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 |