Oil Collars [Member] | Open Crude Oil Derivative Contracts 2 [Member] | Short [Member] | Call Option [Member]
Strike Price (in dollars per share)	$ 63.60
NYMEX Natural Gas Two Way Collars [Member]
Termination Period	December 2022
Notional Quantity (Bbls/day) (Barrel of Oil) | bbl	40,000	[2]
Notional Quantity (Bbls)	43,840,000	[2]
Strike Price (in dollars per share)	$ 3
[1]	Bbls = Barrels
[2]	Bbls = Barrels

Note 10 - Derivative Financia_4

Note 10 - Derivative Financial Instruments - Fair Value of Open and Closed Contracts Which Had Not Yet Settled (Details) - USD ($) $ in Thousands		3 Months Ended					12 Months Ended
		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Prepaid and other assets – current	[1]	$ 7,266				$ 60,687	$ 7,266	$ 60,687
Other assets – non-current		2,653				21,275	2,653	21,275
Derivative loss (gain)		18,700	$ (5,900)	$ (1,800)	$ 48,900	(59,700)	59,887	(53,798)	$ (4,199)
Accrued Liabilities [Member]
Accrued liabilities		1,785					1,785
Open Contracts and Closed Contracts Which Had Not Yet Been Settled [Member] | Prepaid Expenses and Other Current Assets [Member]
Prepaid and other assets – current		7,266				60,687	7,266	60,687
Open Contracts and Closed Contracts Which Had Not Yet Been Settled [Member] | Other Noncurrent Assets [Member]
Other assets – non-current		2,653				21,275	2,653	21,275
Open Contracts and Closed Contracts Which Had Not Yet Been Settled [Member] | Accrued Liabilities [Member]
Accrued liabilities		$ 1,785					$ 1,785
[1]	Includes both open and closed contracts.

Note 10 - Derivative Financia_5

Note 10 - Derivative Financial Instruments - Cash Receipts on Commodity Derivative Contract Settlements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivatives cash receipts (payments), net	$ 13,941	$ (28,164)	$ 4,199

Note 11 - Share-based Awards _3

Note 11 - Share-based Awards and Cash-based Awards (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	10,874,043
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other than Options, Granted in Period, Grant Date Fair Value	$ 4.5	$ 6.8	$ 5.9
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Grant Date Fair Value	7	$ 11	$ 5.5
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total	$ 5.1
Restricted Stock Units (RSUs) [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Percent of Adjustments	0.00%	0.00%	0.00%
Restricted Stock Units (RSUs) [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Percent of Adjustments	100.00%	100.00%	100.00%
Restricted Stock [Member]
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total	$ 0.4
Restricted Stock [Member] | Directors Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	82,620
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other than Options, Granted in Period, Grant Date Fair Value	$ 0.3	$ 0.3	$ 0.3
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Grant Date Fair Value	$ 0.5	$ 0.7	$ 0.1
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Restricted Stock [Member] | Directors Compensation Plan [Member] | Share-based Payment Arrangement, Tranche One [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	33.00%
Cash-based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Adjusted EBITDA Less Interest, Minimum	$ 200

Note 11 - Share-based Awards _4

Note 11 - Share-based Awards and Cash-based Awards - Summary of Share Activity Related to Restricted Stock Units (Details) - Restricted Stock Units (RSUs) [Member] - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Nonvested, units (in shares)	3,355,917	5,765,251	6,107,248
Nonvested, beginning of period (in dollars per share)	$ 3.90	$ 2.48	$ 2.73
Granted, units (in shares)	994,698	988,955	2,128,879
Granted, weighted average grant date fair value per unit (in dollars per share)	$ 4.51	$ 6.90	$ 2.76
Vested, units (in shares)	(1,475,373)	(2,261,665)	(2,108,553)
Vested (in dollars per share)	$ 2.76	$ 2.21	$ 3.45
Forfeited, units (in shares)	(1,260,520)	(1,136,624)	(362,323)
Forfeited, weighted average grant date fair value per unit (in dollars per share)	$ 3.37	$ 2.68	$ 2.87
Nonvested, units (in shares)	1,614,722	3,355,917	5,765,251
Nonvested, end of period (in dollars per share)	$ 5.73	$ 3.90	$ 2.48

