Document And Entity Information
Document And Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Feb. 28, 2023 | Jun. 30, 2022 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2022 | ||
Document Transition Report | false | ||
Entity File Number | 1-32414 | ||
Entity Registrant Name | W&T OFFSHORE, INC. | ||
Entity Incorporation, State or Country Code | TX | ||
Entity Tax Identification Number | 72-1121985 | ||
Entity Address, Address Line One | 5718 Westheimer Road, Suite 700 | ||
Entity Address, City or Town | Houston | ||
Entity Address, State or Province | TX | ||
Entity Address, Postal Zip Code | 77057-5745 | ||
City Area Code | 713 | ||
Local Phone Number | 626-8525 | ||
Title of 12(b) Security | Common Stock, par value $0.00001 | ||
Trading Symbol | WTI | ||
Security Exchange Name | NYSE | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
ICFR Auditor Attestation Flag | true | ||
Entity Shell Company | false | ||
Entity Public Float | $ 407,404,050 | ||
Auditor Name | Ernst & Young LLP | ||
Auditor Firm ID | 42 | ||
Auditor Location | Houston, Texas | ||
Entity Common Stock, Shares Outstanding | 146,460,902 | ||
Entity Central Index Key | 0001288403 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2022 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Current assets: | ||
Cash and cash equivalents | $ 461,357 | $ 245,799 |
Restricted cash | 4,417 | 4,417 |
Receivables: | ||
Oil and natural gas sales | 66,146 | 54,919 |
Joint interest, net | 14,000 | 9,745 |
Total receivables | 80,146 | 64,664 |
Prepaid expenses and other assets (Note 1) | 24,343 | 43,379 |
Total current assets | 570,263 | 358,259 |
Oil and natural gas properties and other, net (Note 1) | 735,215 | 665,252 |
Restricted deposits for asset retirement obligations | 21,483 | 16,019 |
Deferred income taxes | 57,280 | 102,505 |
Other assets (Note 1) | 47,549 | 51,172 |
Total assets | 1,431,790 | 1,193,207 |
Current liabilities: | ||
Accounts payable | 65,158 | 67,409 |
Undistributed oil and natural gas proceeds | 41,934 | 36,243 |
Advances from joint interest partners | 3,181 | 15,072 |
Asset retirement obligations | 25,359 | 56,419 |
Accrued liabilities | 74,041 | 106,140 |
Current portion of long-term debt, net | 582,249 | 42,960 |
Income tax payable | 412 | 133 |
Total current liabilities | 792,334 | 324,376 |
Long-term debt (Note 2) | ||
Principal | 114,158 | 700,359 |
Unamortized debt issuance costs | (2,970) | (12,421) |
Long-term debt, net (Note 2) | 111,188 | 687,938 |
Asset retirement obligations, less current portion | 441,071 | 368,076 |
Other liabilities (Note 1) | 59,134 | 55,389 |
Deferred income taxes | 72 | 113 |
Commitments and contingencies (Note 12) | 20,357 | 4,495 |
Shareholders' equity (deficit): | ||
Preferred stock, $0.00001 par value; 20,000 shares authorized; none issued at December 31, 2022 and December 31, 2021 | ||
Common stock, $0.00001 par value; 200,000 shares authorized; 149,002 issued and 146,133 outstanding at December 31, 2022; 145,732 issued and 142,863 outstanding at December 31, 2021 | 1 | 1 |
Additional paid-in capital | 576,588 | 552,923 |
Retained deficit | (544,788) | (775,937) |
Treasury stock, at cost; 2,869 shares at December 31, 2022 and December 31, 2021 | (24,167) | (24,167) |
Total shareholders' equity (deficit) | 7,634 | (247,180) |
Total liabilities and shareholders' equity (deficit) | $ 1,431,790 | $ 1,193,207 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parentheticals) - $ / shares shares in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Statement of Financial Position [Abstract] | ||
Preferred stock, par value (in dollars per share) | $ 0.00001 | $ 0.00001 |
Preferred stock, shares authorized (in shares) | 20,000 | 20,000 |
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 | 200,000 |
Common stock, shares issued (in shares) | 149,002 | 145,732 |
Common stock, shares outstanding (in shares) | 146,133 | 142,863 |
Treasury stock, shares (in shares) | 2,869 | 2,869 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Revenues: | |||
Total revenues | $ 920,997 | $ 558,010 | $ 346,634 |
Operating expenses: | |||
Lease operating expenses | 224,414 | 174,582 | 162,857 |
Gathering, transportation and production taxes | 35,128 | 27,919 | 20,947 |
Depreciation, depletion, and amortization | 107,122 | 90,522 | 97,763 |
Asset retirement obligations accretion | 26,508 | 22,925 | 22,521 |
General and administrative expenses | 73,747 | 52,400 | 41,745 |
Total operating expenses | 466,919 | 368,348 | 345,833 |
Operating income | 454,078 | 189,662 | 801 |
Interest expense, net | 69,441 | 70,049 | 61,463 |
Derivative loss (gain) | 85,533 | 175,313 | (23,808) |
Gain on debt transactions | 0 | 0 | (47,469) |
Other expense (income), net | 14,295 | (6,165) | 2,978 |
Income (loss) before income taxes | 284,809 | (49,535) | 7,637 |
Income tax expense (benefit) | 53,660 | (8,057) | (30,153) |
Net income (loss) | $ 231,149 | $ (41,478) | $ 37,790 |
Net income (loss) per common share: | |||
Basic | $ 1.61 | $ (0.29) | $ 0.26 |
Diluted | $ 1.59 | $ (0.29) | $ 0.26 |
Weighted average common shares outstanding: | |||
Basic | 143,143 | 142,271 | 141,622 |
Diluted | 145,090 | 142,271 | 143,277 |
Oil and Condensate [Member] | |||
Revenues: | |||
Total revenues | $ 524,274 | $ 329,557 | $ 216,419 |
Natural Gas Liquids [Member] | |||
Revenues: | |||
Total revenues | 56,964 | 44,343 | 19,101 |
Natural Gas, Production [Member] | |||
Revenues: | |||
Total revenues | 323,831 | 173,749 | 99,300 |
Product and Service, Other [Member] | |||
Revenues: | |||
Total revenues | $ 15,928 | $ 10,361 | $ 11,814 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (DEFICIT) - USD ($) $ in Thousands | Common Stock Outstanding [Member] At The Market Equity Offering [Member] | Common Stock Outstanding [Member] | Additional Paid-in Capital [Member] At The Market Equity Offering [Member] | Additional Paid-in Capital [Member] | Retained Deficit [Member] At The Market Equity Offering [Member] | Retained Deficit [Member] | Treasury Stock [Member] At The Market Equity Offering [Member] | Treasury Stock [Member] | At The Market Equity Offering [Member] | Total |
Balances (in shares) at Dec. 31, 2019 | 141,669,000 | |||||||||
Balances (in shares) at Dec. 31, 2019 | 2,869,000 | |||||||||
Balances at Dec. 31, 2019 | $ 1 | $ 547,050 | $ (772,249) | $ (24,167) | $ (249,365) | |||||
Share-based compensation | $ 0 | 3,959 | 0 | $ 0 | 3,959 | |||||
Stock Issued (in shares) | 636,000 | 0 | ||||||||
Stock Issued | $ 0 | 0 | 0 | $ 0 | 0 | |||||
RSUs surrendered for payroll taxes | 0 | (670) | 0 | 0 | (670) | |||||
Net income (loss) | $ 0 | 0 | 37,790 | $ 0 | 37,790 | |||||
Balances (in shares) at Dec. 31, 2020 | 142,305,000 | |||||||||
Balances (in shares) at Dec. 31, 2020 | 2,869,000 | |||||||||
Balances at Dec. 31, 2020 | $ 1 | 550,339 | (734,459) | $ (24,167) | (208,286) | |||||
Share-based compensation | $ 0 | 3,364 | 0 | $ 0 | 3,364 | |||||
Stock Issued (in shares) | 558,000 | 0 | ||||||||
Stock Issued | $ 0 | 0 | 0 | $ 0 | 0 | |||||
RSUs surrendered for payroll taxes | 0 | (780) | 0 | 0 | (780) | |||||
Net income (loss) | $ 0 | 0 | (41,478) | $ 0 | $ (41,478) | |||||
Balances (in shares) at Dec. 31, 2021 | 142,863,000 | |||||||||
Balances (in shares) at Dec. 31, 2021 | 2,869,000 | 2,869,000 | ||||||||
Balances at Dec. 31, 2021 | $ 1 | 552,923 | (775,937) | $ (24,167) | $ (247,180) | |||||
Share-based compensation | $ 0 | 7,922 | 0 | $ 0 | 7,922 | |||||
Stock Issued (in shares) | 2,971,000 | 299,000 | 0 | 2,971,413 | ||||||
Stock Issued | $ 0 | $ 0 | $ 16,458 | 0 | $ 0 | 0 | $ 0 | $ 0 | $ 16,458 | 0 |
RSUs surrendered for payroll taxes | 0 | (715) | 0 | 0 | (715) | |||||
Net income (loss) | $ 0 | 0 | 231,149 | $ 0 | $ 231,149 | |||||
Balances (in shares) at Dec. 31, 2022 | 146,133,000 | |||||||||
Balances (in shares) at Dec. 31, 2022 | 2,869,000 | 2,869,000 | ||||||||
Balances at Dec. 31, 2022 | $ 1 | $ 576,588 | $ (544,788) | $ (24,167) | $ 7,634 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Operating activities: | |||
Net income (loss) | $ 231,149 | $ (41,478) | $ 37,790 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion, amortization and accretion | 133,630 | 113,447 | 120,284 |
Amortization of debt items and other items | 7,551 | 6,555 | 6,834 |
Share-based compensation | 7,922 | 3,364 | 3,959 |
Derivative loss (gain) | 85,533 | 175,313 | (23,808) |
Derivative cash (payments) receipts, net | (41,880) | (81,298) | 45,196 |
Derivative cash premium payments | (46,111) | (40,484) | |
Gain on debt transactions | 0 | 0 | (47,469) |
Deferred income taxes | 45,184 | (8,189) | (30,287) |
Changes in operating assets and liabilities: | |||
Oil and natural gas receivables | (11,227) | (16,089) | 18,537 |
Joint interest receivables | (4,255) | 1,095 | 8,561 |
Prepaid expenses and other assets | 31,906 | (5,103) | 9,563 |
Income tax | 279 | (20) | 2,014 |
Asset retirement obligation settlements | (76,225) | (27,309) | (3,339) |
Cash advances from JV partners | (11,892) | 7,765 | 2,028 |
Accounts payable, accrued liabilities and other | (12,034) | 46,099 | (41,354) |
Net cash provided by operating activities | 339,530 | 133,668 | 108,509 |
Investing activities: | |||
Investment in oil and natural gas properties and equipment | (41,632) | (32,062) | (17,632) |
Changes in operating assets and liabilities associated with investing activities | (1,894) | 5,277 | (26,535) |
Acquisition of property interests | (51,474) | (661) | (2,919) |
Purchases of furniture, fixtures and other | (80) | 2 | (530) |
Net cash used in investing activities | (95,080) | (27,444) | (47,616) |
Financing activities: | |||
Borrowings on credit facility | 25,000 | ||
Repayments on credit facility | (80,000) | (50,000) | |
Purchase of 9.75% Senior Second Lien Notes | 0 | 0 | (23,930) |
Proceeds from Term Loan | 0 | 215,000 | 0 |
Repayments on Term Loan | (42,959) | (24,142) | 0 |
Debt issuance costs | (1,675) | (9,810) | 0 |
Proceeds from at-the-market equity offering | 16,998 | 0 | 0 |
Commission & fees related to at-the-market sales | (540) | 0 | 0 |
Other | (716) | (782) | (670) |
Net cash (used in) provided by financing activities | (28,892) | 100,266 | (49,600) |
Increase in cash and cash equivalents | 215,558 | 206,490 | 11,293 |
Cash and cash equivalents and restricted cash, beginning of period | 250,216 | 43,726 | 32,433 |
Cash and cash equivalents and restricted cash, end of period | $ 465,774 | $ 250,216 | $ 43,726 |
CONSOLIDATED STATEMENTS OF CA_2
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parentheticals) | Jan. 27, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Oct. 18, 2018 |
9.75% Senior Second Lien Notes Due November 2023 [Member] | |||||
Debt instrument, interest rate, stated percentage | 9.75% | 9.75% | 9.75% | 9.75% | 9.75% |
SIGNIFICANT ACCOUNTING POLICIES
SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
SIGNIFICANT ACCOUNTING POLICIES | NOTE 1 — Operations W&T Offshore, Inc. (with subsidiaries referred to herein as “W&T” or the “Company”) is an independent oil, NGL and natural gas producer with substantially all of its operations offshore in the Gulf of Mexico. The Company is active in the exploration, development and acquisition of oil and natural gas properties. Interests in fields, leases, structures and equipment are primarily owned by the Company and its 100% owned subsidiaries, W & T Energy VI, LLC, Aquasition LLC (“A-I, LLC”), and Aquasition II, LLC (“A-II LLC”), and through a proportionately consolidated interest in Monza Energy LLC (“Monza”). Basis of Presentation The Consolidated Financial Statements include the accounts of W&T Offshore, Inc., its majority-owned subsidiary and the proportionately consolidated interests in oil and gas joint ventures. All significant intercompany transactions have been eliminated. The Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and the appropriate rules and regulations of the SEC. Reclassification – Derivative loss (gain) Additionally, as of December 31, 2020, Gathering and transportation and Production taxes have been combined into one line item within “Operating income” on the Consolidated Statement of Operations in order to conform to the current period presentation. Such reclassifications had no effect on the Company’s results of operations, financial position or cash flows. 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. Cash Equivalents W&T considers all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents. Restricted Cash As of December 31, 2021, the Company cash collateralized each of the outstanding letters of credit in the aggregate amount of approximately $4.4 million. See Note 2 –Debt Revenue Recognition The Company records revenues from the sale of oil, NGLs and natural gas based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. Revenue from the sale of crude oil, NGLs and natural gas is recognized when performance obligations under the terms of the respective contracts are satisfied; this generally occurs with the delivery of oil, NGLs and natural gas to the customer. Each unit of product represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. W&T does not record imbalance receivables for those properties in which the Company has taken less than its ownership share of production. As of December 31, 2022 and 2021, $3.5 million, is included as a current liability in Undistributed oil and natural gas proceeds Concentration of Credit Risk The Company’s customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. The majority of the Company’s production is sold to customers under short-term contracts at market-based prices. The Company attempts to minimize credit risk exposure to purchasers, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guarantees when considered necessary. The following table identifies customers whose total represented 10% or more of the Company’s receipts from sales of crude oil, NGLs and natural gas: Year Ended December 31, 2022 2021 2020 Customer BP Products North America 31 % 34 % 39 % Chevron - Texaco 13 % 14 % ** Mercuria Energy America Inc. ** ** 10 % Williams Field Services ** 11 % 13 % ** Less than 10% The loss of any of the customers above would not result in a material adverse effect on the Company’s ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing Accounts Receivables and Allowance for Credit Losses Accounts Receivable are recorded at historical cost, net of an allowance for credit losses, to reflect the net amounts to be collected. Receivables consist of sales of production to customers and joint interest billings. At each reporting period, a loss methodology is used to determine the recoverability of material receivables using historical data, current market conditions and forecasts of future economic conditions to determine expected collectability. The following table describes the balance and changes to the allowance for credit losses (in thousands): 2022 2021 2020 Allowance for credit losses, beginning of period $ 10,046 $ 9,123 $ 9,898 Additional provisions for the year 3,085 2,192 417 Uncollectible accounts written off or collected (1,069) (1,269) (1,192) Allowance for credit losses, end of period $ 12,062 $ 10,046 $ 9,123 Prepaid expenses and other assets Amounts recorded in Prepaid expenses and other assets December 31, 2022 2021 Derivatives (1) (Note 10) $ 4,954 $ 21,086 Unamortized insurance/bond premiums 6,046 5,400 Prepaid deposits related to royalties 9,139 8,441 Prepayment to vendors 1,767 4,522 Prepayments to joint interest partners 1,717 2,808 Debt issue costs 687 1,065 Other 33 57 Prepaid expenses and other assets $ 24,343 $ 43,379 (1) Includes closed contracts which have not yet settled and the current portion of open contracts. Oil and Natural Gas Properties and Other, Net Oil and natural gas properties and equipment are recorded at cost using the full cost method. 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, 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 recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense. Oil and natural gas properties and equipment will include costs of unproved properties when applicable. The cost of unproved properties related to significant acquisitions are excluded from the amortization base until the Company has made an evaluation that impairment has occurred. As of December 31, 2022 and 2021, there were no unproved properties included in the Oil and natural gas properties and other, net Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas. 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 The following table provides the components of Oil and natural gas properties and other, net December 31, 2022 2021 Oil and natural gas properties and equipment $ 8,813,404 $ 8,636,408 Furniture, fixtures and other 20,915 20,844 Total property and equipment 8,834,319 8,657,252 Less: Accumulated depreciation, depletion, amortization and impairment (8,099,104) (7,992,000) Oil and natural gas properties and other, net $ 735,215 $ 665,252 Ceiling Test Write-Down Under the full-cost method of accounting, the Company’s capitalized costs are limited to a quarterly ceiling test which determines a limit on the book value of 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 recoverable or reversible in future periods. The ceiling test limit is calculated as: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related income tax effects. Estimated future net revenues used in the ceiling test for each period are based on current prices for each product, defined by the SEC as the unweighted average of first-day-of-the-month commodity prices over the prior twelve months for that period. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. The Company did not record a ceiling test write-down during 2022, 2021 or 2020. If average crude oil and natural gas prices decrease below average pricing during 2022, the Company could incur ceiling test write-downs in future periods. Oil and Natural Gas Reserve Estimates The Company utilizes SEC pricing when estimating quantities of proved reserves and the standardized measure of discounted future cash flows. Proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years, with some limited exceptions allowed. Refer to Note 19 – Supplemental Oil and Gas Disclosures Asset Retirement Obligations The Company has obligations to plug and abandon well bores, remove 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. The Company records a separate liability for the present value of ARO based on the estimated timing and amount to replace, remove or retire the associated assets, with an offsetting increase to the related oil and natural gas properties on the balance sheet. In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect estimates of these future costs from period to period. After initial recording, the liability is increased for the passage of time, with the increase being reflected as Accretion expense on the Consolidated Statements of Operations. If the Company incurs an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties. See Note 7 – Asset Retirement Contingent Decommissioning Obligations Certain counterparties in past divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. The Company accrues losses associated with decommissioning obligations when such losses are probable and reasonably estimable. When there is a range of possible outcomes, the amount accrued is the most likely outcome within the range. If no single outcome within the range is more likely than the others, the minimum amount in the range is accrued. These accruals may be adjusted as additional information becomes available. In addition, when decommissioning obligations are reasonably possible, the Company discloses an estimate for a possible loss or range of loss (or a statement that such an estimate cannot be reasonably made). See Note 18 —Contingencies Derivative Financial Instruments The Company uses commodity price derivative instruments to manage exposure to commodity price risk from sales of oil and natural gas. The Company does not enter into derivative instruments for speculative trading purposes. Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value. The Company does not designate derivatives instruments as hedging instruments, therefore, all changes in fair value are recognized in Derivative loss (gain) Note 10 – Derivative Financial Instruments Fair Value of Financial Instruments Fair value information is included in the notes to the Consolidated Financial Statements when the fair value of the financial instruments is different from the book value or when it is required by U.S. GAAP. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities approximates fair value due to the short-term, highly liquid nature of these instruments. See Note 3 – Fair Value Measurements Income Taxes The Company’s provision for income taxes includes U.S. state and federal taxes. Income taxes are recorded in accordance with accounting for income taxes under U.S. GAAP which results in the recognition of deferred tax assets and liabilities determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. The effects of changes in tax rates and laws on deferred tax balances are recognized in the period in which the new legislation is enacted. A valuation allowance is established on deferred tax assets when it is more likely than not that some portion or all of the related tax benefits will not be realized. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. Such uncertain tax positions are recognized in the Consolidated Financial Statements when it is determined that the relevant tax authority would more likely than not sustain the position following an audit. Any interest and penalties related to uncertain tax positions are recorded in Income tax expense Note 13 – Income Taxes Other Assets (long-term) The major categories recorded in Other assets December 31, 2022 2021 Right-of-Use assets $ 10,364 $ 10,602 Investment in White Cap, LLC 2,453 2,533 Proportional consolidation of Monza (Note 5) 9,321 2,511 Derivatives (1) (Note 10) 23,236 34,435 Other 2,175 1,091 Total other assets (long-term) $ 47,549 $ 51,172 (1) Includes open contracts. Accrued Liabilities The major categories recorded in Accrued liabilities December 31, 2022 2021 Accrued interest $ 8,967 $ 10,154 Accrued salaries/payroll taxes/benefits 15,097 9,617 Litigation accruals 396 646 Lease liability 1,628 1,115 Derivatives (1) 46,595 81,456 Other 1,358 3,152 Total accrued liabilities $ 74,041 $ 106,140 (1) Includes closed contracts which have not yet settled. Paycheck Protection Program (“PPP”) On April 15, 2020, the Company received $8.4 million under the U.S. Small Business Administration (“SBA”) PPP. The Company’s application to the SBA requesting that the PPP funds received be applied to specific covered and non-covered payroll costs was accepted and approved for full forgiveness on June 11, 2021. As there is no definitive guidance under U.S. GAAP, the Company has applied the guidance under IAS 20 and accounted for the PPP as a government grant. Under IAS 20, a government grant is recognized when there is reasonable assurance that the Company has complied with the provisions of the grant. Accordingly, the funds received were recorded as a reduction to General and administrative expenses Debt Issuance Costs Debt issuance costs associated with the Credit Agreement are amortized using the straight-line method over the scheduled maturity of the debt. The unamortized debt issue costs associated with the Credit Agreement are reported within Prepaid expenses and other assets Debt issuance costs associated with the 9.75% Senior Second Lien Notes and the Term Loan are amortized using the effective interest method over the scheduled maturity of the debt. The unamortized debt issuance costs associated with the current debt instruments are reported as a reduction to the carrying value of Current portion of long-term debt, net Long-term debt net Note 2 –Debt Gain on Debt Transactions During 2020, the Company acquired $72.5 million in principal of the outstanding 9.75% Senior Second Lien Notes for $23.9 million and recorded a non-cash gain on purchase of debt of $47.5 million. Other Liabilities (long-term) The major categories recorded in Other liabilities December 31, 2022 2021 Dispute related to royalty deductions $ 4,937 $ 5,177 Derivatives (Note 10) 43,061 37,989 Lease liability 10,527 11,227 Other 609 996 Total other liabilities (long-term) $ 59,134 $ 55,389 At-the-Market Equity Offering On March 18, 2022, the Company filed a prospectus supplement related to the issuance and sale of up to $100,000,000 of shares of common stock under the Company’s ATM Program. The designated sales agent is entitled to a placement fee of up to 3.0% of the gross sales price per share sold. During the year ended December 31, 2022, the Company sold an aggregate of 2,971,413 shares for an average price of $5.72 per share in connection with the ATM Offering and received proceeds, net of commissions and expenses, of $16.5 million. 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. The fair value for equity instruments subject to market-based performance measures was determined using a Monte Carlo valuation model with estimates made as of the grant date. Share-based compensation expense is recognized 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 expected to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 11 – Share-Based Awards and Cash-Based Awards Employee Retention Credit Under the Consolidated Appropriations Act, 2021 passed by the United States Congress and signed by the President on December 27, 2020, provisions of the Coronavirus Aid, Relief and Economic Security Act were extended and modified making the Company eligible for a refundable employee retention credit subject to meeting certain criteria. The Company recognized a $2.1 million employee retention credit during the year ended December 31, 2021. The funds received were recorded as a reduction to General and administrative on the Consolidated Statement of Operations during the year ended December 31, 2021. No such credit was recognized during the years ended December 31, 2022 or 2020. Other Expense (Income), Net For the year ended December 31, 2022, Other expense (income), net For the year ended December 31, 2021, the amount primarily consists of income related to the release restrictions on the Black Elk Escrow fund, partially offset by expenses related to the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program, offset by contingent decommissioning obligation recognized during the year ended December 31, 2021. For the year ended December 31, 2020, the amount primarily consists of expenses related to the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program. See Note 9 – Restricted Deposits for ARO and Note 18 —Contingencies for additional information . 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-class method when the effect is dilutive. See Note 14 – Earnings Per Share |
DEBT
DEBT | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
Debt [Text Block] | NOTE 2 — The components of debt are presented in the following tables (in thousands): December 31, 2022 2021 Term Loan: Principal $ 147,899 $ 190,859 Unamortized debt issuance costs (4,592) (7,545) Total Term Loan 143,307 183,314 Credit Agreement borrowings: — — 9.75% Senior Second Lien Notes: Principal 552,460 552,460 Unamortized debt issuance costs (2,330) (4,876) Total 9.75% Senior Second Lien Notes 550,130 547,584 Less current portion, net (582,249) (42,960) Total long-term debt, net $ 111,188 $ 687,938 Aggregate annual maturities of principal amounts recorded as of December 31, 2022 are as follows (in millions): 2023 $ 586.2 2024 30.1 2025 27.6 2026 25.4 2027 22.9 Thereafter 8.2 Total $ 700.4 Current portion of Long-Term Debt As of December 31, 2022, the current portion of long-term debt of $582.2 million represented net principal payments due within one year on the Term Loan and 9.75% Senior Second Lien Notes. See Note 20 – Subsequent Events Term Loan (Subsidiary Credit Agreement) On May 19, 2021, A-I LLC and A-II LLC, subsidiaries of W&T Offshore, Inc., entered into a credit agreement (the “Subsidiary Credit Agreement”) providing for a term loan (the “Term Loan”) in an aggregate principal amount equal to $215.0 million. The Term Loan requires quarterly amortization payments which commenced on September 30, 2021. The Term Loan bears interest at a fixed rate of 7.0% per annum and will mature on May 19, 2028. At that time, in exchange for the net cash proceeds received by the Subsidiary Borrowers from the Term Loan, the Company assigned to (a) A-I LLC all of its interests in certain oil and gas leasehold interests and associated wells and units located in State of Alabama waters and U.S. federal waters in the offshore Gulf of Mexico, Mobile Bay region (such assets, the “Mobile Bay Properties”) and (b) A-II LLC its interest in certain gathering and processing assets located (i) in State of Alabama waters and U.S. federal waters in the offshore Gulf of Mexico, Mobile Bay region and (ii) onshore near Mobile, Alabama, including offshore gathering pipelines, an onshore crude oil treating and sweetening facility, an onshore gathering pipeline, and associated assets (such assets, the “Midstream Assets”). During 2021, a portion of the proceeds to the Company was used to repay the $48.0 million outstanding balance on its reserve-based lending facility under the Credit Agreement. The Term Loan is non-recourse to the Company and any subsidiaries other than the Subsidiary Borrowers and the subsidiary that owns the equity in the Subsidiary Borrowers, and is secured by the first lien security interests in the equity of the Subsidiary Borrowers and a first lien mortgage security interest and mortgages on certain assets of the Subsidiary Borrowers (the Mobile Bay Properties, defined below). See Note 4 – Subsidiary Borrowers During the years ended December 31, 2022 and 2021, the Company repaid $43.0 million and $24.1 million of principal outstanding, respectively. As of December 31, 2022 and 2021, the Company had $147.9 million and $190.9 million in principal amount of the Term Loan, respectively. Credit Agreement On November 2, 2021, the Company entered into the Ninth Amendment to the Sixth Amended and Restated Credit Agreement (the “Ninth Amendment”), which established a short-term $100.0 million first priority lien secured revolving facility with borrowings limited to a borrowing base of $50.0 million (the “Credit Agreement”) provided by Calculus Lending, LLC, (“Calculus”) a company affiliated with, and controlled by W&T’s Chairman and Chief Executive Officer, Tracy W. Krohn, as sole lender under the Calculus Lending facility. Additionally, as of November 2, 2021, the Company cash collateralized each of the outstanding letters of credit in the aggregate amount of $4.4 million. Alter Domus (US) LLC was appointed to replace Toronto Dominion (Texas) LLC as administrative agent under the Credit Agreement. On March 8, 2022, the Company entered into the Tenth Amendment to the Sixth Amended and Restated Credit Agreement (the “Tenth Amendment”), which extended the maturity date and Calculus’ commitment to January 3, 2023. A committee of the independent members of the Board of Directors reviewed and approved these amendments given the CEO’s affiliation with Calculus. See Note 17 – Related Parties for additional information. As a result of the Ninth Amendment, Tenth Amendment and Eleventh Amendment and related assignments and agreements, the · The borrowing base is $50.0 million. · The Calculus Lending facility commitment will expire and final maturity of any and all outstanding loans is January 3, 2024. Outstanding borrowings will accrue interest at SOFR plus 6.0% per annum. The commitment fee for the unused portion of available borrowing amounts will be 3.0% per annum; · The Company’s ratio of First Lien Debt (as such term is defined in the Credit Agreement) outstanding under the Credit Agreement on the last day of the most recent quarter to EBITDAX (as such term is defined in the Credit Agreement) for the trailing four quarters must not be greater than 2.50 to 1.00 on the last day of the fiscal quarter ended March 31, 2022 and on the last day of each fiscal quarter thereafter; · The Company ’ · The ratio of the Company and its restricted subsidiaries’ consolidated current assets to consolidated current liabilities (subject in each case to certain exceptions and adjustments as set forth in the Credit Agreement) at the last day of any fiscal quarter must be greater than or equal to 1.00 to 1.00. ● As of the last day of any fiscal quarter commencing with the fiscal quarter ended March 31, 2022, the Company and its restricted subsidiaries on a consolidated basis must pass a “Stress Test” consisting of an analysis conducted by the lender in good faith and in consultation with the Company based upon the latest engineering report furnished to lender, which analysis is designed to determine whether the future net revenues expected to accrue to the Company’s and its guarantor subsidiaries’ interest (and the interest of certain joint ventures) in the oil and gas properties included in the properties used to determine the latest borrowing base during half of the remaining expected economic lives of such properties are sufficient to satisfy the aggregate first lien indebtedness of the Company and its restricted subsidiaries in accordance with the terms of such indebtedness assuming the Calculus Lending facility is 100% funded or fully utilized. ● Certain related party transactions are required to meet certain arm’s length criteria; except in each case as specifically permitted or excluded from the covenant under the Credit Agreement. Availability under the Credit Agreement is subject to redetermination of the borrowing base that may be requested at the discretion of either the lender or the Company. The borrowing base is calculated by the lender based on their evaluation of proved reserves and their own internal criteria. Any redetermination by the lender to change the borrowing base will result in a similar change in the availability under the Credit Agreement. The Credit Agreement is secured by a first priority lien on substantially all of the Company’s oil and natural gas properties and personal property, excluding those assets of the Subsidiary Borrowers, which liens were released (as described in Note 4 – Subsidiary Borrowers As of December 31, 2022 and 2021, there were no borrowings outstanding or incurred under the Credit Agreement. As of December 31, 2022 and 2021, the Company had $4.4 million, outstanding in letters of credit which are cash collateralized. 9.75% Senior Second Lien Notes Due 2023 On October 18, 2018, the Company issued $625.0 million of 9.75% Senior Second Lien Notes due 2023 (the “9.75% Senior Second Lien Notes”), which were issued at par with an interest rate of 9.75% per annum that matures on November 1, 2023, and are governed under the terms of the Indenture of the 9.75% Senior Second Lien Notes entered into by and among the Company, the Guarantors, and Wilmington Trust, National Association, as trustee. The estimated annual effective interest rate on the 9.75% Senior Second Lien Notes was 10.3%, which includes debt issuance costs. Interest on the 9.75% Senior Second Lien Notes is payable in arrears on May 1 and November 1 of each year. During the year ended December 31, 2020 , Subsequent to December 31, 2022, the Company redeemed all of the outstanding 9.75% Senior Second Lien Notes using cash on hand and the net proceeds from the offering of the 11.75% Senior Second Lien Notes. See Note 20 – Subsequent Events Covenants As of December 31, 2022 and for all presented measurement periods, the Company was in compliance with all applicable covenants of the Credit Agreement and 9.75% Senior Second Lien Notes. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
Fair Value Disclosures [Text Block] | NOTE 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 categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy: ● Level 1 – quoted prices in active markets for identical assets or liabilities. ● Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs). ● Level 3 – unobservable inputs that reflect the Company’s expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability. Derivative Financial Instruments The Company measures the fair value of derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used for the fair value measurement of derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity future prices. Derivative financial instruments are reported in the Consolidated Balance Sheets using fair value. See Note 10 – Derivative Financial Instruments The following table presents the fair value of the Company’s derivative financial instruments (in thousands): December 31, 2022 2021 Assets: Derivative instruments - current $ 4,954 $ 21,086 Derivative instruments - long-term 23,236 34,435 Liabilities: Derivative instruments - current 46,595 81,456 Derivative instruments - long-term 43,061 37,989 Debt Instruments The fair value of the Term Loan was measured using a discounted cash flows model and current market rates. The fair value of the 9.75% Senior Second Lien Notes was measured using quoted prices, although the market is not a highly liquid market. The fair value of debt was classified as Level 2 within the valuation hierarchy. Note 2 – Debt The following table presents the net value and fair value of the Company’s debt (in thousands): December 31, 2022 December 31, 2021 Net Value Fair Value Net Value Fair Value Liabilities: Term Loan $ 143,307 $ 139,056 $ 183,314 $ 190,579 9.75% Senior Second Lien Notes 550,130 544,902 547,584 527,715 Total $ 693,437 $ 683,958 $ 730,898 $ 718,294 |
SUBSIDIARY BORROWERS
SUBSIDIARY BORROWERS | 12 Months Ended |
Dec. 31, 2022 | |
SUBSIDIARY BORROWERS | |
SUBSIDIARY BORROWERS | NOTE — On May 19, 2021, the Subsidiary Borrowers entered into the Subsidiary Credit Agreement providing for the Term Loan in an aggregate principal amount equal to $215.0 million. Proceeds of the Term Loan were used by the Borrowers to (i) fund the acquisition of the Mobile Bay Properties and the Midstream Assets from the Company and (ii) pay fees, commissions and expenses in connection with the transactions contemplated by the Subsidiary Credit Agreement and the other related loan documents, including to enter into certain swap and put derivative contracts described in more detail under Note 10 Derivative Financial Instruments As part of the transaction, the Subsidiary Borrowers entered into a management services agreement (the “Services Agreement”) with the Company, pursuant to which the Company will provide (a) certain operational and management services for i) the Mobile Bay Properties and ii) the Midstream Assets and (b) certain corporate, general and administrative services for A-I LLC and A-II LLC (collectively in this capacity, the “Services Recipient”). Under the Services Agreement, the Company will indemnify the Services Recipient with respect to claims, losses or liabilities incurred by the Services Agreement Parties that relate to personal injury or death or property damage of the Company, in each case, arising out of performance of the Services Agreement, except to the extent of the gross negligence or willful misconduct of the Services Recipient. The Services Recipient will indemnify the Company with respect to claims, losses or liabilities incurred by the Company that relate to personal injury or death of the Services Recipient or property damage of the Services Recipient, in each case, arising out of performance of the Services Agreement, except to the extent of the gross negligence or willful misconduct of the Company. The Services Agreement will terminate upon the earlier of (a) termination of the Subsidiary Credit Agreement and payment and satisfaction of all obligations thereunder or (b) the exercise of certain remedies by the secured parties under the Subsidiary Credit Agreement and the realization by such secured parties upon any of the collateral under the Subsidiary Credit Agreement. The Subsidiary Borrowers are wholly-owned subsidiaries of the Company; however, the assets of the Subsidiary Borrowers are not available to satisfy the debt or contractual obligations of any other entities, including debt securities or other contractual obligations of the Company, and the Subsidiary Borrowers do not bear any liability for the indebtedness or other contractual obligations of any other entities, and vice versa. During the year ended December 31, 2022, the Subsidiary Borrowers paid cash distributions to W&T of $30.2 million. Consolidation and Carrying Amounts The following table presents the amounts recorded by W&T on the Consolidated Balance Sheets related to the consolidation of the Subsidiary Borrowers and the subsidiary that owns the equity of the Subsidiary Borrowers (in thousands): December 31, 2022 2021 Assets: Cash and cash equivalents $ 21,764 $ 38,937 Receivables: Oil and natural gas sales 37,344 34,420 Joint interest, net (5,760) (10,856) Prepaid expenses and other assets 417 356 Oil and natural gas properties and other, net 280,649 272,747 Other assets 8,473 (19,903) Liabilities: Accounts payable 27,387 29,678 Undistributed oil and natural gas proceeds 7,930 3,144 Accrued liabilities 45,102 29,937 Current portion of long-term debt 32,119 42,960 Long-term debt, net 111,188 140,353 Asset retirement obligations 61,138 54,515 Other liabilities 47,398 42,615 The following table presents the amounts recorded by W&T in the (i The period from Year Ended May 19, 2021 to December 31, 2022 December 31, 2021 Total revenues $ 268,573 $ 119,550 Total operating expenses 73,990 32,735 Interest expense, net 14,721 9,782 Derivative loss 141,736 104,533 |