Note 11 - Share-based Awards _5

Note 11 - Share-based Awards and Cash-based Awards - Schedule of Outstanding Restricted Stock Units Issued to Eligible Employees (Details) - Restricted Stock Units (RSUs) [Member] - shares	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Awards expected to vest (in shares)	1,614,722	3,355,917	5,765,251	6,107,248
Vesting in 2020 [Member]
Awards expected to vest (in shares)	821,656
Vesting in 2021 [Member]
Awards expected to vest (in shares)	793,066

Note 11 - Share-based Compensat

Note 11 - Share-based Compensation and Cash-based Incentive Compensation - Summary of Restricted Stock Activity (Details) - Restricted Stock [Member] - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Nonvested, units (in shares)	181,832	246,528	161,296
Nonvested, beginning of period (in dollars per share)	$ 3.08	$ 2.27	$ 3.47
Granted, units (in shares)	46,360	41,544	147,372
Granted, weighted average grant date fair value per unit (in dollars per share)	$ 6.04	$ 6.74	$ 1.90
Vested, units (in shares)	(105,012)	(106,240)	(62,140)
Vested (in dollars per share)	$ 2.67	$ 2.64	$ 4.51
Nonvested, units (in shares)	123,180	181,832	246,528
Nonvested, end of period (in dollars per share)	$ 4.55	$ 3.08	$ 2.27

Note 11 - Share-based Awards _6

Note 11 - Share-based Awards and Cash-based Awards - Schedule of Outstanding Restricted Shares Issued to Non-employee Directors (Details) - Restricted Stock [Member] - shares	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Awards expected to vest by period (in shares)	123,180	181,832	246,528	161,296
Vesting in 2020 [Member]
Awards expected to vest by period (in shares)	78,428
Vesting in 2021 [Member]
Awards expected to vest by period (in shares)	29,304
Vesting in 2022 [Member]
Awards expected to vest by period (in shares)	15,448

Note 11 - Share-based Awards _7

Note 11 - Share-based Awards and Cash-based Awards - Summary of Incentive Compensation Expense Under Share-based Payment Arrangements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based compensation expense	$ 3,690	$ 3,540	$ 8,065
Restricted Stock Units (RSUs) [Member]
Share-based compensation expense	3,410	3,260	7,785
Restricted Stock [Member]
Share-based compensation expense	$ 280	$ 280	$ 280

Note 11 - Share-based Awards _8

Note 11 - Share-based Awards and Cash-based Awards - Summary of Compensation Expense Related to Share-Based Awards and Cash-Based Awards (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based compensation expense	$ 3,690	$ 3,540	$ 8,065
Total charged to operating income	14,793	16,722	15,198
General and Administrative Expense [Member]
Share-based compensation expense	3,690	3,540	8,065
Cash-based incentive compensation	8,897	9,586	5,032
Lease Operating Expense [Member]
Cash-based incentive compensation	$ 2,206	$ 3,596	$ 2,101

Note 12 - Employee Benefit Pl_2

Note 12 - Employee Benefit Plan (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	100.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	6.00%
Deferred Compensation Arrangement with Individual, Requisite Service Period	5 years
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage	20.00%
Defined Contribution Plan, Cost	$ 2	$ 2	$ 1.4

Note 13 - Income Taxes (Details

Note 13 - Income Taxes (Details Textual) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	21.00%	35.00%
Income Taxes Receivable, Current		$ 1,861	$ 54,076
Proceeds from Income Tax Refunds		51,833	11,126	$ 11,906
Income Taxes Paid		51	138	185
Interest Income Related to Income Tax Refunds		4,500
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ (105,900)	(63,300)	(53,800)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount		(64,704)	(53,980)	$ (118,643)
Deferred Tax Assets, Valuation Allowance, Total		$ 54,436	$ 117,764
Open Tax Year		2016 2017 2018 2019

Note 13 - Income Taxes - Compon

Note 13 - Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current					$ (11,092)	$ 35	$ (12,786)
Deferred					(64,102)	500	217
Total income tax (benefit) expense	$ (8,200)	$ (55,500)	$ (11,700)	$ 200	$ (75,194)	$ 535	$ (12,569)