JOINT VENTURE DRILLING PROGRAM
JOINT VENTURE DRILLING PROGRAM | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
Joint Venture Drilling Program [Text Block] | NOTE — In March 2018, W&T and two other initial members formed and initially funded Monza, which jointly participates with the Company in the exploration, drilling and development of certain drilling projects (the “Joint Venture Drilling Program”) in the Gulf of Mexico. Subsequent to the initial closing, additional investors joined as members of Monza during 2018 and total commitments by all members, including W&T’s commitment outside of Monza, were $361.4 million. W&T contributed 88.94% of its working interest in certain identified undeveloped drilling projects to Monza and retained 11.06% of its working interest. The Joint Venture Drilling Program is structured so that the Company initially receives an aggregate of 30.0% of the revenues less expenses, through both the Company’s direct ownership of its working interest in the projects and the Company’s indirect interest through its interest in Monza, for contributing 20.0% of the estimated total well costs plus associated leases and providing access to available infrastructure at agreed-upon rates. Any exceptions to this structure are approved by the Monza board. The members of Monza are made up of third-party investors, W&T and an entity owned and controlled by Tracy W. Krohn, the Company’s Chairman and Chief Executive Officer. The entity affiliated with the Company’s CEO invested as a minority investor on the same terms and conditions as the third-party investors, and its investment is limited to 4.5% of total invested capital within Monza. The entity affiliated with Mr. Krohn has made a capital commitment to Monza of $14.5 million. 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 available to pay creditors of the Company and its affiliates. Through December 31, 2022, ten wells have been completed of which six were producing as of December 31, 2022. W&T is the operator for eight of the ten wells completed through December 31, 2022. Since inception through December 31, 2022, members of Monza made partner capital contributions, including W&T’s contributions of working interest in the drilling projects, to Monza totaling $302.4 million and received cash distributions totaling $166.0 million. Since inception through December 31, 2022, W&T made total capital contributions, including the contributions of working interest in the drilling projects, to Monza totaling $68.2 million and received cash distributions totaling $35.7 million. Consolidation and Carrying Amounts W&T’s interest in Monza is considered to be a variable interest that is proportionally consolidated. Through December 31, 2022, there have been no events or changes that would cause a redetermination of the variable interest status. W&T does not fully consolidate Monza because the Company is not considered the primary beneficiary of Monza. The following table presents the amounts recorded by W&T on the Consolidated Balance Sheets related to the consolidation of the proportional interest in Monza’s operations (in thousands): December 31, 2022 2021 Working capital $ 2,515 $ 4,648 Oil and natural gas properties and other, net 37,260 45,510 Asset retirement obligations 467 301 Other assets 11,571 2,511 As required, W&T may call on Monza to provide cash to fund its portion of certain Joint Venture Drilling Program projects in advance of capital expenditure spending, and the unused balances as of December 31, 2022 and December 31, 2021 were $2.9 million and $14.8 million, respectively, which are included in the Consolidated Balance Sheets in Advances from joint interest partners. The following table presents the amounts recorded by W&T in the (i f Year Ended December 31, 2022 2021 Total revenues $ 28,803 $ 12,716 Total operating expenses 13,523 10,044 Derivative loss — 2,096 Interest income 42 — |
ACQUISITIONS
ACQUISITIONS | 12 Months Ended |
Dec. 31, 2022 | |
Asset Acquisition [Abstract] | |
ACQUISITIONS | NOTE — On January 5, 2022, the Company entered into a purchase and sale agreement with ANKOR E&P Holdings Corporation and KOA Energy LP to acquire their interests in and operatorship of certain oil and natural gas producing properties in federal shallow waters in the Gulf of Mexico at Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields for $47.0 million. The transaction closed on February 1, 2022, and after normal and customary post-effective date adjustments (including net operating cash flow attributable to the properties from the effective date of July 1, 2021 to the close date), cash consideration of $34.0 million was paid to the sellers. The transaction was funded using cash on hand. The Company also assumed the related AROs associated with these assets. Additionally, on April 1, 2022, the Company entered into a purchase and sale agreement with a private seller to acquire the remaining working interests in certain oil and natural gas producing properties in federal shallow waters of the Gulf of Mexico at the Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields. The transaction had an effective date and closing date of April 1, 2022. The Company determined that the assets acquired did not meet the definition of a business; therefore, the transactions were accounted for as asset acquisitions in accordance with ASC 805. An acquisition qualifying as an asset acquisition requires, among other items, that the cost of the assets acquired and liabilities assumed to be recognized on the Consolidated Balance Sheet by allocating the asset cost on a relative fair value basis. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized as a component of the assets acquired. The amounts recorded on the Consolidated Balance Sheet for the purchase price allocation and liabilities assumed related to the acquisitions described above on February 1, 2022, and April 1, 2022, are presented in the following tables, respectively (in thousands): February 1, 2022 Oil and natural gas properties and other, net $ 54,299 Restricted deposits for asset retirement obligations 6,196 Asset retirement obligations (26,493) Allocated purchase price $ 34,002 April 1, 2022 Oil and natural gas properties and other, net $ 22,632 Restricted deposits for asset retirement obligations 1,549 Asset retirement obligations (6,709) Allocated purchase price $ 17,472 |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
ASSET RETIREMENT OBLIGATIONS | NOTE — 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 the Company’s 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 changes in liability are included in the Consolidated Balance Sheet in current and long-term liabilities, and the changes in that liability were as follows (in thousands): Year Ended December 31, 2022 2021 Asset retirement obligations, beginning of period $ 424,495 $ 392,704 Liabilities settled (76,225) (27,309) Accretion expense 26,508 22,925 Liabilities acquired 33,202 454 Liabilities incurred 138 — Revisions of estimated liabilities 58,312 35,721 Asset retirement obligations, end of period 466,430 424,495 Less: Current portion (25,359) (56,419) Long-term $ 441,071 $ 368,076 |
LEASES
LEASES | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
LEASES | NOTE — The Company has operating leases consisting of office leases, a land lease and various pipeline right-of-way contracts. For these contracts, a right-of-use (“ROU”) asset and lease liability was established based on the Company’s assumptions of the term, inflation rates and incremental borrowing rates. At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. The amounts disclosed herein primarily represent costs associated with properties operated by the Company that are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners where applicable. The Company’s share of these costs is included in property and equipment, lease operating expense or general and administrative expense, as applicable. The components of lease costs were as follows (in thousands): December 31, 2022 2021 2020 Operating lease costs, excluding short-term leases $ 1,579 $ 1,743 $ 3,060 Short-term lease cost (1) 2,957 5,926 1,633 Variable lease cost (2) 647 — — Total lease cost $ 5,183 $ 7,669 $ 4,693 (1) Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a right-of-use asset and lease liability on the balance sheet. The majority of such costs are recorded within Oil and natural gas properties and other, net , on the Consolidated Balance Sheet. (2) Variable lease costs primarily represent differences between minimum lease payment obligations and actual operating charges incurred by the Company related to long-term operating leases. The present value of the fixed lease payments recorded as the Company’s right-of-use asset and liability, adjusted for initial direct costs and incentives are as follows (in thousands): December 31, 2022 2021 ROU assets $ 10,364 $ 10,602 Lease liability: Accrued liabilities $ 1,628 $ 1,115 Other liabilities 10,527 11,227 Total lease liability $ 12,155 $ 12,342 The table below presents the weighted average remaining lease term and discount rate related to leases (in thousands): December 31, 2022 2021 2020 Weighted average remaining lease term: 13.1 years 14.1 years 14.8 years Weighted average discount rate: 10.1 % 10.1 % 10.2 % The table below presents the supplemental cash flow information related to leases (in thousands): December 31, 2022 2021 2020 Operating cash outflow from operating leases $ 1,224 $ 425 $ 1,825 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ — $ 5,142 Undiscounted future minimum payments as of December 31, 2022 are as follows (in thousands): 2023 $ 1,628 2024 2,026 2025 1,514 2026 1,545 2027 1,576 Thereafter 14,242 Total lease payments 22,531 Present value adjustment (10,376) Total $ 12,155 |
RESTRICTED DEPOSITS FOR ARO
RESTRICTED DEPOSITS FOR ARO | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
RESTRICTED DEPOSITS FOR ARO | NOTE 9 — Restricted deposits as of December 31, 2022 and 2021 consisted of funds escrowed for collateral related to the future plugging and abandonment obligations of certain oil and natural gas properties as follows: December 31, 2022 2021 Main Pass 283/Viosca Knoll 734 (1) $ 13,684 $ 13,663 Eugene Island 205/89 (2) — 1,880 South Marsh Island 73 (3) 7,753 — Other 47 477 (1) In connection with a prior period acquisition of the Main Pass 283 and Viosca Knoll 734 fields, the Company received funds from the previous operator to cover future asset retirement obligations for those fields. The Company is not obligated to contribute additional amounts to these escrowed accounts. (2) In connection with a prior period acquisition of the Eugene Island 205 and 89 fields, the Company received funds from the previous owner to cover future asset retirement obligations for those fields. As of December 31, 2022, the Company has performed the related plugging and abandonment work at both fields. (3) During the first and second quarter of 2022, the Company acquired the South Marsh Island 73 field. As part of the transaction, the Company received a total of $7.8 million from the previous owners to cover future asset retirement obligations. The Company is not obligated to contribute additional amounts to this escrowed account. See Note 6 - Acquisitions for additional information. Black Elk Escrow – Other (income) expense |
DERIVATIVE FINANCIAL INSTRUMENT
DERIVATIVE FINANCIAL INSTRUMENTS | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
DERIVATIVE FINANCIAL INSTRUMENTS | NOTE — W&T’s market risk exposure relates primarily to commodity prices. The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production through the use of oil and natural gas swaps, costless collars, sold calls and purchased puts. W&T has elected not to designate commodity derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts, and changes in the unrealized fair value, recorded as Derivative loss (gain) on the Consolidated Statements of Operations in each period presented. Net cash provided by operating activities The crude oil contracts are based on WTI crude oil prices and the natural gas contracts are based off the Henry Hub prices, both of which are quoted off NYMEX. The following table reflects the contracted volumes and weighted average prices under the terms of the Company’s open derivative contracts as of December 31, 2022: Average Instrument Daily Total Weighted Weighted Weighted Period Type Volumes Volumes Strike Price Put Price Call Price Natural Gas - Henry Hub (NYMEX) (MMbtu) (MMbtu) ($/MMbtu) ($/MMbtu) ($/MMbtu) Jan 2023 - Dec 2023 calls 70,000 25,550,000 $ — $ — $ 7.50 Jan 2024 - Dec 2024 calls 65,000 23,790,000 $ — $ — $ 6.13 Jan 2025 - Mar 2025 calls 62,000 5,580,000 $ — $ — $ 5.50 Jan 2023 - Dec 2023 (1) swaps 72,329 26,400,000 $ 2.48 $ — $ — Jan 2024 - Dec 2024 (1) swaps 65,574 24,000,000 $ 2.46 $ — $ — Jan 2025 - Mar 2025 (1) swaps 63,333 5,700,000 $ 2.72 $ — $ — Apr 2025 - Dec 2025 (1) puts 62,182 17,100,000 $ — $ 2.27 $ — Jan 2026 - Dec 2026 (1) puts 55,890 20,400,000 $ — $ 2.35 $ — Jan 2027 - Dec 2027 (1) puts 52,603 19,200,000 $ — $ 2.37 $ — Jan 2028 - Apr 2028 (1) puts 49,587 6,000,000 $ — $ 2.50 $ — (1) These contracts were entered into by the Company’s wholly owned subsidiary, A-I LLC (see Note 4 – Subsidiary Borrowers). Financial Statement Presentation The following fair value of derivative financial instruments amounts were recorded in the Consolidated Balance Sheets (in thousands): December 31, 2022 2021 Prepaid expenses and other current assets $ 4,954 $ 21,086 Other assets (long-term) 23,236 34,435 Accrued liabilities 46,595 81,456 Other liabilities (long-term) 43,061 37,989 Although the Company has master netting arrangements with its counterparties, t Changes in the fair value and settlements of contracts are recorded on the Consolidated Statements of Operations as Derivative loss (gain) Year Ended December 31, 2022 2021 2020 Realized loss (gain) (1) $ 125,089 $ 95,187 $ (33,415) Unrealized (gain) loss (39,556) 80,126 9,607 Derivative loss (gain) 85,533 175,313 (23,808) (1) The year ended December 31, 2022 includes the effects of the $138.0 million realized gain related to the monetization of certain natural gas call contracts through restructuring of strike prices which occurred in June 2022. Cash payments on commodity derivative contract settlements, net, are included within Net cash provided by operating activities Year Ended December 31, 2022 2021 2020 Derivative loss (gain) $ 85,533 $ 175,313 $ (23,808) Derivative cash (payments) receipts, net (1) (41,880) (81,298) 45,196 Derivative cash premium payments (46,111) (40,484) — (1) The year ended December 31, 2022 includes $105.3 million of net cash receipts related to the monetization of certain natural gas call contracts through restructuring of strike prices. |
SHARE-BASED AWARDS AND CASH BAS
SHARE-BASED AWARDS AND CASH BASED AWARDS | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
Share-based Payment Arrangement [Text Block] | NOTE 11 — Incentive Compensation Plan The W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (as amended, from time to time, the “Plan”) was approved by the Company’s 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 subject to section 16 of the Exchange Act (as applicable, the “Compensation Committee”). Pursuant to the terms of the Plan, the Compensation Committee establishes the vesting or performance criteria applicable to the award and may use a single measure or combination of business measures as described in the Plan. Also, individual goals may be established by the Compensation Committee. Performance awards may be granted in the form of stock options, stock appreciation rights, restricted stock, restricted stock units (“RSUs”), bonus stock, dividend equivalents, or other awards related to stock, and awards may be paid in cash, stock, or any combination of cash and stock, as determined by the Compensation Committee. The performance awards granted under the Plan can be measured over a performance period of up to 10 years and annual incentive awards (a type of performance award) will generally be paid within 90 days following the applicable year end. Restricted Stock Units During 2022 and 2021, the Company granted RSUs under the Plan to certain of its employees. There were no RSUs granted in 2020. RSUs are a long-term compensation component, granted to certain employees. As of December 31, 2022, there were 9,595,681 shares of common stock available for issuance in satisfaction of awards under the Plan. The shares available for issuance are reduced on a one-for-one basis when RSUs are settled in shares of common stock, net of withholding tax through the withholding of shares. The Company has the option following vesting to settle RSUs in stock or cash, or a combination of stock and cash. During 2022, 2021 and 2020, only shares of common stock were used to settle all vested RSUs. The Company expects to settle RSUs that vest in the future using shares of common stock. RSUs currently outstanding relate to the 2022 and 2021 grants. RSUs granted to employees are a long-term compensation component, that vest ratably over an approximate three year period subject to service conditions through each vesting date. See the table below for anticipated vesting by year of outstanding RSU grants. Compensation cost for share-based payments to employees is recognized ratably 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 using the Company’s closing price on the grant date. Forfeitures are estimated during the vesting period, resulting in the recognition of compensation cost only for those awards that are expected to actually vest. Estimated forfeitures are adjusted to actual forfeitures when the award vests. All RSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period. A summary of activity related to RSUs is as follows: 2022 2021 2020 Weighted Weighted Weighted Average Average Average Restricted Grant Date Fair Restricted Grant Date Fair Restricted Grant Date Fair Stock Units Value Per Unit Stock Units Value Per Unit Stock Units Value Per Unit Nonvested, beginning of period 698,465 $ 4.71 763,688 $ 4.51 1,614,722 $ 5.73 Granted 984,394 6.24 710,441 4.71 — — Vested (1) (387,285) 5.20 (731,095) 4.51 (787,203) 6.90 Forfeited (74,113) 5.24 (44,569) 4.50 (63,831) 5.80 Nonvested, end of period 1,221,461 5.76 698,465 $ 4.71 763,688 $ 4.51 (1) During May and June 2022, approximately 22,000 outstanding RSUs awarded in 2021 to two individuals retiring from their employment with the Company were modified to fully vest upon their retirement, which occurred during May and June 2022, respectively. The remaining unrecognized grant date fair value of the original RSUs was recognized over the requisite period. The incremental cost due to the modification was not materially different from the grant date fair value. RSUs fair value at grant date RSUs fair value at vested date For the outstanding RSUs issued to the eligible employees as of December 31, 2022, vesting is expected to occur as follows (subject to forfeitures): Restricted Shares 2023 470,750 2024 470,699 2025 280,012 Total 1,221,461 Performance Share Units (“PSUs”) During 2022 and 2021, the Company granted PSUs under the Plan to certain of its employees. There were no PSUs granted in 2020. PSUs are a long-term compensation component, granted to certain employees. The PSUs are RSU awards granted subject to performance criteria. The performance criteria relates to the evaluation of the Company’s total shareholder return (“TSR”) ranking against peer companies’ TSR for the applicable performance period and subject to service conditions through the vesting date. TSR is determined based on the change in the entity’s stock price plus dividends and distributions for the applicable performance period. PSUs currently outstanding relate to 2022 and 2021 grants. PSUs granted to employees in 2022 are subject to an approximate three year performance period and service conditions through the vesting date. The performance period for the 2022 PSU grants ends on December 31, 2024 with vesting occurring on January 1, 2025. PSUs granted to employees in 2021 were subject to an approximate one year performance period which ended on December 31, 2021. Subsequent to the performance period, the PSUs continue to be subject to service-based criteria until vesting occurring on October 1, 2023. A summary of activity related to PSUs is as follows: 2022 2021 Weighted Weighted Average Average Performance Grant Date Fair Performance Grant Date Fair Share Units Value Per Unit Share Units Value Per Unit Nonvested, beginning of period 196,918 $ 5.55 — $ — Granted 1,384,214 10.29 393,073 5.56 Vested (1) (15,264) 5.57 — — Forfeited (63,629) 8.84 (196,155) 5.57 Nonvested, end of period 1,502,239 9.78 196,918 $ 5.55 (1) During May and June 2022, approximately 12,000 outstanding PSUs awarded in 2021 to two individuals retiring from their employment with the Company were modified to fully vest upon their retirement, which occurred during May and June 2022, respectively. The remaining unrecognized grant date fair value of the original PSUs was recognized over the requisite period. The incremental cost due to the modification was not materially different from the grant date fair value. Compensation cost for share-based payments to employees is recognized ratably 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. All PSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period. The grant date fair value of the PSUs was determined through the use of the Monte Carlo simulation method. This method requires the use of highly subjective assumptions. Key assumptions in the method include the price and the expected volatility of the Company’s stock and its self-determined Peer Group companies’ stock, risk free rate of return and cross-correlations between the Company and its Peer Group companies. The valuation model assumes dividends, if any, are immediately reinvested. The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted: 2022 Grant Date 2021 Grant Date May 26, 2022 June 28, 2021 Expected term for performance period (in years) 2.6 0.5 Expected volatility 84.4 % 67.9 % Risk-free interest rate 2.5 % 0.1 % Fair value (in thousands) $ 14,240 $ 1,852 PSUs fair value at vested date For the outstanding PSUs issued to the eligible employees as of December 31, 2022, vesting is expected to occur as follows (subject to forfeitures): Performance Shares 2023 161,418 2024 — 2025 1,340,821 Total 1,502,239 Share-Based Awards: Restricted Stock Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2022, 2021 and 2020 to the Company’s non-employee directors as a component of their compensation arrangement. Vesting occurs upon completion of the one year vesting period. The holders of Restricted Shares generally have the same rights as a shareholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. Restricted Shares are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restriction period. As of December 31, 2022, there were 368,316 shares of common stock available for issuance in satisfaction of awards under the Directors Compensation Plan. Reductions in shares available are made when Restricted Shares are granted. A summary of activity related to Restricted Shares is as follows: 2022 2021 2020 Weighted Weighted Weighted Average Average Average Grant Date Grant Date Grant Date Restricted Fair Value Restricted Fair Value Restricted Fair Value Shares Per Share Shares Per Share Shares Per Share Nonvested, beginning of period 70,226 $ 3.65 154,128 $ 3.64 123,180 $ 4.55 Granted 42,426 4.95 62,502 3.36 109,376 2.56 Vested (70,226) 3.65 (146,404) 3.51 (78,428) 2.38 Nonvested, end of period 42,426 $ 4.95 70,226 $ 3.65 154,128 $ 3.64 Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2022 are eligible to vest in 2023. Restricted stock fair value at grant date Restricted stock fair value at vested date Share-Based Compensation A summary of compensation expense under share-based payment arrangements is as follows (in thousands): Year Ended December 31, 2022 2021 2020 Restricted stock units $ 4,192 $ 2,579 $ 3,555 Performance share units 3,504 412 — Restricted Shares 226 373 404 Total $ 7,922 $ 3,364 $ 3,959 As of December 31, 2022, unrecognized share-based compensation expense related to our awards of RSUs, PSUs and Restricted Shares was $2.4 million, $9.9 million and $0.1 million, respectively. Unrecognized compensation expense will be recognized through December 2024 for RSUs and PSUs and April 2023 for Restricted Shares. Cash-based Incentive Compensation Short-term Cash-Based Incentive Compensation The following short-term cash-based incentive awards were granted during 2022 and 2021: ● On May 26, 2022 the Company granted cash based awards subject to Company performance criteria. As of December 31, 2022, a portion of the Company performance based criteria was achieved. As of December 31, 2022, incentive compensation expense of $11.9 million was recognized related to these awards. Payment is expected to be made in March 2023. ● In February 2021, the Company granted discretionary cash-based awards subject only to continued employment on the payment dates. The 2021 discretionary bonus award was paid in equal installments on March 15, 2021 and April 15, 2021, to substantially all employees subject to employment on those dates. Incentive compensation expense of $7.0 million was recognized as of December 31, 2021, related to these awards. ● During June 2021, the Company granted cash-based awards subject to Company performance criteria through December 31, 2021. A portion of the Company performance-based criteria were achieved. In addition, the Board of Directors approved a discretionary amount. Incentive compensation expense of $2.1 million and $6.4 million was recognized in 2022 and 2021, respectively, related to these awards. Payments were made in March 2022. No cash-based incentive awards were granted in 2020. Cash-based incentive compensation expense recorded in 2020 related to the amortization of long-term cash awards granted in prior periods. Long-term Cash-Based Incentive Compensation No long-term cash-based incentive awards were granted during the year ended December 31, 2022. During June 2021, the Company granted long-term, cash-based awards (the “2021 Cash Awards”) subject to the same performance-based criteria as the 2021 PSUs noted above. The 2021 Cash Awards were subject to an approximate one year performance period, which ended on December 31, 2021. Subsequent to the performance period, the 2021 Cash Awards will continue to be subject to service-based criteria until vesting occurring on October 1, 2023. The 2021 Cash Awards are accounted for as liability awards and are measured at fair value each reporting date through the end of the performance period. Compensation cost for the 2021 Cash Awards to employees is recognized over the service period from June 28, 2021 through October 1, 2023. The fair value of the awards as of December 31, 2022 is $1.1 million. During the year ended December 31, 2022 and 2021, the Company recognized expense of $0.5 million and $0.2 million related to the 2021 Cash Awards. As of December 31, 2022, unrecognized compensation expense related to these awards was $0.4 million. 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, 2022 2021 2020 Share-based compensation included in: General and administrative expenses $ 7,922 $ 3,364 $ 3,959 Cash-based incentive compensation included in: Lease operating expense (1) 3,812 3,500 849 General and administrative expenses (1) 10,697 10,086 4,019 Total charged to operating income (loss) $ 22,431 $ 16,950 $ 8,827 (1) Includes adjustments of accruals to actual payments. |
EMPLOYEE BENEFIT PLAN
EMPLOYEE BENEFIT PLAN | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
EMPLOYEE BENEFIT PLAN | NOTE — The Company maintains a defined contribution benefit plan (the “401(k) Plan”) in compliance with Section 401(k) of the Internal Revenue Code (“IRC”), which covers those employees who meet the 401(k) Plan’s eligibility requirements. During 2022, 2021, and 2020 the time periods where matching occurred, the Company’s matching contribution was 100% of each participant’s contribution up to a maximum of 6% of the participant’s eligible compensation, subject to limitations imposed by the IRC. The 401(k) Plan provides 100% vesting in Company match contributions on a pro rata basis over five years of service (20% per year). Expenses relating to the 401(k) Plan were $2.4 million, $2.0 million, and $2.3 million for 2022, 2021 and 2020, respectively. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
INCOME TAXES | NOTE — Income Tax Expense (Benefit) Components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2022 2021 2020 Current $ 8,476 $ 132 $ 134 Deferred 45,184 (8,189) (30,287) Total income tax expense (benefit) $ 53,660 $ (8,057) $ (30,153) Reconciliation The reconciliation of income taxes computed at the U.S. federal statutory tax rate to the Company’s income tax expense (benefit) is as follows (in thousands): Year Ended December 31, 2022 2021 2020 Income tax expense (benefit) at the federal statutory rate $ 59,810 $ (10,402) $ 1,604 Compensation adjustments 599 559 1,373 State income taxes 2,418 (330) 75 Impact of U.S. legislative changes — — (21,345) Valuation allowance (9,117) 1,863 (12,018) Other (50) 253 158 Total income tax expense (benefit) $ 53,660 $ (8,057) $ (30,153) The Company’s effective tax rate for the years 2022, 2021 and 2020 differed from the applicable federal statutory rate of 21.0% primarily due to adjustments in the valuation allowance on deferred tax assets, which is discussed below, and the impact of state income taxes. As a result, the effective tax rate for 2022 and 2021 is 18.8% and 16.3%, respectively, while the effective tax rate for the year 2020 is not meaningful. 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 the Company’s deferred tax assets and liabilities were as follows (in thousands): December 31, 2022 2021 Deferred tax liabilities: Property and equipment $ 80,616 $ 55,170 Investment in non-consolidated entity 3,951 4,659 Other 2,948 2,817 Total deferred tax liabilities 87,515 62,646 Deferred tax assets: Derivatives 25,969 21,026 Asset retirement obligations 103,910 91,850 Contingent asset retirement obligations 4,540 980 Right of use liability 2,964 2,976 Federal net operating losses 281 42,127 State net operating losses 5,691 7,612 Interest expense limitation carryover 9,620 18,628 Share-based compensation 1,546 312 Valuation allowance (15,311) (24,359) Other 5,513 3,886 Total deferred tax assets 144,723 165,038 Net deferred tax assets $ 57,208 $ 102,392 Income Taxes Receivable, Refunds and Payments As of December 31, 2022 and 2021, the Company did not have any current income taxes receivable. During the year ended December 31, 2022 the Company made $8.2 million in income tax payments, and during the year ended December 31, 2021, the Company did not make any tax payments of significance. Net Operating Loss and Interest Expense Limitation Carryover The table below presents the details of the Company’s net operating loss and interest expense limitation carryover as of December 31, 2022 (in thousands): Amount Expiration Year Federal net operating loss $ 1,339 N/A State net operating loss 96,054 2026-2041 Interest expense limitation carryover 43,139 N/A Valuation Allowance During 2022, the Company’s valuation allowance decreased $9.0 million primarily due to the utilization of part of the Company’s disallowed interest expense limitation carryover. Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on the Company’s deferred tax assets, the Company considers whether it is more likely than not that some portion or all of them will not be realized. The Company assesses available positive and negative evidence regarding its ability to realize its deferred tax assets including reversing temporary differences and projections of future taxable income during the periods in which those temporary differences become deductible, as well as negative evidence such as historical losses. Assumptions about the Company’s future taxable income are consistent with the plans and estimates used to manage the Company’s business. The Company showed positive income in 2022 and continues to project similar results into the future. Based on this, the Company concluded that there is enough positive evidence to outweigh any negative evidence although any changes in forecasted taxable income could have a material impact on this analysis. The portion of the valuation allowance remaining relates to state net operating losses and the disallowed interest limitation carryover under IRC section 163(j). As of December 31, 2022, the Company’s valuation allowance was $15.3 million. Years Open to Examination The tax years from 2019 through 2022 remain open to examination by the tax jurisdictions to which the Company is subject. |
EARNINGS PER SHARE
EARNINGS PER SHARE | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
EARNINGS PER SHARE | NOTE — 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-class method when the effect is dilutive. The following table presents the calculation of basic and diluted earnings per common share (in thousands, except per share amounts): Year Ended December 31, 2022 2021 2020 Net income (loss) $ 231,149 $ (41,478) $ 37,790 Weighted average common shares outstanding - basic 143,143 142,271 141,622 Dilutive effect of securities 1,947 — 1,655 Weighted average common shares outstanding - diluted 145,090 142,271 143,277 Earnings per common share: Basic $ 1.61 $ (0.29) $ 0.26 Diluted $ 1.59 $ (0.29) $ 0.26 Shares excluded due to being anti-dilutive (weighted average) — 1,370 — |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
SUPPLEMENTAL CASH FLOW INFORMATION | NOTE — The following table reflects supplemental cash flow information (in thousands): Year Ended December 31, 2022 2021 2020 Supplemental cash items: Cash and cash equivalents $ 461,357 $ 245,799 $ 43,726 Restricted cash and restricted cash equivalents 4,417 4,417 — Cash paid for interest 71,126 64,805 59,183 Cash paid for income taxes 8,198 152 159 Cash refunds received for income taxes — 1 2,007 Cash received for interest income 5,909 112 603 Non-cash investing activities: Accruals of property and equipment 6,636 9,464 3,035 ARO - additions, dispositions and revisions, net 91,652 36,175 17,928 |
COMMITMENTS
COMMITMENTS | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
COMMITMENTS | NOTE 16 — Pursuant to the 2010 Purchase and Sale Agreement with Total E&P, the Company may fulfill security requirements related to ARO for certain properties through securing surety bonds, or through making payments to an escrow account under a formula pursuant to the agreement, or a combination thereof, until certain prescribed thresholds are met. As of December 31, 2022, the Company had surety bonds related to the agreement totaling $100.4 million and had no amounts in escrow. The threshold escalates to $103.0 million for 2023. There is no further escalation of the threshold after 2023. Pursuant to the 2010 Purchase and Sale Agreement with Shell Offshore Inc. related to ARO for certain properties, the Company has surety bonds that are subject to re-appraisal by either party. As of December 31, 2022, neither party had requested a re-appraisal to be made. The current security requirement of $64.0 million could be increased up to $94.0 million depending on certain conditions and circumstances. Pursuant to the 2019 Purchase and Sale Agreement with Exxon related to ARO for certain properties, the Company was required to obtain $36.3 million of surety bonds as of December 31, 2022. This amount increases on June 1 of the following years to $40.0 million - 2023; $44.0 million - 2024; $48.3 million - 2025; $53.2 million - 2026; $58.5 million - 2027, and future increases in increments ranging $5.9 million to $10.4 million per year until the total amount reaches $114.0 million in 2034. The Company may request a redetermination with Exxon every two years by providing certain documentation as provided in the purchase agreement. W&T is required to maintain this scheduled level of bonds until the properties are fully plugged, abandoned, and restored in accordance with applicable laws and regulations. Pursuant to the 2019 Purchase and Sale Agreement with Conoco related to ARO for certain properties, W&T was required to obtain $49.0 million of surety bonds and is required to maintain this level of bonds until the properties are fully plugged, abandoned, and restored in accordance with applicable laws and regulations. During 2022, 2021 and 2020, the Company had surety bonds primarily related to decommissioning obligations. Total expenses related to surety bonds, inclusive of the surety bonds in connection with the agreements described above, were $8.3 million, $6.0 million, and $5.4 million during 2022, 2021 and 2020, respectively. Future surety bond costs may change due to a number of factors, including changes and interpretations of regulations by the BOEM, rates being charged in the market place, and timing of when decommissioning obligations are completed. In conjunction with the purchase of an interest in the Heidelberg field, the Company assumed contracts with certain pipeline companies that contain minimum quantities obligations that extend to 2028. For 2022, 2021 and 2020 expense recognized for the difference between the quantities shipped and the minimum obligations was $1.6 million, $2.1 million and $4.5 million, respectively. The Company does not have any long-term drilling rig commitments as of December 31, 2022. |
RELATED PARTIES
RELATED PARTIES | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
RELATED PARTIES | NOTE — During 2022, 2021 and 2020, there were certain transactions between W&T and other companies W&T’s Chief Executive Officer, Tracy W. Krohn (“CEO”) either controlled or in which he had an ownership interest. The Company’s CEO owns an aircraft that the Company used for business purposes and the CEO used for his personal matters pursuant to his employment contract, and these costs were paid by the Company. Airplane services transactions were approximately $1.7 million, $0.6 million and $0.3 million for the each of the years ended December 31, 2022, 2021 and 2020. An entity owned by the Company’s CEO has legacy ownership interests in certain wells operated by W&T. Revenues are disbursed and expenses are collected in accordance with ownership interest. As of December 31, 2022, such wells have been plugged and abandoned by the operator. The entity also has ownership interests in certain wells in which the Company does not have an ownership interest in. These wells are covered under W&T’s insurance policy. The entity reimburses the Company for its proportionate share of insurance premiums related to these wells and when insurance proceeds are collected related to damage, those costs are disbursed as applicable. In addition, the entity reimburses W&T for certain administrative costs incurred during the year. These costs are less than $0.1 million per year and are included on the Company’s Consolidated Statements of Operations as a reduction to general and administrative expenses. All ownership interests noted above pre-date the Company’s initial public offering. A company that provides marine transportation and logistics services to W&T employs the spouse of the Company’s CEO. The rates charged for these marine and transportation services were generally either equal to or below rates charged by non-related, third-party companies and/or otherwise determined to be of the best value to the Company. Payments to such company totaled $20.0 million, $12.0 million and $14.4 million in 2022, 2021 and 2020, respectively. The spouse received commissions partially based on services rendered to W&T which were approximately $0.1 million in 2022, 2021 and 2020. During 2018, an entity controlled by the Company’s CEO participated in the 9.75% Senior Second Lien Note issuance for an $8.0 million principal commitment on the same terms as the other lenders. During 2022 and 2021, pursuant to the Amendments to the Sixth Amended and Restated Credit Agreement, Calculus, an entity indirectly owned and controlled by W&T’s CEO, became the sole lender under the Credit Agreement. In relation to the execution of the Ninth, Tenth and Eleventh Amendments, the Company paid Calculus arrangement and extension fees of approximately $1.1 million and $0.8 million in 2022 and 2021, respectively and paid legal fees on behalf of Calculus of approximately $0.1 million and $0.2 million in 2022 and 2021, respectively. See Note 2 – Debt See Note 5 – Joint Venture Drilling Program Note 20 – Subsequent Events |