Note 13 - Income Taxes - Reconc

Note 13 - Income Taxes - Reconciliation of Income Taxes Computed to Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income tax (benefit) expense at the federal statutory rate, amount					$ (233)	$ 52,366	$ 23,490
Compensation adjustments, amount					971	457	664
State income taxes, amount					(175)	560	63
Uncertain tax position, amount					(11,523)
Impact of U.S. tax reform, amount						487	105,933
Gain on exchange of debt, amount							(24,981)
Valuation allowance, amount					(64,704)	(53,980)	(118,643)
Other, amount					470	645	905
Income tax (benefit) expense	$ (8,200)	$ (55,500)	$ (11,700)	$ 200	$ (75,194)	$ 535	$ (12,569)

Note 13 - Income Taxes - Signif

Note 13 - Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax liabilities:
Property and equipment	$ 21,647
Derivatives		11,139
Investment in non-consolidated entity	14,716	6,875
Other	2,283	812
Total deferred tax liabilities	38,646	18,826
Deferred tax assets:
Property and equipment		3,934
Derivatives	1,409
Asset retirement obligations	76,924	65,811
Federal net operating losses	15,265	10,039
State net operating losses	7,393	7,133
Interest expense limitation carryover	48,458	41,814
Share-based compensation	965	583
Valuation allowance	(54,436)	(117,764)
Other	6,584	7,091
Total deferred tax assets	102,562	18,641
Net deferred tax assets	$ 63,916
Net deferred tax liabilities		$ (185)

Note 13 - Income Taxes - Net Op

Note 13 - Income Taxes - Net Operating Loss, Interest and Tax Credit Carryovers (Details) $ in Thousands	Dec. 31, 2019USD ($)
Net operating loss, amount	$ 223,928
Domestic Tax Authority [Member]
Net operating loss, amount	72,692
State and Local Jurisdiction [Member]
Net operating loss, amount	$ 122,155

Note 13 - Income Taxes - Balanc

Note 13 - Income Taxes - Balances in Uncertain Tax Positions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Balance, beginning of period	$ 9,482	$ 9,482
Decrease during the period	(9,482)
Balance, end of period		$ 9,482

Note 14 - Earnings Per Share -

Note 14 - Earnings Per Share - Schedule of Basic and Diluted (Loss) Earnings Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net income	$ 9,559	[1]	$ 75,899	[1]	$ 36,389	[1]	$ (47,761)	[1]	$ 138,844	[1]	$ 46,260	[1]	$ 36,083	[1]	$ 27,640	[1]	$ 74,086	$ 248,827	$ 79,682
Less portion allocated to nonvested shares																	1,371	9,727	3,244
Net income allocated to common shares																	$ 72,715	$ 239,100	$ 76,438
Weighted average common shares outstanding (in shares)																	140,583	139,002	137,617
Basic and diluted earnings per common share (in dollars per share)	$ 0.07		$ 0.53		$ 0.25		$ (0.34)		$ 0.96		$ 0.32		$ 0.25		$ 0.19		$ 0.52	$ 1.72	$ 0.56
[1]	During 2019, we recorded a derivative loss (gain) of $48.9 million, ($1.8) million, ($5.9) million, and $18.7 million in the first, second, third and fourth quarters, respectively. During 2019, we recorded income tax expense (benefit) of $0.2 million, ($11.7) million, ($55.5) million and ($5.9) million in the first, second, third and fourth quarters, respectively. During the fourth quarter of 2018, we recorded a gain on debt transactions of $47.1 million and a derivative gain of $59.7 million. See Note 2, Note 9 and Note 13 for additional information.

Note 15 - Supplemental Cash F_3

Note 15 - Supplemental Cash Flow Information (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interest Costs Capitalized Adjustment	$ 0	$ 0	$ 0

Note 15 - Supplemental Cash F_4

Note 15 - Supplemental Cash Flow Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental cash items:
Cash paid for income taxes		$ 51	$ 138	$ 185
Cash refunds received for income taxes		51,833	11,126	11,906
Cash paid for share-based compensation (2)	[1]		1,130	874
Cash received for interest income		7,720	2,385	315
Non-cash investing activities:
Accruals of property and equipment		29,662	18,575	33,003
ARO - additions, dispositions and revisions, net		37,440	19,877	21,245
Debt Convert to Second Lien Term Loan, due May 2020 [Member]
Supplemental cash items:
Cash paid for interest	[2]	$ 66,720	$ 61,501	$ 65,873
[1]	During 2019, only common shares were used to settle vested RSUs and Restricted Shares. During 2018 and 2017, cash was used to settle vested RSUs related to the retirement of executive officers and shares of common stock were used to settle all other vested RSUs and to settle Restricted Shares.
[2]	During 2018 and 2017, cash paid for interest included amounts related to the debt instruments issued during 2016, which were accounted for under ASC 470-60 and recorded against the carrying value of the debt instruments on the Consolidated Balance Sheets and included in financing activities on the Consolidated Statements of Cash Flows. No interest was capitalized in the periods presented.