CONTINGENCIES
CONTINGENCIES | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
CONTINGENCIES | NOTE — Appeal with ONRR In 2009 , W&T recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through subsea pipeline systems owned by the Company. In 2010 , the ONRR audited calculations and support related to this usage fee, and in 2010 , ONRR notified the Company that they had disallowed approximately $4.7 million of the reductions taken. The Company recorded a reduction to other revenue in 2010 to reflect this disallowance with the offset to a liability reserve; however, the Company disagrees with the position taken by the ONRR. W&T filed an appeal with the ONRR, which ultimately led to the Company posting a bond in the amount of $7.2 million and cash collateral of $6.9 million with the surety in order to appeal the Interior Board of Land Appeals decision. The cash collateral held by the surety was subsequently returned to the Company during the first quarter of 2020 . The Company has continued to pursue its legal rights and the case is in front of the U.S. District Court for the Eastern District of Louisiana where both parties have filed cross-motions for summary judgment and opposition briefs. W&T has filed a Reply in support of its Motion for Summary Judgment and the government has in turn filed its Reply brief. With briefing now completed, the Company is waiting for the district court’s ruling on the merits. Civil Penalties Assessment In January 2021, the Company executed a Settlement Agreement with BSEE which resolved nine pending civil penalties issued by BSEE which pertained to INCs alleging regulatory non-compliance at separate offshore locations on various dates between July 2012 and January 2018, with the proposed civil penalty amounts totaling $7.7 million. Under the Settlement Agreement, W&T will pay a total of $720,000 in three annual installments. The first, second and final installments were paid in March 2021, March 2022 and February 2023, respectively. In addition, W&T committed to implement a Safety Improvement Plan with various deliverables due, which have all been timely satisfied . Contingent Decommissioning Obligations The Company may be subject to retained liabilities with respect to certain divested property interests by operation of law. Certain counterparties in past divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. Due to operation of law, W&T may be required to assume decommissioning obligations for those interests. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. W&T no longer owns these assets nor are they related to current operations. During the year ended December 31, 2021, as a result of the declaration of bankruptcy by a third party that is the indirect successor in title to certain offshore interests that were previously divested by the Company, W&T recorded a $4.5 million loss contingency accrual related to the anticipated decommissioning obligations reflected in Other expense (income) Other expense (income) AAIT Litigation In August 2022, the Company’s primary information technology service provider, AAIT, notified the Company of its intention to cease providing services to the Company by September 2, 2022. Following such notification, the Company began the process of moving certain of these services within the Company and transitioning the remaining services to new service providers. On August 19, 2022, the Company filed in the District Court of Harris County, Texas a petition for a temporary restraining order, temporary injunction, and permanent injunction seeking, among other things, to restrain AAIT from ceasing to provide services to the Company until the transition process is complete. On September 14, 2022, AAIT removed the matter to the United States District Court for the Southern District of Texas. On September 16, 2022, the Company and AAIT mutually agreed to the terms of an agreed order of the court providing for a temporary injunction for a period of a minimum of 60 days from the date of the order and up to a maximum of 120 days at the Company’s option, during which AAIT would continue to provide information technology services to the Company and assist with the transition process. By agreement of the parties, the agreed order also provided for the appointment of Hon. Gregg J. Costa (Ret.) as an independent adjudicator to assist in adjudicating ongoing disputes between the parties. As of December 31, 2022, the Company has substantially completed the transition process and the Company no longer has a material relationship with AAIT. Other Claims W&T is a party to various pending or threatened claims and complaints seeking damages or other remedies concerning commercial operations and other matters in the ordinary course of its business. In addition, claims or contingencies may arise related to matters occurring prior to the Company’s acquisition of properties or related to matters occurring subsequent to the Company’s sale of properties. In certain cases, W&T has indemnified the sellers of properties acquired, and in other cases, W&T has indemnified the buyers of properties sold. The Company is also subject to federal and state administrative proceedings conducted in the ordinary course of business including matters related to alleged royalty underpayments on certain federal-owned properties. Although W&T can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have, the Company believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on the consolidated financial position, results of operations or liquidity of the Company. |
SUPPLEMENTAL OIL AND GAS DISCLO
SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED | NOTE 19 — Capitalized Costs Net capitalized costs related to oil, NGLs and natural gas producing activities are as follows (in thousands): Year Ended December 31, 2022 2021 2020 Net capitalized costs: Proved oil and natural gas properties and equipment $ 8,813,404 $ 8,636,408 $ 8,567,509 Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities (8,088,271) (7,981,271) (7,890,889) Net capitalized costs related to producing activities $ 725,133 $ 655,137 $ 676,620 Depreciation, depletion and amortization ($/Boe) 7.32 6.50 6.34 Costs Incurred In Oil and Gas Property Acquisition, Exploration and Development Activities The following costs were incurred in oil, NGLs and natural gas property acquisition, exploration, and development activities (in thousands): Year Ended December 31, 2022 2021 2020 Costs incurred: (1) Proved properties acquisitions $ 78,565 $ 2,197 $ 8,118 Exploration (2) 24,498 18,444 7,727 Development 77,282 47,218 23,528 Total costs incurred in oil and gas property acquisition, exploration and development activities $ 180,345 $ 67,859 $ 39,373 (1) Includes net additions from capitalized ARO of $88.8 million, $36.2 million, and $15.2 million during 2022, 2021, and 2020, respectively. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates. (2) Includes seismic costs of $5.6 million, $ 0.1 million, and $0.3 million incurred during 2022, 2021, and 2020, respectively. Includes geological and geophysical costs charged to expense of $5.5 million, $5.7 million, and $4.5 million during 2022, 2021, and 2020, respectively. Oil and Natural Gas Reserve Information All of the Company’s proved reserves are located in state and federal waters in the U.S. Gulf of Mexico. 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. Reserve estimates were prepared based on the interpretation of various data by the Company’s independent reservoir engineers, including production data and geological and geophysical data of the Company’s existing wells. 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-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC. The prices used do not purport, nor should it be interpreted, to present the current market prices related to estimated oil and natural gas reserves. The following sets forth estimated quantities of net proved oil, NGLs and natural gas reserves: NGLs Natural Gas Oil Equivalent Oil (MMBbls) (MMBbls) (Bcf) (MMBoe) Proved reserves as of December 31, 2019 37.8 24.5 571.1 157.4 Revisions of previous estimates (0.9) (5.9) 31.6 (1.4) Extensions and discoveries 0.2 — 0.2 0.2 Purchase of minerals in place 0.7 0.5 14.8 3.6 Sales of minerals in place — — — — Production (5.6) (1.7) (48.4) (15.4) Proved reserves as of December 31, 2020 32.2 17.4 569.3 144.4 Revisions of previous estimates 10.0 3.1 83.0 27.1 Extensions and discoveries — — — — Purchase of minerals in place — — 0.1 — Production (5.0) (1.4) (44.8) (13.9) Proved reserves as of December 31, 2021 37.2 19.1 607.6 157.6 Revisions of previous estimates 4.5 1.2 64.3 16.3 Extensions and discoveries — — — — Purchase of minerals in place 4.5 0.2 7.5 6.0 Production (5.6) (1.6) (44.8) (14.6) Proved reserves as of December 31, 2022 40.6 18.9 634.6 165.3 Year-end proved developed reserves: 2022 31.1 17.6 576.0 144.8 2021 27.6 17.8 549.2 137.0 2020 24.0 16.5 550.2 132.2 Year-end proved undeveloped reserves: 2022 (10) 9.5 1.3 58.6 20.5 2021 9.6 1.3 58.4 20.6 2020 8.2 0.9 19.1 12.2 During 2022, increases in revisions of previous estimates were primarily due to upward revisions to the Brazos A133 field combined with increases due to SEC price revisions for all proved reserves. Proved reserves were also added through the acquisitions of properties acquired from ANKOR and subsequent working interest acquisition in the same properties from a private seller. During 2021, increases in revisions of previous estimates were primarily due to upward revisions to the Garden Banks 783 (Magnolia) field combined with increases due to SEC price revisions for all proved reserves. During 2020, decreases in revisions of previous estimates were primarily due to additions made in the Mobile Bay properties due to the consolidation of the Yellowhammer and OTF gas plants which significantly reduced field lease operating expenses and additions made in the Garden Banks 783 (Magnolia) field. These additions were offset due to significant negative revisions due to SEC price revisions for all proved reserves. Proved reserves were also added as a result of working interest acquisitions in both the Mobile Bay Properties and Garden Banks 783 (Magnolia) field. The Company believes that it will be able to develop all but 2.5 MMBoe (approximately 12%) of the total 20.5 MMBoe classified as PUDs at December 31, 2022, within five years from the date such PUDs were initially recorded. The lone exceptions are at the Mississippi Canyon 243 field (“Matterhorn”) and Viosca Knoll 823 (“Virgo”) deepwater fields where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability. Two sidetrack PUD locations, one each at Matterhorn and Virgo, will be delayed until an existing well is depleted and available to sidetrack. The Company also plans to recomplete and convert an existing producer at Matterhorn to water injection for improved recovery following depletion of existing well. Based the latest reserve report, these PUD locations are expected to be developed in 2024. Standardized Measure of Discounted Future Net Cash Flows The following presents the standardized measure of discounted future net cash flows related to the Company’s proved oil, NGLs and natural gas reserves together with changes therein (in thousands): Year Ended December 31, 2022 2021 2020 Standardized Measure of Discounted Future Net Cash Flows Future cash inflows $ 8,855,730 $ 5,178,215 $ 2,561,189 Future costs: Production (2,894,652) (2,061,752) (1,257,421) Development and abandonment (990,329) (976,500) (707,357) Income taxes (1,005,917) (358,954) (60,503) Future net cash inflows before 10% discount 3,964,832 1,781,009 535,908 10% annual discount factor (1,701,871) (625,019) (42,202) Total $ 2,262,961 $ 1,155,990 $ 493,706 Future cash inflows represent expected revenues from production of period-end quantities of proved reserve computed using SEC pricing for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the crude oil realized price. Then, this ratio is applied to the crude oil price using SEC guidance. The average base commodity prices used to determine the standardized measure are as follows: December 31, 2022 2021 2020 Oil ($/Bbl) $ 91.50 $ 65.25 $ 37.78 NGLs ($/Bbl) 41.92 26.83 10.29 Natural gas ($/Mcf) 6.85 3.68 2.05 Future production, development and abandonment costs and production rates and timing were based on the best information available to the Company. Estimated future net cash flows, net of future income taxes, have been discounted to their present values based on the prescribed annual discount rate of 10%. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of the Company’s oil, NGLs and natural gas reserves. Actual prices realized, costs incurred, and production quantities and timing may vary significantly from those used. The change in the standardized measure of discounted future net cash flows relating to the Company’s proved oil, NGLs and natural gas reserves is as follows (in thousands): Year Ended December 31, 2022 2021 2020 Changes in Standardized Measure Standardized measure, beginning of year $ 1,155,990 $ 493,706 $ 986,900 Increases (decreases): Sales and transfers of oil and gas produced, net of production costs (672,665) (370,456) (168,563) Net changes in price, net of future production costs 1,368,626 980,922 (503,676) Extensions and discoveries, net of future production and development costs — — 2,767 Changes in estimated future development costs (18,617) (25,357) (15,881) Previously estimated development costs incurred 3,313 613 1,384 Revisions of quantity estimates 249,117 289,637 (65,218) Accretion of discount 138,077 43,993 111,760 Net change in income taxes (369,307) (181,795) 87,713 Purchases of reserves in-place 225,205 319 44,621 Sales of reserves in-place — — — Changes in production rates due to timing and other 183,222 (75,592) 11,899 Net (decrease) increase 1,106,971 662,284 (493,194) Standardized measure, end of year $ 2,262,961 $ 1,155,990 $ 493,706 |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2022 | |
Subsequent Events | |
SUBSEQUENT EVENTS | NOTE 20 — 11.75% Senior Second Lien Notes due 2026 On January 27, 2023, the Company issued and sold $275 million in aggregate principal amount of its 11.75% Senior Second Lien Notes at par with an interest rate of 11.75% per annum that matures on February 1, 2026 (the “11.75% Senior Second Lien Notes”), which are governed under the terms of an indenture (the “Indenture”). Interest on the 11.75% Senior Second Lien Notes is payable in arrears on February 1 and August 1, commencing August 1, 2023. The 11.75% Senior Second Lien Notes will be recorded at their carrying value consisting of principal and unamortized debt issuance costs. The 11.75% Senior Second Lien Notes are secured by second-priority liens on the same collateral that is secured under the Credit Agreement. Prior to August 1, 2024, the Company may redeem all or any portion of the 11.75% Senior Second Lien Notes at a redemption price equal to 100% of the principal amount of the outstanding plus accrued and unpaid interest, if any, to the redemption date, plus the “Applicable Premium” (as defined in the Indenture). In addition, prior to August 1, 2024, the Company may, at its option, on one or more occasions redeem up to 35% of the aggregate original principal amount of the 11.75% Senior Second Lien Notes in an amount not greater than the net cash proceeds from certain equity offerings at a redemption price of 111.750% of the principal amount of the outstanding plus accrued and unpaid interest, if any, to the redemption date. On and after August 1, 2024, the Company may redeem the 11.75% Senior Second Lien Notes, in whole or in part, at redemption prices (expressed as percentages of the principal amount thereof) equal to 105.875% for the 12-month period beginning August 1, 2024, and 100.000% on August 1, 2025 and thereafter, plus accrued and unpaid interest, if any, to the redemption date. The 11.75% Senior Second Lien Notes are guaranteed by the Guarantors. The 11.75% Senior Second Lien Notes contain covenants that limit or prohibit the Company’s ability and the ability of certain of its subsidiaries to: (i) make investments; (ii) incur additional indebtedness or issue certain types of preferred stock; (iii) create certain liens; (iv) sell assets; (v) enter into agreements that restrict dividends or other payments from the Company’s subsidiaries to the Company; (vi) consolidate, merge or transfer all or substantially all of the assets of the Company; (vii) engage in transactions with affiliates; (viii) pay dividends or make other distributions on capital stock or subordinated indebtedness; and (ix) create subsidiaries that would not be restricted by the covenants of the Indenture. These covenants are subject to important exceptions and qualifications set forth in the Indenture. In addition, most of the above-described covenants will terminate if both S&P Global Ratings, a division of S&P Global Inc., and Moody’s Investors Service, Inc. assign the 11.75% Senior Second Lien Notes an investment grade rating and no default exists with respect to the 11.75% Senior Second Lien Notes. An entity controlled by the Company’s CEO participated in the issuance of the 11.75% Senior Second Lien Notes for a $21.0 million principal commitment, on the same terms as the other lenders. Redemption of 9.75% Senior Second Lien Notes due 2023 On February 8, 2023, the Company redeemed all of the existing 9.75% Senior Second Lien Notes outstanding at a redemption price of 100.0%, plus accrued and unpaid interest to the redemption date. As of December 31, 2022, there was $552.5 million of aggregate principal outstanding. The Company used the net proceeds of $270.8 million from the issuance of the 11.75% Senior Second Lien Notes and cash on hand of $296.1 million to fund the redemption. As part of the redemption of the 9.75% Senior Second Lien Notes, an entity controlled by the Company’s CEO had their previously disclosed $8.0 million principal commitment repaid in full. Credit Agreement On February 8, 2023, the Company provided notice of the redemption of the existing 9.75% Senior Second Lien Notes and the issuance of the 11.75% Senior Second Lien Notes to Alter Domus (US) LLC and Calculus pursuant to the terms of the Credit Agreement, which reaffirmed the Credit Agreement’s maturity date of January 3, 2024. |
SIGNIFICANT ACCOUNTING POLICI_2
SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Basis of Accounting, Policy [Policy Text Block] | Basis of Presentation The Consolidated Financial Statements include the accounts of W&T Offshore, Inc., its majority-owned subsidiary and the proportionately consolidated interests in oil and gas joint ventures. All significant intercompany transactions have been eliminated. The Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and the appropriate rules and regulations of the SEC. |
Reclassification, Comparability Adjustment [Policy Text Block] | Reclassification – Derivative loss (gain) Additionally, as of December 31, 2020, Gathering and transportation and Production taxes have been combined into one line item within “Operating income” on the Consolidated Statement of Operations in order to conform to the current period presentation. Such reclassifications had no effect on the Company’s results of operations, financial position or cash flows. |
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. |
Cash and Cash Equivalents, Policy [Policy Text Block] | Cash Equivalents W&T considers all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents. |
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block] | Restricted Cash As of December 31, 2021, the Company cash collateralized each of the outstanding letters of credit in the aggregate amount of approximately $4.4 million. See Note 2 –Debt |
Revenue from Contract with Customer [Policy Text Block] | Revenue Recognition The Company records revenues from the sale of oil, NGLs and natural gas based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. Revenue from the sale of crude oil, NGLs and natural gas is recognized when performance obligations under the terms of the respective contracts are satisfied; this generally occurs with the delivery of oil, NGLs and natural gas to the customer. Each unit of product represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. W&T does not record imbalance receivables for those properties in which the Company has taken less than its ownership share of production. As of December 31, 2022 and 2021, $3.5 million, is included as a current liability in Undistributed oil and natural gas proceeds |
Concentration Risk, Credit Risk, Policy [Policy Text Block] | Concentration of Credit Risk The Company’s customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. The majority of the Company’s production is sold to customers under short-term contracts at market-based prices. The Company attempts to minimize credit risk exposure to purchasers, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guarantees when considered necessary. The following table identifies customers whose total represented 10% or more of the Company’s receipts from sales of crude oil, NGLs and natural gas: Year Ended December 31, 2022 2021 2020 Customer BP Products North America 31 % 34 % 39 % Chevron - Texaco 13 % 14 % ** Mercuria Energy America Inc. ** ** 10 % Williams Field Services ** 11 % 13 % ** Less than 10% The loss of any of the customers above would not result in a material adverse effect on the Company’s ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing |
Accounts Receivable [Policy Text Block] | Accounts Receivables and Allowance for Credit Losses Accounts Receivable are recorded at historical cost, net of an allowance for credit losses, to reflect the net amounts to be collected. Receivables consist of sales of production to customers and joint interest billings. At each reporting period, a loss methodology is used to determine the recoverability of material receivables using historical data, current market conditions and forecasts of future economic conditions to determine expected collectability. The following table describes the balance and changes to the allowance for credit losses (in thousands): 2022 2021 2020 Allowance for credit losses, beginning of period $ 10,046 $ 9,123 $ 9,898 Additional provisions for the year 3,085 2,192 417 Uncollectible accounts written off or collected (1,069) (1,269) (1,192) Allowance for credit losses, end of period $ 12,062 $ 10,046 $ 9,123 |
Prepaid Expenses and Other Assets [Policy Text Block] | Prepaid expenses and other assets Amounts recorded in Prepaid expenses and other assets December 31, 2022 2021 Derivatives (1) (Note 10) $ 4,954 $ 21,086 Unamortized insurance/bond premiums 6,046 5,400 Prepaid deposits related to royalties 9,139 8,441 Prepayment to vendors 1,767 4,522 Prepayments to joint interest partners 1,717 2,808 Debt issue costs 687 1,065 Other 33 57 Prepaid expenses and other assets $ 24,343 $ 43,379 (1) Includes closed contracts which have not yet settled and the current portion of open contracts. |
Property, Plant and Equipment, Policy [Policy Text Block] | Oil and Natural Gas Properties and Other, Net Oil and natural gas properties and equipment are recorded at cost using the full cost method. 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, 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 recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense. Oil and natural gas properties and equipment will include costs of unproved properties when applicable. The cost of unproved properties related to significant acquisitions are excluded from the amortization base until the Company has made an evaluation that impairment has occurred. As of December 31, 2022 and 2021, there were no unproved properties included in the Oil and natural gas properties and other, net Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas. 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 The following table provides the components of Oil and natural gas properties and other, net December 31, 2022 2021 Oil and natural gas properties and equipment $ 8,813,404 $ 8,636,408 Furniture, fixtures and other 20,915 20,844 Total property and equipment 8,834,319 8,657,252 Less: Accumulated depreciation, depletion, amortization and impairment (8,099,104) (7,992,000) Oil and natural gas properties and other, net $ 735,215 $ 665,252 |
Oil and Gas Properties Policy [Policy Text Block] | Ceiling Test Write-Down Under the full-cost method of accounting, the Company’s capitalized costs are limited to a quarterly ceiling test which determines a limit on the book value of 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 recoverable or reversible in future periods. The ceiling test limit is calculated as: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related income tax effects. Estimated future net revenues used in the ceiling test for each period are based on current prices for each product, defined by the SEC as the unweighted average of first-day-of-the-month commodity prices over the prior twelve months for that period. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. The Company did not record a ceiling test write-down during 2022, 2021 or 2020. If average crude oil and natural gas prices decrease below average pricing during 2022, the Company could incur ceiling test write-downs in future periods. |
Industry Specific Policies, Oil and Gas [Policy Text Block] | Oil and Natural Gas Reserve Estimates The Company utilizes SEC pricing when estimating quantities of proved reserves and the standardized measure of discounted future cash flows. Proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years, with some limited exceptions allowed. Refer to Note 19 – Supplemental Oil and Gas Disclosures |
Asset Retirement Obligation [Policy Text Block] | Asset Retirement Obligations The Company has obligations to plug and abandon well bores, remove 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. The Company records a separate liability for the present value of ARO based on the estimated timing and amount to replace, remove or retire the associated assets, with an offsetting increase to the related oil and natural gas properties on the balance sheet. In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect estimates of these future costs from period to period. After initial recording, the liability is increased for the passage of time, with the increase being reflected as Accretion expense on the Consolidated Statements of Operations. If the Company incurs an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties. See Note 7 – Asset Retirement |
Contingent Decommissioning Obligations Policy [Policy Text Block] | Contingent Decommissioning Obligations Certain counterparties in past divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. The Company accrues losses associated with decommissioning obligations when such losses are probable and reasonably estimable. When there is a range of possible outcomes, the amount accrued is the most likely outcome within the range. If no single outcome within the range is more likely than the others, the minimum amount in the range is accrued. These accruals may be adjusted as additional information becomes available. In addition, when decommissioning obligations are reasonably possible, the Company discloses an estimate for a possible loss or range of loss (or a statement that such an estimate cannot be reasonably made). See Note 18 —Contingencies |
Derivatives, Reporting of Derivative Activity [Policy Text Block] | Derivative Financial Instruments The Company uses commodity price derivative instruments to manage exposure to commodity price risk from sales of oil and natural gas. The Company does not enter into derivative instruments for speculative trading purposes. Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value. The Company does not designate derivatives instruments as hedging instruments, therefore, all changes in fair value are recognized in Derivative loss (gain) Note 10 – Derivative Financial Instruments |
Fair Value of Financial Instruments, Policy [Policy Text Block] | Fair Value of Financial Instruments Fair value information is included in the notes to the Consolidated Financial Statements when the fair value of the financial instruments is different from the book value or when it is required by U.S. GAAP. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities approximates fair value due to the short-term, highly liquid nature of these instruments. See Note 3 – Fair Value Measurements |
Income Tax, Policy [Policy Text Block] | Income Taxes The Company’s provision for income taxes includes U.S. state and federal taxes. Income taxes are recorded in accordance with accounting for income taxes under U.S. GAAP which results in the recognition of deferred tax assets and liabilities determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. The effects of changes in tax rates and laws on deferred tax balances are recognized in the period in which the new legislation is enacted. A valuation allowance is established on deferred tax assets when it is more likely than not that some portion or all of the related tax benefits will not be realized. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. Such uncertain tax positions are recognized in the Consolidated Financial Statements when it is determined that the relevant tax authority would more likely than not sustain the position following an audit. Any interest and penalties related to uncertain tax positions are recorded in Income tax expense Note 13 – Income Taxes |
Other Noncurrent Assets [Policy Text Block] | Other Assets (long-term) The major categories recorded in Other assets December 31, 2022 2021 Right-of-Use assets $ 10,364 $ 10,602 Investment in White Cap, LLC 2,453 2,533 Proportional consolidation of Monza (Note 5) 9,321 2,511 Derivatives (1) (Note 10) 23,236 34,435 Other 2,175 1,091 Total other assets (long-term) $ 47,549 $ 51,172 (1) Includes open contracts. |
Accrued Liabilities Policy [Policy Text Block] | Accrued Liabilities The major categories recorded in Accrued liabilities December 31, 2022 2021 Accrued interest $ 8,967 $ 10,154 Accrued salaries/payroll taxes/benefits 15,097 9,617 Litigation accruals 396 646 Lease liability 1,628 1,115 Derivatives (1) 46,595 81,456 Other 1,358 3,152 Total accrued liabilities $ 74,041 $ 106,140 (1) Includes closed contracts which have not yet settled. |
Paycheck Protection Program, Policy [Policy Text Block] | Paycheck Protection Program (“PPP”) On April 15, 2020, the Company received $8.4 million under the U.S. Small Business Administration (“SBA”) PPP. The Company’s application to the SBA requesting that the PPP funds received be applied to specific covered and non-covered payroll costs was accepted and approved for full forgiveness on June 11, 2021. As there is no definitive guidance under U.S. GAAP, the Company has applied the guidance under IAS 20 and accounted for the PPP as a government grant. Under IAS 20, a government grant is recognized when there is reasonable assurance that the Company has complied with the provisions of the grant. Accordingly, the funds received were recorded as a reduction to General and administrative expenses |
Debt, Policy [Policy Text Block] | Debt Issuance Costs Debt issuance costs associated with the Credit Agreement are amortized using the straight-line method over the scheduled maturity of the debt. The unamortized debt issue costs associated with the Credit Agreement are reported within Prepaid expenses and other assets Debt issuance costs associated with the 9.75% Senior Second Lien Notes and the Term Loan are amortized using the effective interest method over the scheduled maturity of the debt. The unamortized debt issuance costs associated with the current debt instruments are reported as a reduction to the carrying value of Current portion of long-term debt, net Long-term debt net Note 2 –Debt |
Gain on Refinancing of Debt Transaction Policy [Policy Text Block] | Gain on Debt Transactions During 2020, the Company acquired $72.5 million in principal of the outstanding 9.75% Senior Second Lien Notes for $23.9 million and recorded a non-cash gain on purchase of debt of $47.5 million. |
Other Noncurrent Liabilities [Policy Text Block] | Other Liabilities (long-term) The major categories recorded in Other liabilities December 31, 2022 2021 Dispute related to royalty deductions $ 4,937 $ 5,177 Derivatives (Note 10) 43,061 37,989 Lease liability 10,527 11,227 Other 609 996 Total other liabilities (long-term) $ 59,134 $ 55,389 |
At The Market Equity Offering Policy, [Policy Text Block] | At-the-Market Equity Offering On March 18, 2022, the Company filed a prospectus supplement related to the issuance and sale of up to $100,000,000 of shares of common stock under the Company’s ATM Program. The designated sales agent is entitled to a placement fee of up to 3.0% of the gross sales price per share sold. During the year ended December 31, 2022, the Company sold an aggregate of 2,971,413 shares for an average price of $5.72 per share in connection with the ATM Offering and received proceeds, net of commissions and expenses, of $16.5 million. |
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. The fair value for equity instruments subject to market-based performance measures was determined using a Monte Carlo valuation model with estimates made as of the grant date. Share-based compensation expense is recognized 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 expected to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 11 – Share-Based Awards and Cash-Based Awards |
Employee Retention Credit [Policy Text Block] | Employee Retention Credit Under the Consolidated Appropriations Act, 2021 passed by the United States Congress and signed by the President on December 27, 2020, provisions of the Coronavirus Aid, Relief and Economic Security Act were extended and modified making the Company eligible for a refundable employee retention credit subject to meeting certain criteria. The Company recognized a $2.1 million employee retention credit during the year ended December 31, 2021. The funds received were recorded as a reduction to General and administrative on the Consolidated Statement of Operations during the year ended December 31, 2021. No such credit was recognized during the years ended December 31, 2022 or 2020. |
Other Income (Expense), Net [Policy Text Block] | Other Expense (Income), Net For the year ended December 31, 2022, Other expense (income), net For the year ended December 31, 2021, the amount primarily consists of income related to the release restrictions on the Black Elk Escrow fund, partially offset by expenses related to the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program, offset by contingent decommissioning obligation recognized during the year ended December 31, 2021. For the year ended December 31, 2020, the amount primarily consists of expenses related to the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program. See Note 9 – Restricted Deposits for ARO and Note 18 —Contingencies for additional information . |
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-class method when the effect is dilutive. See Note 14 – Earnings Per Share |
SIGNIFICANT ACCOUNTING POLICI_3
SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Notes Tables | |
Schedules of Concentration of Risk, by Risk Factor [Table Text Block] | Year Ended December 31, 2022 2021 2020 Customer BP Products North America 31 % 34 % 39 % Chevron - Texaco 13 % 14 % ** Mercuria Energy America Inc. ** ** 10 % Williams Field Services ** 11 % 13 % ** Less than 10% |
Accounts Receivable, Allowance for Credit Loss [Table Text Block] | The following table describes the balance and changes to the allowance for credit losses (in thousands): 2022 2021 2020 Allowance for credit losses, beginning of period $ 10,046 $ 9,123 $ 9,898 Additional provisions for the year 3,085 2,192 417 Uncollectible accounts written off or collected (1,069) (1,269) (1,192) Allowance for credit losses, end of period $ 12,062 $ 10,046 $ 9,123 |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Table Text Block] | December 31, 2022 2021 Derivatives (1) (Note 10) $ 4,954 $ 21,086 Unamortized insurance/bond premiums 6,046 5,400 Prepaid deposits related to royalties 9,139 8,441 Prepayment to vendors 1,767 4,522 Prepayments to joint interest partners 1,717 2,808 Debt issue costs 687 1,065 Other 33 57 Prepaid expenses and other assets $ 24,343 $ 43,379 (1) Includes closed contracts which have not yet settled and the current portion of open contracts. |
Property, Plant and Equipment [Table Text Block] | The following table provides the components of Oil and natural gas properties and other, net December 31, 2022 2021 Oil and natural gas properties and equipment $ 8,813,404 $ 8,636,408 Furniture, fixtures and other 20,915 20,844 Total property and equipment 8,834,319 8,657,252 Less: Accumulated depreciation, depletion, amortization and impairment (8,099,104) (7,992,000) Oil and natural gas properties and other, net $ 735,215 $ 665,252 |
Schedule of Other Assets, Noncurrent [Table Text Block] | The major categories recorded in Other assets December 31, 2022 2021 Right-of-Use assets $ 10,364 $ 10,602 Investment in White Cap, LLC 2,453 2,533 Proportional consolidation of Monza (Note 5) 9,321 2,511 Derivatives (1) (Note 10) 23,236 34,435 Other 2,175 1,091 Total other assets (long-term) $ 47,549 $ 51,172 (1) Includes open contracts. |
Schedule of Accrued Liabilities [Table Text Block] | The major categories recorded in Accrued liabilities December 31, 2022 2021 Accrued interest $ 8,967 $ 10,154 Accrued salaries/payroll taxes/benefits 15,097 9,617 Litigation accruals 396 646 Lease liability 1,628 1,115 Derivatives (1) 46,595 81,456 Other 1,358 3,152 Total accrued liabilities $ 74,041 $ 106,140 (1) Includes closed contracts which have not yet settled. |
Other Noncurrent Liabilities [Table Text Block] | The major categories recorded in Other liabilities December 31, 2022 2021 Dispute related to royalty deductions $ 4,937 $ 5,177 Derivatives (Note 10) 43,061 37,989 Lease liability 10,527 11,227 Other 609 996 Total other liabilities (long-term) $ 59,134 $ 55,389 |
DEBT (Tables)
DEBT (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Notes Tables | |
Schedule of Debt Instruments [Table Text Block] | The components of debt are presented in the following tables (in thousands): December 31, 2022 2021 Term Loan: Principal $ 147,899 $ 190,859 Unamortized debt issuance costs (4,592) (7,545) Total Term Loan 143,307 183,314 Credit Agreement borrowings: — — 9.75% Senior Second Lien Notes: Principal 552,460 552,460 Unamortized debt issuance costs (2,330) (4,876) Total 9.75% Senior Second Lien Notes 550,130 547,584 Less current portion, net (582,249) (42,960) Total long-term debt, net $ 111,188 $ 687,938 |
Schedule of Maturities of Long-term Debt [Table Text Block] | Aggregate annual maturities of principal amounts recorded as of December 31, 2022 are as follows (in millions): 2023 $ 586.2 2024 30.1 2025 27.6 2026 25.4 2027 22.9 Thereafter 8.2 Total $ 700.4 |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Notes Tables | |
Schedule of Derivative Assets at Fair Value [Table Text Block] | December 31, 2022 2021 Assets: Derivative instruments - current $ 4,954 $ 21,086 Derivative instruments - long-term 23,236 34,435 Liabilities: Derivative instruments - current 46,595 81,456 Derivative instruments - long-term 43,061 37,989 |
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block] | December 31, 2022 December 31, 2021 Net Value Fair Value Net Value Fair Value Liabilities: Term Loan $ 143,307 $ 139,056 $ 183,314 $ 190,579 9.75% Senior Second Lien Notes 550,130 544,902 547,584 527,715 Total $ 693,437 $ 683,958 $ 730,898 $ 718,294 |
SUBSIDIARY BORROWERS (Tables)
SUBSIDIARY BORROWERS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
SUBSIDIARY BORROWERS | |
Schedule of Consolidation of Subsidiary Borrowers [Table Text Block] | December 31, 2022 2021 Assets: Cash and cash equivalents $ 21,764 $ 38,937 Receivables: Oil and natural gas sales 37,344 34,420 Joint interest, net (5,760) (10,856) Prepaid expenses and other assets 417 356 Oil and natural gas properties and other, net 280,649 272,747 Other assets 8,473 (19,903) Liabilities: Accounts payable 27,387 29,678 Undistributed oil and natural gas proceeds 7,930 3,144 Accrued liabilities 45,102 29,937 Current portion of long-term debt 32,119 42,960 Long-term debt, net 111,188 140,353 Asset retirement obligations 61,138 54,515 Other liabilities 47,398 42,615 |
Schedule of Subsidiary Borrowers and the subsidiary that owns the equity [Table Text Block] | The period from Year Ended May 19, 2021 to December 31, 2022 December 31, 2021 Total revenues $ 268,573 $ 119,550 Total operating expenses 73,990 32,735 Interest expense, net 14,721 9,782 Derivative loss 141,736 104,533 |
JOINT VENTURE DRILLING PROGRAM
JOINT VENTURE DRILLING PROGRAM (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Note 7 - Joint Venture Drilling Program | |