Note 16 - Commitments (Details

Note 16 - Commitments (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Escrow Deposit		$ 49,500
Expense Relating to Surety Bonds Paid.	4,700	5,900	$ 5,700
Deposit Liabilities, Collateral Issued, Financial Instruments	6,900
Surety Bonds [Member]
Other Commitment, Due in Next Twelve Months	4,600
Other Commitment, Due in Second Year	4,600
Other Commitment, Due in Third Year	20,224,600
Other Commitment, Due in Fourth Year	4,700
Other Commitment, Due in Fifth Year	4,700
Other Commitment, Due after Fifth Year	52,000
Surety Bonds [Member] | Other Commitment [Member]
Bonding Requirement, Related To Purchase of Properties Minimum Amount	64,000
Bonding Requirement Related To Purchase of Properties Maximum Amount	94,000
Surety Bonds [Member] | Total E&P [Member]
Bonding Requirement Related to Purchase of Properties Amount Current Year.	90,700
Escrow Deposit	0
Bonding Requirement Related to Purchase of Properties Amount, Fifth Anniversary.	103,000
Bonding Requirement Related to Purchase of Properties Amount Increment From Second Anniversary.	3,000
Surety Bonds [Member] | Exxon [Member]
Bonding Requirement, Related To Purchase of Properties Minimum Amount	27,300
Other Commitment, Due in Next Twelve Months	30,000
Other Commitment, Due in Second Year	33,000
Other Commitment, Due in Third Year	36,300
Other Commitment, Due in Fourth Year	40,000
Other Commitment, Due in Fifth Year	44,000
Other Commitment, Due after Fifth Year	114,000
Surety Bonds [Member] | Exxon [Member] | Minimum [Member]
Annual Increase in Other Commitment	4,000
Surety Bonds [Member] | Exxon [Member] | Maximum [Member]
Annual Increase in Other Commitment	9,000
Surety Bonds [Member] | Conoco [Member]
Bonding Requirement, Related To Purchase of Properties Minimum Amount	49,000
Heidelberg Field [Member]
Other Commitment, Due in Next Twelve Months	3,700
Other Commitment, Due in Second Year	2,200
Other Commitment, Due in Third Year	1,600
Other Commitment, Due in Fourth Year	1,200
Other Commitment, Due in Fifth Year	800
Other Commitment, Due after Fifth Year	1,300
Other Commitment, Expense	$ 4,500	$ 2,300

Note 17 - Related Parties (Deta

Note 17 - Related Parties (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Airplane Services [Member]
Related Party Transaction, Amounts of Transaction	$ 1.2	$ 1.3	$ 1.2
Marine Transportation and Logistic Services [Member]
Related Party Transaction, Amounts of Transaction	0.2	0.2	0.2
Repayments of Related Party Debt	$ 22.8	21	$ 22.8
CEO and Largest Shareholder [Member] | Senior Second Lien Note Issuance [Member]
Debt Instrument, Face Amount		$ 8

Note 18 - Contingencies (Detail

Note 18 - Contingencies (Details Textual) $ in Thousands	May 31, 2017USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jul. 25, 2017USD ($)	Jun. 30, 2017USD ($)	Jan. 27, 2017USD ($)	Dec. 31, 2010USD ($)
Escrow Deposit			$ 49,500
Additional Royalty Due to Disallowed Deductions							$ 4,700	$ 4,700
Bonds Posted to Appeal IBLA Decision					$ 7,200
Collateral for Bonds Posted Related to Appeal with IBLA					$ 6,900
Incremental Payments for Royalties Related to Unbundling		400	600	$ 1,600
Minerals Management Service ("MMS") [Member]
Loss Contingency Accrual, Ending Balance		250
BSEE [Member]
Loss Contingency Accrual, Ending Balance		3,500	3,500
Payment for Civil Penalty		$ 0	0
Loss Contingency, Number of Claims Filed		9
Proposed Civil Penalties		$ 7,700
Other Noncurrent Liabilities [Member]
Loss Contingency Accrual, Ending Balance			49,500
Apache Corporation [Member] | Judicial Ruling [Member]
Loss Contingency, Damages Awarded, Value	$ 49,500
Escrow Deposit						$ 49,500
Apache Corporation [Member] | Judicial Ruling [Member] | Interest Expense [Member]
Interest Income, Litigation		$ 1,900
Apache Corporation [Member] | Judicial Ruling [Member] | Other Noncurrent Assets [Member]
Loss Contingency Accrual, Ending Balance			49,500
Apache Corporation [Member] | Judicial Ruling [Member] | Other Noncurrent Liabilities [Member]
Loss Contingency Accrual, Ending Balance			$ 49,500

Note 19 - Selected Quarterly _3

Note 19 - Selected Quarterly Financial Data - Unaudited (Details Textual) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Gain (Loss) on Derivative Instruments, Net, Pretax, Total	$ (18,700)	$ 5,900	$ 1,800	$ (48,900)	$ 59,700	$ (59,887)	$ 53,798	$ 4,199
Income Tax Expense (Benefit), Total	$ (8,200)	$ (55,500)	$ (11,700)	$ 200		(75,194)	535	(12,569)
Gain (Loss) on Extinguishment of Debt, Total					$ 47,100		$ 47,109	$ 7,811

Note 19 - Selected Quarterly _4

Note 19 - Selected Quarterly Financial Data - Unaudited - Unaudited Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Total revenues	$ 151,894		$ 132,221		$ 134,701		$ 116,080		$ 143,422		$ 153,459		$ 149,612		$ 134,213		$ 534,896	$ 580,706	$ 487,096
Operating (loss) income	16,847		35,399		37,379		(30,976)		102,674		57,147		48,467		38,739		58,649	247,027	109,950
Net income	$ 9,559	[1]	$ 75,899	[1]	$ 36,389	[1]	$ (47,761)	[1]	$ 138,844	[1]	$ 46,260	[1]	$ 36,083	[1]	$ 27,640	[1]	$ 74,086	$ 248,827	$ 79,682
Basic and diluted earnings per common share (in dollars per share)	$ 0.07		$ 0.53		$ 0.25		$ (0.34)		$ 0.96		$ 0.32		$ 0.25		$ 0.19		$ 0.52	$ 1.72	$ 0.56
[1]	During 2019, we recorded a derivative loss (gain) of $48.9 million, ($1.8) million, ($5.9) million, and $18.7 million in the first, second, third and fourth quarters, respectively. During 2019, we recorded income tax expense (benefit) of $0.2 million, ($11.7) million, ($55.5) million and ($5.9) million in the first, second, third and fourth quarters, respectively. During the fourth quarter of 2018, we recorded a gain on debt transactions of $47.1 million and a derivative gain of $59.7 million. See Note 2, Note 9 and Note 13 for additional information.

Note 20 - Supplemental Oil an_3

Note 20 - Supplemental Oil and Gas Disclosures - Unaudited (Details Textual) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)MMBoe	Dec. 31, 2018USD ($)MMBoe	Dec. 31, 2017USD ($)BoeMMBoe
Asset Retirement Obligation, Period Increase (Decrease) Due To Acquisitions Incurred and Revisions | $	$ 37.5	$ 20.3	$ 21.3
Seismic Costs | $	7.8	1.5	0.5
Geological and Geophysical Costs | $	$ 5.7	$ 5.4	$ 4.2
Percentage of Non-operated Proved Developed Non-producing Reserves	10.70%
Proved Undeveloped Reserve Net Energy Converted Outside of Five Years	2.5
Percentage of Proved Undeveloped Reserves Expected To Be Developed	11.00%
Present Value Discounted Percentage.		10.00%
Barrel Equivalent [Member] | Proved Undeveloped Reserves [Member]
Proved Developed and Undeveloped Reserve, Net (Energy), Ending Balance	23.6
Changes Due To Price [Member]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		2.3	3.4
Proved Developed and Undeveloped Reserve, Extension and Discovery (Energy)	10
Changes at Ship Shoal 349 Field (Mahogany) [Member]
Proved Developed and Undeveloped Reserve, Extension and Discovery (Energy) | Boe			3.5
Main Pass 286 Field [Member]
Proved Developed and Undeveloped Reserve, Extension and Discovery (Energy) | Boe			1.5
Changes at the Viosca Knoll 823 [Member]
Proved Developed and Undeveloped Reserve, Extension and Discovery (Energy)		1.3
Ewing Bank 910 Field [Member]
Proved Developed and Undeveloped Reserve, Extension and Discovery (Energy)		0.7
Mississippi Canyon 800 (Gladden) Field [Member]
Proved Developed and Undeveloped Reserve, Extension and Discovery (Energy)	0.9
Mississippi Canyon 243 Field [Member]
Wells Expected To Be Drilled, Year	2021
Virgo Deepwater Fields [Member]
Wells Expected To Be Drilled, Year	2022