Schedule of Condensed Consolidated Balance Sheet related to the consolidation of the proportional interest in Monza's operations | The following table presents the amounts recorded by W&T on the Consolidated Balance Sheets related to the consolidation of the proportional interest in Monza’s operations (in thousands): December 31, 2022 2021 Working capital $ 2,515 $ 4,648 Oil and natural gas properties and other, net 37,260 45,510 Asset retirement obligations 467 301 Other assets 11,571 2,511 |
Schedule of Condensed Consolidated Statement of Operations related to the consolidation of the proportional interest in Monza's operations | f Year Ended December 31, 2022 2021 Total revenues $ 28,803 $ 12,716 Total operating expenses 13,523 10,044 Derivative loss — 2,096 Interest income 42 — |
ACQUISITIONS (Tables)
ACQUISITIONS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Asset Acquisition [Abstract] | |
Schedule of purchase price allocation and liabilities assumed | February 1, 2022 Oil and natural gas properties and other, net $ 54,299 Restricted deposits for asset retirement obligations 6,196 Asset retirement obligations (26,493) Allocated purchase price $ 34,002 April 1, 2022 Oil and natural gas properties and other, net $ 22,632 Restricted deposits for asset retirement obligations 1,549 Asset retirement obligations (6,709) Allocated purchase price $ 17,472 |
ASSET RETIREMENT OBLIGATIONS (T
ASSET RETIREMENT OBLIGATIONS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Notes Tables | |
Schedule of Change in Asset Retirement Obligation [Table Text Block] | Year Ended December 31, 2022 2021 Asset retirement obligations, beginning of period $ 424,495 $ 392,704 Liabilities settled (76,225) (27,309) Accretion expense 26,508 22,925 Liabilities acquired 33,202 454 Liabilities incurred 138 — Revisions of estimated liabilities 58,312 35,721 Asset retirement obligations, end of period 466,430 424,495 Less: Current portion (25,359) (56,419) Long-term $ 441,071 $ 368,076 |
LEASES (Tables)
LEASES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Notes Tables | |
Lease, Cost [Table Text Block] | December 31, 2022 2021 2020 Operating lease costs, excluding short-term leases $ 1,579 $ 1,743 $ 3,060 Short-term lease cost (1) 2,957 5,926 1,633 Variable lease cost (2) 647 — — Total lease cost $ 5,183 $ 7,669 $ 4,693 (1) Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a right-of-use asset and lease liability on the balance sheet. The majority of such costs are recorded within Oil and natural gas properties and other, net , on the Consolidated Balance Sheet. (2) Variable lease costs primarily represent differences between minimum lease payment obligations and actual operating charges incurred by the Company related to long-term operating leases. |
Operating Lease, Lessee, Assets and Liabilities [Table Text Block] | The present value of the fixed lease payments recorded as the Company’s right-of-use asset and liability, adjusted for initial direct costs and incentives are as follows (in thousands): December 31, 2022 2021 ROU assets $ 10,364 $ 10,602 Lease liability: Accrued liabilities $ 1,628 $ 1,115 Other liabilities 10,527 11,227 Total lease liability $ 12,155 $ 12,342 |
Lessee, Operating Lease, Weighted Average Remaining Lease Term and Discount Rate [Table Text Block] | The table below presents the weighted average remaining lease term and discount rate related to leases (in thousands): December 31, 2022 2021 2020 Weighted average remaining lease term: 13.1 years 14.1 years 14.8 years Weighted average discount rate: 10.1 % 10.1 % 10.2 % |
Lessee, Operating Lease, Supplemental Cash Flow Information [Table Text Block] | The table below presents the supplemental cash flow information related to leases (in thousands): December 31, 2022 2021 2020 Operating cash outflow from operating leases $ 1,224 $ 425 $ 1,825 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ — $ 5,142 |
Lessee, Operating Lease, Liability, Maturity [Table Text Block] | Undiscounted future minimum payments as of December 31, 2022 are as follows (in thousands): 2023 $ 1,628 2024 2,026 2025 1,514 2026 1,545 2027 1,576 Thereafter 14,242 Total lease payments 22,531 Present value adjustment (10,376) Total $ 12,155 |
RESTRICTED DEPOSITS FOR ARO (Ta
RESTRICTED DEPOSITS FOR ARO (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Notes to Financial Statements | |
Schedule of Restricted Deposits for Asset Retirement Obligations [Table Text Block] | December 31, 2022 2021 Main Pass 283/Viosca Knoll 734 (1) $ 13,684 $ 13,663 Eugene Island 205/89 (2) — 1,880 South Marsh Island 73 (3) 7,753 — Other 47 477 (1) In connection with a prior period acquisition of the Main Pass 283 and Viosca Knoll 734 fields, the Company received funds from the previous operator to cover future asset retirement obligations for those fields. The Company is not obligated to contribute additional amounts to these escrowed accounts. (2) In connection with a prior period acquisition of the Eugene Island 205 and 89 fields, the Company received funds from the previous owner to cover future asset retirement obligations for those fields. As of December 31, 2022, the Company has performed the related plugging and abandonment work at both fields. (3) During the first and second quarter of 2022, the Company acquired the South Marsh Island 73 field. As part of the transaction, the Company received a total of $7.8 million from the previous owners to cover future asset retirement obligations. The Company is not obligated to contribute additional amounts to this escrowed account. See Note 6 - Acquisitions for additional information. |
DERIVATIVE FINANCIAL INSTRUME_2
DERIVATIVE FINANCIAL INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Notes Tables | |
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block] | Average Instrument Daily Total Weighted Weighted Weighted Period Type Volumes Volumes Strike Price Put Price Call Price Natural Gas - Henry Hub (NYMEX) (MMbtu) (MMbtu) ($/MMbtu) ($/MMbtu) ($/MMbtu) Jan 2023 - Dec 2023 calls 70,000 25,550,000 $ — $ — $ 7.50 Jan 2024 - Dec 2024 calls 65,000 23,790,000 $ — $ — $ 6.13 Jan 2025 - Mar 2025 calls 62,000 5,580,000 $ — $ — $ 5.50 Jan 2023 - Dec 2023 (1) swaps 72,329 26,400,000 $ 2.48 $ — $ — Jan 2024 - Dec 2024 (1) swaps 65,574 24,000,000 $ 2.46 $ — $ — Jan 2025 - Mar 2025 (1) swaps 63,333 5,700,000 $ 2.72 $ — $ — Apr 2025 - Dec 2025 (1) puts 62,182 17,100,000 $ — $ 2.27 $ — Jan 2026 - Dec 2026 (1) puts 55,890 20,400,000 $ — $ 2.35 $ — Jan 2027 - Dec 2027 (1) puts 52,603 19,200,000 $ — $ 2.37 $ — Jan 2028 - Apr 2028 (1) puts 49,587 6,000,000 $ — $ 2.50 $ — (1) These contracts were entered into by the Company’s wholly owned subsidiary, A-I LLC (see Note 4 – Subsidiary Borrowers). |
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location [Table Text Block] | December 31, 2022 2021 Prepaid expenses and other current assets $ 4,954 $ 21,086 Other assets (long-term) 23,236 34,435 Accrued liabilities 46,595 81,456 Other liabilities (long-term) 43,061 37,989 Year Ended December 31, 2022 2021 2020 Realized loss (gain) (1) $ 125,089 $ 95,187 $ (33,415) Unrealized (gain) loss (39,556) 80,126 9,607 Derivative loss (gain) 85,533 175,313 (23,808) (1) The year ended December 31, 2022 includes the effects of the $138.0 million realized gain related to the monetization of certain natural gas call contracts through restructuring of strike prices which occurred in June 2022. |
Schedule of Cash Receipts and Payments on Commodity Derivative Contract Settlements [Table Text Block] | Year Ended December 31, 2022 2021 2020 Derivative loss (gain) $ 85,533 $ 175,313 $ (23,808) Derivative cash (payments) receipts, net (1) (41,880) (81,298) 45,196 Derivative cash premium payments (46,111) (40,484) — (1) The year ended December 31, 2022 includes $105.3 million of net cash receipts related to the monetization of certain natural gas call contracts through restructuring of strike prices. |
SHARE-BASED AWARDS AND CASH B_2
SHARE-BASED AWARDS AND CASH BASED AWARDS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Notes Tables | |
Schedule of Unvested Restricted Stock Units Roll Forward [Table Text Block] | 2022 2021 2020 Weighted Weighted Weighted Average Average Average Restricted Grant Date Fair Restricted Grant Date Fair Restricted Grant Date Fair Stock Units Value Per Unit Stock Units Value Per Unit Stock Units Value Per Unit Nonvested, beginning of period 698,465 $ 4.71 763,688 $ 4.51 1,614,722 $ 5.73 Granted 984,394 6.24 710,441 4.71 — — Vested (1) (387,285) 5.20 (731,095) 4.51 (787,203) 6.90 Forfeited (74,113) 5.24 (44,569) 4.50 (63,831) 5.80 Nonvested, end of period 1,221,461 5.76 698,465 $ 4.71 763,688 $ 4.51 (1) During May and June 2022, approximately 22,000 outstanding RSUs awarded in 2021 to two individuals retiring from their employment with the Company were modified to fully vest upon their retirement, which occurred during May and June 2022, respectively. The remaining unrecognized grant date fair value of the original RSUs was recognized over the requisite period. The incremental cost due to the modification was not materially different from the grant date fair value. |
Summary Of Nonvested Restricted Stock Units, Vesting Schedule [Table Text Block] | For the outstanding RSUs issued to the eligible employees as of December 31, 2022, vesting is expected to occur as follows (subject to forfeitures): Restricted Shares 2023 470,750 2024 470,699 2025 280,012 Total 1,221,461 |
Schedule of Nonvested Performance-based Units Activity [Table Text Block] | 2022 2021 Weighted Weighted Average Average Performance Grant Date Fair Performance Grant Date Fair Share Units Value Per Unit Share Units Value Per Unit Nonvested, beginning of period 196,918 $ 5.55 — $ — Granted 1,384,214 10.29 393,073 5.56 Vested (1) (15,264) 5.57 — — Forfeited (63,629) 8.84 (196,155) 5.57 Nonvested, end of period 1,502,239 9.78 196,918 $ 5.55 (1) During May and June 2022, approximately 12,000 outstanding PSUs awarded in 2021 to two individuals retiring from their employment with the Company were modified to fully vest upon their retirement, which occurred during May and June 2022, respectively. The remaining unrecognized grant date fair value of the original PSUs was recognized over the requisite period. The incremental cost due to the modification was not materially different from the grant date fair value. |
Share-based Payment Arrangement, Nonemployee Director Award Plan, Activity [Table Text Block] | 2022 2021 2020 Weighted Weighted Weighted Average Average Average Grant Date Grant Date Grant Date Restricted Fair Value Restricted Fair Value Restricted Fair Value Shares Per Share Shares Per Share Shares Per Share Nonvested, beginning of period 70,226 $ 3.65 154,128 $ 3.64 123,180 $ 4.55 Granted 42,426 4.95 62,502 3.36 109,376 2.56 Vested (70,226) 3.65 (146,404) 3.51 (78,428) 2.38 Nonvested, end of period 42,426 $ 4.95 70,226 $ 3.65 154,128 $ 3.64 |
Share-based Payment Arrangement, Cost by Plan [Table Text Block] | A summary of compensation expense under share-based payment arrangements is as follows (in thousands): Year Ended December 31, 2022 2021 2020 Restricted stock units $ 4,192 $ 2,579 $ 3,555 Performance share units 3,504 412 — Restricted Shares 226 373 404 Total $ 7,922 $ 3,364 $ 3,959 |
Schedule of Incentive Compensation Expense [Table Text Block] | A summary of compensation expense related to share-based awards and cash-based awards is as follows (in thousands): Year Ended December 31, 2022 2021 2020 Share-based compensation included in: General and administrative expenses $ 7,922 $ 3,364 $ 3,959 Cash-based incentive compensation included in: Lease operating expense (1) 3,812 3,500 849 General and administrative expenses (1) 10,697 10,086 4,019 Total charged to operating income (loss) $ 22,431 $ 16,950 $ 8,827 (1) Includes adjustments of accruals to actual payments. |
Performance Share Units [Member] | |
Notes Tables | |
Summary Of Nonvested Restricted Stock Units, Vesting Schedule [Table Text Block] | Performance Shares 2023 161,418 2024 — 2025 1,340,821 Total 1,502,239 |
Schedule of Share-based Payment Award, Equity Instrument Other Than Options, Valuation Assumptions [Table Text Block] | 2022 Grant Date 2021 Grant Date May 26, 2022 June 28, 2021 Expected term for performance period (in years) 2.6 0.5 Expected volatility 84.4 % 67.9 % Risk-free interest rate 2.5 % 0.1 % Fair value (in thousands) $ 14,240 $ 1,852 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Notes Tables | |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | Components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2022 2021 2020 Current $ 8,476 $ 132 $ 134 Deferred 45,184 (8,189) (30,287) Total income tax expense (benefit) $ 53,660 $ (8,057) $ (30,153) |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | The reconciliation of income taxes computed at the U.S. federal statutory tax rate to the Company’s income tax expense (benefit) is as follows (in thousands): Year Ended December 31, 2022 2021 2020 Income tax expense (benefit) at the federal statutory rate $ 59,810 $ (10,402) $ 1,604 Compensation adjustments 599 559 1,373 State income taxes 2,418 (330) 75 Impact of U.S. legislative changes — — (21,345) Valuation allowance (9,117) 1,863 (12,018) Other (50) 253 158 Total income tax expense (benefit) $ 53,660 $ (8,057) $ (30,153) |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | December 31, 2022 2021 Deferred tax liabilities: Property and equipment $ 80,616 $ 55,170 Investment in non-consolidated entity 3,951 4,659 Other 2,948 2,817 Total deferred tax liabilities 87,515 62,646 Deferred tax assets: Derivatives 25,969 21,026 Asset retirement obligations 103,910 91,850 Contingent asset retirement obligations 4,540 980 Right of use liability 2,964 2,976 Federal net operating losses 281 42,127 State net operating losses 5,691 7,612 Interest expense limitation carryover 9,620 18,628 Share-based compensation 1,546 312 Valuation allowance (15,311) (24,359) Other 5,513 3,886 Total deferred tax assets 144,723 165,038 Net deferred tax assets $ 57,208 $ 102,392 |
Summary of Operating Loss Carryforwards [Table Text Block] | The table below presents the details of the Company’s net operating loss and interest expense limitation carryover as of December 31, 2022 (in thousands): Amount Expiration Year Federal net operating loss $ 1,339 N/A State net operating loss 96,054 2026-2041 Interest expense limitation carryover 43,139 N/A |
EARNINGS PER SHARE (Tables)
EARNINGS PER SHARE (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Notes Tables | |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | The following table presents the calculation of basic and diluted earnings per common share (in thousands, except per share amounts): Year Ended December 31, 2022 2021 2020 Net income (loss) $ 231,149 $ (41,478) $ 37,790 Weighted average common shares outstanding - basic 143,143 142,271 141,622 Dilutive effect of securities 1,947 — 1,655 Weighted average common shares outstanding - diluted 145,090 142,271 143,277 Earnings per common share: Basic $ 1.61 $ (0.29) $ 0.26 Diluted $ 1.59 $ (0.29) $ 0.26 Shares excluded due to being anti-dilutive (weighted average) — 1,370 — |
SUPPLEMENTAL CASH FLOW INFORM_2
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Notes Tables | |
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block] | The following table reflects supplemental cash flow information (in thousands): Year Ended December 31, 2022 2021 2020 Supplemental cash items: Cash and cash equivalents $ 461,357 $ 245,799 $ 43,726 Restricted cash and restricted cash equivalents 4,417 4,417 — Cash paid for interest 71,126 64,805 59,183 Cash paid for income taxes 8,198 152 159 Cash refunds received for income taxes — 1 2,007 Cash received for interest income 5,909 112 603 Non-cash investing activities: Accruals of property and equipment 6,636 9,464 3,035 ARO - additions, dispositions and revisions, net 91,652 36,175 17,928 |
SUPPLEMENTAL OIL AND GAS DISC_2
SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Notes Tables | |
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block] | Net capitalized costs related to oil, NGLs and natural gas producing activities are as follows (in thousands): Year Ended December 31, 2022 2021 2020 Net capitalized costs: Proved oil and natural gas properties and equipment $ 8,813,404 $ 8,636,408 $ 8,567,509 Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities (8,088,271) (7,981,271) (7,890,889) Net capitalized costs related to producing activities $ 725,133 $ 655,137 $ 676,620 Depreciation, depletion and amortization ($/Boe) 7.32 6.50 6.34 |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] | The following costs were incurred in oil, NGLs and natural gas property acquisition, exploration, and development activities (in thousands): Year Ended December 31, 2022 2021 2020 Costs incurred: (1) Proved properties acquisitions $ 78,565 $ 2,197 $ 8,118 Exploration (2) 24,498 18,444 7,727 Development 77,282 47,218 23,528 Total costs incurred in oil and gas property acquisition, exploration and development activities $ 180,345 $ 67,859 $ 39,373 (1) Includes net additions from capitalized ARO of $88.8 million, $36.2 million, and $15.2 million during 2022, 2021, and 2020, respectively. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates. (2) Includes seismic costs of $5.6 million, $ 0.1 million, and $0.3 million incurred during 2022, 2021, and 2020, respectively. Includes geological and geophysical costs charged to expense of $5.5 million, $5.7 million, and $4.5 million during 2022, 2021, and 2020, respectively. |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block] | The following sets forth estimated quantities of net proved oil, NGLs and natural gas reserves: NGLs Natural Gas Oil Equivalent Oil (MMBbls) (MMBbls) (Bcf) (MMBoe) Proved reserves as of December 31, 2019 37.8 24.5 571.1 157.4 Revisions of previous estimates (0.9) (5.9) 31.6 (1.4) Extensions and discoveries 0.2 — 0.2 0.2 Purchase of minerals in place 0.7 0.5 14.8 3.6 Sales of minerals in place — — — — Production (5.6) (1.7) (48.4) (15.4) Proved reserves as of December 31, 2020 32.2 17.4 569.3 144.4 Revisions of previous estimates 10.0 3.1 83.0 27.1 Extensions and discoveries — — — — Purchase of minerals in place — — 0.1 — Production (5.0) (1.4) (44.8) (13.9) Proved reserves as of December 31, 2021 37.2 19.1 607.6 157.6 Revisions of previous estimates 4.5 1.2 64.3 16.3 Extensions and discoveries — — — — Purchase of minerals in place 4.5 0.2 7.5 6.0 Production (5.6) (1.6) (44.8) (14.6) Proved reserves as of December 31, 2022 40.6 18.9 634.6 165.3 Year-end proved developed reserves: 2022 31.1 17.6 576.0 144.8 2021 27.6 17.8 549.2 137.0 2020 24.0 16.5 550.2 132.2 Year-end proved undeveloped reserves: 2022 (10) 9.5 1.3 58.6 20.5 2021 9.6 1.3 58.4 20.6 2020 8.2 0.9 19.1 12.2 |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block] | The following presents the standardized measure of discounted future net cash flows related to the Company’s proved oil, NGLs and natural gas reserves together with changes therein (in thousands): Year Ended December 31, 2022 2021 2020 Standardized Measure of Discounted Future Net Cash Flows Future cash inflows $ 8,855,730 $ 5,178,215 $ 2,561,189 Future costs: Production (2,894,652) (2,061,752) (1,257,421) Development and abandonment (990,329) (976,500) (707,357) Income taxes (1,005,917) (358,954) (60,503) Future net cash inflows before 10% discount 3,964,832 1,781,009 535,908 10% annual discount factor (1,701,871) (625,019) (42,202) Total $ 2,262,961 $ 1,155,990 $ 493,706 |
Schedule Of Prices Weighted By Field Production Related To The Proved Reserves [Table Text Block] | December 31, 2022 2021 2020 Oil ($/Bbl) $ 91.50 $ 65.25 $ 37.78 NGLs ($/Bbl) 41.92 26.83 10.29 Natural gas ($/Mcf) 6.85 3.68 2.05 |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] | The change in the standardized measure of discounted future net cash flows relating to the Company’s proved oil, NGLs and natural gas reserves is as follows (in thousands): Year Ended December 31, 2022 2021 2020 Changes in Standardized Measure Standardized measure, beginning of year $ 1,155,990 $ 493,706 $ 986,900 Increases (decreases): Sales and transfers of oil and gas produced, net of production costs (672,665) (370,456) (168,563) Net changes in price, net of future production costs 1,368,626 980,922 (503,676) Extensions and discoveries, net of future production and development costs — — 2,767 Changes in estimated future development costs (18,617) (25,357) (15,881) Previously estimated development costs incurred 3,313 613 1,384 Revisions of quantity estimates 249,117 289,637 (65,218) Accretion of discount 138,077 43,993 111,760 Net change in income taxes (369,307) (181,795) 87,713 Purchases of reserves in-place 225,205 319 44,621 Sales of reserves in-place — — — Changes in production rates due to timing and other 183,222 (75,592) 11,899 Net (decrease) increase 1,106,971 662,284 (493,194) Standardized measure, end of year $ 2,262,961 $ 1,155,990 $ 493,706 |