Note 20 - Supplemental Oil an_4

Note 20 - Supplemental Oil and Gas Disclosures - Unaudited - Capitalized Costs Related to Oil and Natural Gas (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net capitalized cost:
Proved oil and natural gas properties and equipment	$ 8,532.2	$ 8,169.9	$ 8,102
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities	(7,793.3)	(7,665.1)	(7,525)
Net capitalized costs related to producing activities	$ 738.9	$ 504.8	$ 577

Note 20 - Supplemental Oil an_5

Note 20 - Supplemental Oil and Gas Disclosures - Cost Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Costs incurred: (1)
Proved properties acquisitions	[1]	$ 223.8	$ 24.1	$ 1.1
Exploration (2) (3)	[1],[2],[3]	30.6	49.9	62
Development	[1]	114.5	56.2	92.5
Total costs incurred in oil and gas property acquisition, exploration and development activities	[1]	$ 368.9	$ 130.2	$ 155.6
[1]	Includes net additions from capitalized ARO of $x.x million, $20.3 million and $21.3 million during 2019, 2018 and 2017, respectively. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates.
[2]	Includes geological and geophysical costs charged to expense of $x.x million, $5.4 million and $4.2 million during 2019, 2018 and 2017, respectively.
[3]	Includes seismic costs of $x.x million, $1.5 million and $0.5 million incurred during 2019, 2018 and 2017, respectively.

Note 20 - Supplemental Oil an_6

Note 20 - Supplemental Oil and Gas Disclosures - Schedule of Depreciation, Depletion, Amortization and Accretion Expense (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Depreciation, depletion, amortization and accretion per Boe	$ 10.01	$ 11.24	$ 10.68

Note 20 - Supplemental Oil an_7

Note 20 - Supplemental Oil and Gas Disclosures - Estimated Quantities of Net Proved, Proved Developed and Proved Undeveloped Oil, NGLs and Natural Gas Reserves (Details) ft³ in Billions, Boe in Billions		12 Months Ended
		Dec. 31, 2019MMBoeMcfeft³MMBbls		Dec. 31, 2018BoeMMBoeMcfeft³MMBbls		Dec. 31, 2017BoeMMBoeMcfeft³MMBbls
Oil [Member]
Proved reserves, balance (Million Barrels of Oil)		39.1		34.4		32.9
Revisions of previous estimates (Million Barrels of Oil)		1.4	[1]	11.6	[2]	4.5	[3]
Extensions and discoveries (Million Barrels of Oil)		0.9	[4]	0.5	[5]	4.1	[6]
Production (Million Barrels of Oil)		(6.7)		(6.7)		(7,100,000)
Purchase of minerals in place (Million Barrels of Oil)		3,100,000	[7]	1.5	[8]
Sales of minerals in place (Million Barrels of Oil)	[9]			(2.2)
Proved reserves, balance (Million Barrels of Oil)		37.8		39.1		34.4
Proved reserves, ending balance (Million Barrels of Oil)		28		31.5		26.1
Undeveloped reserves, ending balance (Million Barrels of Oil)		9.8	[10]	7.6		8.3
Natural Gas Liquids [Member]
Proved reserves, balance (Million Barrels of Oil)		9.8		7.8		8.2
Revisions of previous estimates (Million Barrels of Oil)		(1.5)	[1]	2.8	[2]	0.7	[3]
Extensions and discoveries (Million Barrels of Oil)		0.1	[4]	0.3	[5]	0.3	[6]
Production (Million Barrels of Oil)		(1.3)		(1.3)		(1.4)
Purchase of minerals in place (Million Barrels of Oil)		17.4	[7]	0.4	[8]
Sales of minerals in place (Million Barrels of Oil)	[9]			(0.2)
Proved reserves, balance (Million Barrels of Oil)		24.5		9.8		7.8
Proved reserves, ending balance (Million Barrels of Oil)		21.7		7.8		7.2
Undeveloped reserves, ending balance (Million Barrels of Oil)		2.8	[10]	2		0.6
Natural Gas [Member]
Proved reserves, balance (Million Barrels of Oil) | ft³		210.5		192.2		197.8
Revisions of previous estimates (Million Barrels of Oil) | ft³		(16.9)	[1]	40.4	[2]	25.8	[3]
Extensions and discoveries (Million Barrels of Oil) | ft³		1.2	[4]	7.7	[5]	5.4	[6]
Production (Million Barrels of Oil) | ft³		(41.3)		(32)		(36.8)
Purchase of minerals in place (Million Barrels of Oil) | ft³		417.6	[7]	9.4	[8]
Sales of minerals in place (Million Barrels of Oil) | ft³	[9]			(7.2)
Proved reserves, balance (Million Barrels of Oil) | ft³		571.1		210.5		192.2
Proved reserves, ending balance (Million Barrels of Oil) | ft³		504.9		166.8		173.5
Undeveloped reserves, ending balance (Million Barrels of Oil) | ft³		66.2	[10]	43.7		18.7
Oil Equivalent [Member]
Proved reserves, balance (Millions of Barrels of Oil Equivalent) | MMBoe	[11]	84		74.2		74
Revisions of previous estimates (Millions of Barrels of Oil Equivalent) | MMBoe	[11]	(3)	[1]	21.1	[2]	9.6	[3]
Extensions and discoveries (Millions of Barrels of Oil Equivalent) | MMBoe		1.1	[4]	2.1	[5],[11]	5.2	[6],[11]
Production (Millions of Barrels of Oil Equivalent) | MMBoe	[11]	(14.8)		(13.3)		(14.6)
Purchase of minerals in place (Millions of Barrels of Oil Equivalent) | MMBoe		90.1	[7]	3.4	[8],[11]
Sales of minerals in place (Millions of Barrels of Oil Equivalent) | MMBoe	[9],[11]			(3.5)
Proved reserves, balance (Millions of Barrels of Oil Equivalent) | MMBoe	[11]	157.4		84		74.2
Proved reserves, ending balance (Millions of Barrels of Oil Equivalent) | MMBoe		133.8		67	[11]	62.2	[11]
Undeveloped reserves, ending balance (Millions of Barrels of Oil Equivalent) | MMBoe		23.6	[10]	17	[11]	12	[11]
Natural Gas Equivalent [Member]
Proved reserves, balance (Millions of Barrels of Oil Equivalent)	[11]	504,100,000		445.3		444,000,000
Revisions of previous estimates (Millions of Barrels of Oil Equivalent) | Mcfe	[11]	(18,200,000)	[1]	126,700,000	[2]	57,400,000	[3]
Extensions and discoveries (Millions of Barrels of Oil Equivalent) | Mcfe		6.7	[4]	12,600,000	[5],[11]	31,300,000	[6],[11]
Production (Millions of Barrels of Oil Equivalent)	[11]	(89,000,000)		(80,000,000)		(87.4)
Purchase of minerals in place (Millions of Barrels of Oil Equivalent) | Mcfe		540,900,000	[7]	20,700,000	[8],[11]
Sales of minerals in place (Millions of Barrels of Oil Equivalent) | Mcfe	[9],[11]			(21,200,000)
Proved reserves, balance (Millions of Barrels of Oil Equivalent)	[11]	944,500,000		504,100,000		445.3
Proved reserves, ending balance (Millions of Barrels of Oil Equivalent) | Mcfe		802,900,000		402,200,000	[11]	373,300,000	[11]
Undeveloped reserves, ending balance (Millions of Barrels of Oil Equivalent) | Mcfe		141,600,000	[10]	101,900,000	[11]	72,000,000	[11]
[1]	Primarily related to upward revisions related to our Ship Shoal 028 field and our Main Pass 108 field. Additionally, decreases of 10.0 MMBoe were due to price revisions for all proved reserves, which includes estimated price revisions of the purchase of minerals in place from the date of purchase to December 31, 2019.
[2]	Primarily related to upward revisions at our Mahogany field and our Ship Shoal 028 field. Additionally, increases of 2.3 MMBoe were due to price revisions.
[3]	Primarily related to upward revisions at our Mississippi Canyon 698 (Big Bend) field, our Fairway field, our Ewing Bank 910 field and our Viosca Knoll 783 (Tahoe/SE Tahoe) field. Additionally, increases of 3.4 MMBoe were due to price revisions.
[4]	Primarily related to extensions and discoveries of 0.9 MMBoe at our Mississippi Canyon 800 (Gladden) field.
[5]	Primarily related to extensions and discoveries of 1.3 MMBoe at our Viosca Knoll 823 (Virgo) field and 0.7 MMBoe at our Ewing Bank 910 field.
[6]	Primarily related to extensions and discoveries at our Ship Shoal 349 (Mahogany) field of 3.5 MMBoe and at our Main Pass 286 field of 1.5 MMBoe.
[7]	Primarily related to the Mobile Bay Properties and Magnolia acquisitions
[8]	Primarily related to our Ship Shoal 028 field and our Green Canyon 859 field (Heidelberg).
[9]	Primarily related to conveyance of interest in properties related to the JV Drilling Program.
[10]	We believe that we will be able to develop all but 2.5 MMBoe (approximately 11%) of the total of 23.6 MMBoe reserves classified as proved undeveloped ("PUDs") at December 31, 2019, within five years from the date such reserves were initially recorded. The lone exceptions are at the Mississippi Canyon 243 field (Matterhorn) and Virgo deepwater fields where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability. Three sidetrack PUD locations, two at Mississippi Canyon 243 (Matterhorn) field and one at Virgo, will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, these PUD locations are expected to be developed in 2021 and 2022, respectively.
[11]	The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly.

Note 20 - Supplemental Oil an_8

Note 20 - Supplemental Oil and Gas Disclosures - Schedule of Prices Weighted by Field Production Related to Proved Reserves (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil [Member]
Weighted price	$ 58.11	$ 65.21	$ 46.58	$ 36.28
Natural Gas Liquids [Member]
Weighted price	18.72	29.73	22.65	16.82
Natural Gas [Member]
Weighted price	$ 2.63	$ 3.13	$ 2.86	$ 2.47

Note 20 - Supplemental Oil an_9

Note 20 - Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows		$ 4,153.8	$ 3,500.9	$ 2,328.8
Production		(1,901.1)	(958.5)	(813.8)
Development		(297.3)	(272.4)	(157.4)
Dismantlement and abandonment		(497.4)	(355.9)	(361.9)
Income taxes	[1]	(170.5)	(293.9)	(74.8)
Future net cash inflows before 10% discount		1,287.5	1,620.2	920.9
10% annual discount factor		(300.6)	(553.2)	(180.3)
Total		$ 986.9	$ 1,067	$ 740.6	$ 478.3
[1]	No future income taxes were estimated for 2016 as our tax position had sufficient tax basis to offset estimated future taxes. State income taxes were disregarded due to immateriality.

Note 20 - Supplemental Oil a_10

Note 20 - Supplemental Oil and Gas Disclosures - Change in Standard Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Changes in Standardized Measure
Standardized measure, beginning of year	$ 1,067	$ 740.6	$ 478.3
Sales and transfers of oil and gas produced, net of production costs	(315.8)	(398.1)	(315.3)
Net changes in price, net of future production costs	(376.4)	571.5	288
Extensions and discoveries, net of future production and development costs	27	53.6	119.3
Changes in estimated future development costs	(6)	(114.7)	(38.9)
Previously estimated development costs incurred	19.3	48.4	102.8
Revisions of quantity estimates	116.4	307.6	106.4
Accretion of discount	107.4	50.5	30.2
Net change in income taxes	(62.9)	133.4	54.7
Purchases of reserves in-place	298.3	27.8
Sales of reserves in-place		(54.1)
Changes in production rates due to timing and other	(13.2)	(32.7)	24.5
Net (decrease) increase	(80.1)	326.4	262.3
Standardized measure, end of year	$ 986.9	$ 1,067	$ 740.6