SIGNIFICANT ACCOUNTING POLICI_4
SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($) | 12 Months Ended | |||||
Mar. 18, 2022 | Apr. 15, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Accounts Receivable, Allowance for Credit Loss, Ending Balance | $ 12,062,000 | $ 10,046,000 | $ 9,123,000 | $ 9,898,000 | ||
Proceeds From Paycheck Protection Program Under Cares Act | $ 8,400,000 | |||||
Gain (Loss) on Extinguishment of Debt, Total | 0 | 0 | 47,469,000 | |||
Proceeds from sale of equity | 16,998,000 | 0 | 0 | |||
Impairment of Oil and Gas Properties | 0 | 0 | 0 | |||
Unproved property | 0 | 0 | ||||
Employee retention credit | $ 0 | 0 | ||||
At The Market Equity Offering [Member] | ||||||
Issuance and sale of common stock | $ 100,000,000 | |||||
Sale of Stock, Maximum Percentage of Placement Fee | 3% | |||||
Stock Issued (in shares) | 2,971,413 | |||||
Share issued price per share | $ 5.72 | |||||
Proceeds from sale of equity | $ 16,500,000 | |||||
W&T Energy VI, LLC, Aquasition LLC, and Aquasition II, LLC [Member] | ||||||
Owned Subsidiaries | 100% | |||||
Senior Second Lien Note Issuance [Member] | ||||||
Extinguishment of Debt, Amount | $ 72,500,000 | |||||
Debt instrument, interest rate, stated percentage | 9.75% | 9.75% | ||||
Gain (Loss) on Extinguishment of Debt, Total | $ 47,500,000 | |||||
Repayments of Long-term Debt | $ 23,900,000 | |||||
Minimum [Member] | Furniture, Fixtures and Non-oil and Natural Gas Property and Equipment [Member] | ||||||
Property, Plant and Equipment, Useful Life (Year) | 5 years | |||||
Maximum [Member] | Furniture, Fixtures and Non-oil and Natural Gas Property and Equipment [Member] | ||||||
Property, Plant and Equipment, Useful Life (Year) | 7 years | |||||
General and Administrative Expense [Member] | ||||||
Employee retention credit | $ 2,100,000 |
SIGNIFICANT ACCOUNTING POLICI_5
SIGNIFICANT ACCOUNTING POLICIES - Percentage of Revenue by Major Customers (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Oil and Gas Sales Payable, Current [Member] | |||
Gas Imbalance | $ 3.5 | $ 3.5 | |
Customer Concentration Risk [Member] | Revenue from Contract with Customer Benchmark [Member] | BP Products North America [Member] | |||
us-gaap_ConcentrationRiskPercentage1 | 31% | 34% | 39% |
Customer Concentration Risk [Member] | Revenue from Contract with Customer Benchmark [Member] | Chevron - Texaco [Member] | |||
us-gaap_ConcentrationRiskPercentage1 | 13% | 14% | |
Customer Concentration Risk [Member] | Revenue from Contract with Customer Benchmark [Member] | Mercuria Energy America Inc. [Member] | |||
us-gaap_ConcentrationRiskPercentage1 | 10% | ||
Customer Concentration Risk [Member] | Revenue from Contract with Customer Benchmark [Member] | Williams Field Services [Member] | |||
us-gaap_ConcentrationRiskPercentage1 | 11% | 13% |
SIGNIFICANT ACCOUNTING POLICI_6
SIGNIFICANT ACCOUNTING POLICIES - Credit Risk and Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Significant Accounting Policies - Credit Risk and Allowance for Doubtful Accounts (Details) | |||
Allowance for credit losses, beginning of period | $ 10,046 | $ 9,123 | $ 9,898 |
Additional provisions for the year | 3,085 | 2,192 | 417 |
Uncollectible accounts written off or collected | (1,069) | (1,269) | (1,192) |
Allowance for credit losses, end of period | $ 12,062 | $ 10,046 | $ 9,123 |
SIGNIFICANT ACCOUNTING POLICI_7
SIGNIFICANT ACCOUNTING POLICIES - Schedule of Amounts Recorded in Prepaid Expenses and Other Assets (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Significant Accounting Policies - Schedule of Amounts Recorded in Prepaid Expenses and Other Assets (Details) | ||
Derivative instruments - current | $ 4,954 | $ 21,086 |
Derivative Asset, Current, Statement of Financial Position [Extensible Enumeration] | Prepaid expenses and other assets | Prepaid expenses and other assets |
Unamortized insurance/bond premiums | $ 6,046 | $ 5,400 |
Prepaid deposits related to royalties | 9,139 | 8,441 |
Prepayment to vendors | 1,767 | 4,522 |
Prepayments to joint interest partners | 1,717 | 2,808 |
Debt issue costs | 687 | 1,065 |
Other | 33 | 57 |
Prepaid expenses and other assets | $ 24,343 | $ 43,379 |
SIGNIFICANT ACCOUNTING POLICI_8
SIGNIFICANT ACCOUNTING POLICIES - Schedule of Oil and Natural Gas Properties and Other, Net at Cost (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Significant Accounting Policies - Schedule of Oil and Natural Gas Properties and Other, Net at Cost (Details) | ||
Oil and natural gas properties and equipment, at cost | $ 8,813,404 | $ 8,636,408 |
Furniture, fixtures and other | 20,915 | 20,844 |
Total property and equipment | 8,834,319 | 8,657,252 |
Less: Accumulated depreciation, depletion, amortization and impairment | (8,099,104) | (7,992,000) |
Oil and natural gas properties and other, net | $ 735,215 | $ 665,252 |
SIGNIFICANT ACCOUNTING POLICI_9
SIGNIFICANT ACCOUNTING POLICIES - Schedule of Other Assets (Long-term) (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Significant Accounting Policies - Schedule of Other Assets (Long-term) (Details) | ||
Right-of-Use assets | $ 10,364 | $ 10,602 |
Investment in White Cap, LLC | 2,453 | 2,533 |
Proportional consolidation of Monza (Note 5) | 9,321 | 2,511 |
Derivatives | $ 23,236 | $ 34,435 |
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Total other assets (long-term) | Total other assets (long-term) |
Other | $ 2,175 | $ 1,091 |
Total other assets (long-term) | $ 47,549 | $ 51,172 |
SIGNIFICANT ACCOUNTING POLIC_10
SIGNIFICANT ACCOUNTING POLICIES - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Significant Accounting Policies - Schedule of Accrued Liabilities (Details) | ||
Accrued interest | $ 8,967 | $ 10,154 |
Accrued salaries/payroll taxes/benefits | 15,097 | 9,617 |
Litigation accruals | 396 | 646 |
Lease liability | $ 1,628 | $ 1,115 |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Accrued liabilities | Accrued liabilities |
Derivative liabilities, current | $ 46,595 | $ 81,456 |
Other | 1,358 | 3,152 |
Accrued liabilities | $ 74,041 | $ 106,140 |
SIGNIFICANT ACCOUNTING POLIC_11
SIGNIFICANT ACCOUNTING POLICIES - Schedule of Other Liabilities (Long-term) (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Significant Accounting Policies - Schedule of Other Liabilities (Long-term) (Details) | ||
Dispute related to royalty deductions | $ 4,937 | $ 5,177 |
Derivative instruments - long-term | 43,061 | 37,989 |
Lease liability, non-current | 10,527 | 11,227 |
Other | 609 | 996 |
Total other liabilities (long-term) | $ 59,134 | $ 55,389 |
DEBT - Components of Long-term
DEBT - Components of Long-term Debt (Details) - USD ($) $ in Thousands | Jan. 27, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | May 19, 2021 | Dec. 31, 2020 | Oct. 18, 2018 |
Principal | $ 700,400 | |||||
Total | 693,437 | $ 730,898 | ||||
Less current portion, net | (582,249) | (42,960) | ||||
Long-term debt, net | 111,188 | 687,938 | ||||
Term Loan [Member] | ||||||
Principal | 147,899 | 190,859 | ||||
Unamortized debt issuance costs | (4,592) | (7,545) | ||||
Total | 143,307 | 183,314 | ||||
Less current portion, net | (582,200) | |||||
Debt instrument, interest rate, stated percentage | 7% | |||||
9.75% Senior Second Lien Notes Due November 2023 [Member] | ||||||
Principal | 552,460 | 552,460 | ||||
Unamortized debt issuance costs | (2,330) | (4,876) | ||||
Total | $ 550,130 | $ 547,584 | ||||
Debt instrument, interest rate, stated percentage | 9.75% | 9.75% | 9.75% | 9.75% | 9.75% |
DEBT - Aggregate annual maturit
DEBT - Aggregate annual maturities (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Long-term Debt, Fiscal Year Maturity [Abstract] | |
2023 | $ 586.2 |
2024 | 30.1 |
2025 | 27.6 |
2026 | 25.4 |
2027 | 22.9 |
Thereafter | 8.2 |
Total | $ 700.4 |
DEBT (Details Textual)
DEBT (Details Textual) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||
Mar. 31, 2022 item | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Feb. 08, 2023 | Jan. 27, 2023 | Nov. 02, 2021 USD ($) | May 19, 2021 USD ($) | Oct. 18, 2018 USD ($) | |
Current portion of long-term debt, net | $ 582,249 | $ 42,960 | |||||||
Principal | 700,400 | ||||||||
Proceeds from sale of equity | 16,998 | 0 | $ 0 | ||||||
Gain (Loss) on Extinguishment of Debt, Total | 0 | 0 | $ 47,469 | ||||||
At The Market Equity Offering [Member] | |||||||||
Proceeds from sale of equity | 16,500 | ||||||||
Term Loan [Member] | |||||||||
Current portion of long-term debt, net | 582,200 | ||||||||
Principal | 147,899 | 190,859 | |||||||
Debt instrument, interest rate, stated percentage | 7% | ||||||||
Debt Instrument, Face Amount | $ 215,000 | ||||||||
Repayments of Long-term Debt, Total | 43,000 | 24,100 | |||||||
Credit Agreement [Member] | |||||||||
Borrowings outstanding | 0 | 0 | |||||||
Repayments of Long-term Debt, Total | 48,000 | ||||||||
Letters of Credit Outstanding, Amount | 4,400 | ||||||||
9.75% Senior Second Lien Notes Due November 2023 [Member] | |||||||||
Principal | $ 552,460 | $ 552,460 | |||||||
Debt instrument, interest rate, stated percentage | 9.75% | 9.75% | 9.75% | 9.75% | 9.75% | ||||
Debt Instrument, Face Amount | $ 625,000 | ||||||||
Debt Instrument, Interest Rate, Effective Percentage | 10.30% | ||||||||
Extinguishment of Debt, Amount | $ 72,500 | ||||||||
Repayments of Long-term Debt, Total | 23,900 | ||||||||
Gain (Loss) on Extinguishment of Debt, Total | 47,500 | ||||||||
Write off of Deferred Debt Issuance Cost | $ 1,100 | ||||||||
9.75% Senior Second Lien Notes Due November 2023 [Member] | Subsequent Event | |||||||||
Debt instrument, interest rate, stated percentage | 9.75% | ||||||||
11.75% Senior Second Lien Notes | |||||||||
Debt instrument, interest rate, stated percentage | 11.75% | ||||||||
Short Term First Priority Lien Secured Revolving Facility [Member] | |||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 100,000 | ||||||||
Calculus Lending Facility [Member] | |||||||||
Letters of Credit Outstanding, Amount | $ 4,400 | 4,400 | |||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 50,000 | $ 50,000 | |||||||
Commitment fee percentage for unused Portion | 3% | ||||||||
Number of trailing quarters | item | 4 | ||||||||
Total proved PV -10 to debt ratio | 2 | ||||||||
Percentage of funding or utilization of the credit facility | 100% | ||||||||
Credit Agreement Leverage Ratio | 2.50 | ||||||||
Credit Agreement Minimum Current Ratio | 1% | ||||||||
Commitment fees | $ 1,500 | $ 1,000 | |||||||
Calculus Lending Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||||||||
Debt Instrument, Basis Spread on Variable Rate | 6% |
FAIR VALUE MEASUREMENTS - Fair
FAIR VALUE MEASUREMENTS - Fair Value of Open Derivative Financial Instruments (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Derivative instruments - current | $ 4,954 | $ 21,086 |
Derivative instruments - long-term | 23,236 | 34,435 |
Derivative instruments - current | 46,595 | 81,456 |
Derivative instruments - long-term | 43,061 | 37,989 |
Open Contracts [Member] | ||
Derivative instruments - current | 4,954 | 21,086 |
Derivative instruments - long-term | 23,236 | 34,435 |
Derivative instruments - current | 46,595 | 81,456 |
Derivative instruments - long-term | $ 43,061 | $ 37,989 |
FAIR VALUE MEASUREMENTS - Net v
FAIR VALUE MEASUREMENTS - Net value and Fair Value of Long-term Debt (Details) - USD ($) $ in Thousands | Jan. 27, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | May 19, 2021 | Dec. 31, 2020 | Oct. 18, 2018 |
Long-term debt, net value | $ 693,437 | $ 730,898 | ||||
Long-term debt, fair value | 683,958 | 718,294 | ||||
Term Loan [Member] | ||||||
Long-term debt, net value | 143,307 | 183,314 | ||||
Long-term debt, fair value | 139,056 | 190,579 | ||||
Debt instrument, interest rate, stated percentage | 7% | |||||
9.75% Senior Second Lien Notes Due November 2023 [Member] | ||||||
Long-term debt, net value | 550,130 | 547,584 | ||||
Long-term debt, fair value | $ 544,902 | $ 527,715 | ||||
Debt instrument, interest rate, stated percentage | 9.75% | 9.75% | 9.75% | 9.75% | 9.75% |
SUBSIDIARY BORROWERS (Details)
SUBSIDIARY BORROWERS (Details) - Term Loan [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | May 19, 2021 | |
Subsidiary or Equity Method Investee [Line Items] | ||
Principal | $ 215 | |
Subsidiary Borrowers | ||
Subsidiary or Equity Method Investee [Line Items] | ||
Principal | $ 215 | |
Cash Distributions Received | $ 30.2 |
SUBSIDIARY BORROWERS - Consolid
SUBSIDIARY BORROWERS - Consolidation of Subsidiary Borrowers (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Assets: | |||
Cash and cash equivalents | $ 461,357 | $ 245,799 | $ 43,726 |
Receivables: | |||
Oil and natural gas sales | 66,146 | 54,919 | |
Joint interest, net | 14,000 | 9,745 | |
Prepaid expenses and other assets | 24,343 | 43,379 | |
Oil and natural gas properties and other, net | 735,215 | 665,252 | |
Other assets | 47,549 | 51,172 | |
Liabilities: | |||
Accounts payable | 65,158 | 67,409 | |
Undistributed oil and natural gas proceeds | 41,934 | 36,243 | |
Accrued liabilities | 74,041 | 106,140 | |
Current portion of long-term debt, net | 582,249 | 42,960 | |
Long-term debt, net | 111,188 | 687,938 | |
Asset Retirement Obligations | 25,359 | 56,419 | |
Other liabilities | 59,134 | 55,389 | |
Term Loan [Member] | |||
Liabilities: | |||
Current portion of long-term debt, net | 582,200 | ||
Subsidiary Borrowers | |||
Assets: | |||
Cash and cash equivalents | 21,764 | 38,937 | |
Receivables: | |||
Oil and natural gas sales | 37,344 | 34,420 | |
Joint interest, net | (5,760) | (10,856) | |
Prepaid expenses and other assets | 417 | 356 | |
Oil and natural gas properties and other, net | 280,649 | 272,747 | |
Other assets | 8,473 | (19,903) | |
Liabilities: | |||
Accounts payable | 27,387 | 29,678 | |
Undistributed oil and natural gas proceeds | 7,930 | 3,144 | |
Accrued liabilities | 45,102 | 29,937 | |
Current portion of long-term debt, net | 32,119 | 42,960 | |
Long-term debt, net | 111,188 | 140,353 | |
Asset Retirement Obligations | 61,138 | 54,515 | |
Other liabilities | $ 47,398 | $ 42,615 |
SUBSIDIARY BORROWERS - Subsidia
SUBSIDIARY BORROWERS - Subsidiary Borrowers and Subsidiary Owns Equity (Details) - USD ($) $ in Thousands | 7 Months Ended | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Subsidiary or Equity Method Investee [Line Items] | ||||
Total revenues | $ 920,997 | $ 558,010 | $ 346,634 | |
Total operating expenses | 466,919 | 368,348 | 345,833 | |
Interest expense, net | 69,441 | 70,049 | 61,463 | |
Derivative loss (gain) | 85,533 | $ 175,313 | $ (23,808) | |
Subsidiary Borrowers | ||||
Subsidiary or Equity Method Investee [Line Items] | ||||
Total revenues | $ 119,550 | 268,573 | ||
Total operating expenses | 32,735 | 73,990 | ||
Interest expense, net | 9,782 | 14,721 | ||
Derivative loss (gain) | $ 104,533 | $ 141,736 |
JOINT VENTURE DRILLING PROGRA_2
JOINT VENTURE DRILLING PROGRAM (Details Textual) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Mar. 31, 2018 USD ($) item | Dec. 31, 2022 USD ($) item | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Asset Retirement Obligation, Ending Balance | $ 466,430 | $ 424,495 | $ 392,704 | |
JV Drilling Program [Member] | ||||
Number of wells completed | item | 10 | |||
Number of wells producing | item | 6 | |||
Number of completed wells in operation | item | 8 | |||
Capital Contribution Payments From Related Party | $ 68,200 | |||
Capital Contributions From Related Party During Period | 35,700 | |||
JV Drilling Program [Member] | Mr. Tracy W. Krohn [Member] | ||||
Minority Interest Ownership Percentage By Joint Venture | 4.5 | |||
Monza Energy, LLC [Member] | ||||
Cash Call Balance | 2,900 | $ 14,800 | ||
Monza Energy, LLC [Member] | JV Drilling Program [Member] | ||||
Number of initial members | item | 2 | |||
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 | |||
Well Cost Percent | 20 | |||
Capital Contribution Payments From Related Party | 302,400 | |||
Capital Contributions From Related Party During Period | $ 166,000 | |||
Monza Energy, LLC [Member] | JV Drilling Program [Member] | Mr. Tracy W. Krohn [Member] | ||||
Capital Commitment To Joint Venture | $ 14,500 |
JOINT VENTURE DRILLING PROGRA_3
JOINT VENTURE DRILLING PROGRAM - Condensed Consolidated Balance Sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Oil and natural gas properties and other, net | $ 735,215 | $ 665,252 |
Asset Retirement Obligations | 25,359 | 56,419 |
Other assets | 47,549 | 51,172 |
Other liabilities | 59,134 | 55,389 |
Monza Energy, LLC [Member] | ||
Working capital | 2,515 | 4,648 |
Oil and natural gas properties and other, net | 37,260 | 45,510 |
Asset Retirement Obligations | 467 | 301 |
Other assets | $ 11,571 | $ 2,511 |
JOINT VENTURE DRILLING PROGRA_4
JOINT VENTURE DRILLING PROGRAM - Condensed Consolidated Statement of Operations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Total revenues | $ 920,997 | $ 558,010 | $ 346,634 |
Derivative loss | (85,533) | (175,313) | $ 23,808 |
Monza Energy, LLC [Member] | |||
Total revenues | 28,803 | 12,716 | |
Total operating expenses | 13,523 | 10,044 | |
Derivative loss | $ 2,096 | ||
Interest income | $ 42 |
ACQUISITIONS (Details)
ACQUISITIONS (Details) - USD ($) $ in Thousands | Apr. 01, 2022 | Feb. 01, 2022 | Jan. 05, 2022 | Dec. 31, 2022 | Dec. 31, 2021 |
Asset Acquisition [Line Items] | |||||
Oil and natural gas properties and other, net | $ 735,215 | $ 665,252 | |||
Restricted deposits for asset retirement obligations | 21,483 | 16,019 | |||
Current liabilities | 792,334 | 324,376 | |||
Asset retirement obligations | $ (25,359) | $ (56,419) | |||
Interests in and Operatorship of Certain Oil and Natural Gas Producing Properties [Member] | |||||
Asset Acquisition [Line Items] | |||||
Total consideration | $ 47,000 | ||||
Cash consideration | $ 17,500 | $ 34,000 | |||
Oil and natural gas properties and other, net | 22,632 | 54,299 | |||
Restricted deposits for asset retirement obligations | 1,549 | 6,196 | |||
Asset retirement obligations | (6,709) | (26,493) | |||
Allocated purchase price | $ 17,472 | $ 34,002 |
ASSET RETIREMENT OBLIGATIONS -
ASSET RETIREMENT OBLIGATIONS - Changes to Asset Retirement Obligation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Asset Retirement Obligations - Changes to Asset Retirement Obligation (Details) | |||
Asset retirement obligations, beginning of period | $ 424,495 | $ 392,704 | |
Liabilities settled | (76,225) | (27,309) | |
Accretion expense | 26,508 | 22,925 | $ 22,521 |
Liabilities acquired | 33,202 | 454 | |
Liabilities incurred | 138 | ||
Revisions of estimated liabilities | 58,312 | 35,721 | |
Asset retirement obligations, end of period | 466,430 | 424,495 | $ 392,704 |
Less: Current portion | (25,359) | (56,419) | |
Long-term | $ 441,071 | $ 368,076 |
LEASES - Lease Cost (Details)
LEASES - Lease Cost (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Note 8 - Leases - Lease Cost (Details) | ||||
Operating lease costs, excluding short-term leases | $ 1,579 | $ 1,743 | $ 3,060 | |
Short-term lease cost (1) | [1] | 2,957 | 5,926 | 1,633 |
Variable lease cost (2) | [2] | 647 | ||
Total lease cost | $ 5,183 | $ 7,669 | $ 4,693 | |
[1] Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a right-of-use asset and lease liability on the balance sheet. The majority of such costs are recorded within Oil and natural gas properties and other, net , on the Consolidated Balance Sheet. Variable lease costs primarily represent differences between minimum lease payment obligations and actual operating charges incurred by the Company related to long-term operating leases. |
LEASES - Lessee Assets and Liab
LEASES - Lessee Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Note 8 - Leases - Lessee Assets and Liabilities (Details) | ||
Right-of-Use assets | $ 10,364 | $ 10,602 |
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Other assets (Note 1) | Other assets (Note 1) |
Lease liability | $ 1,628 | $ 1,115 |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Accrued Liabilities, Current | Accrued Liabilities, Current |
Lease liability, non-current | $ 10,527 | $ 11,227 |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Other liabilities (Note 1) | Other liabilities (Note 1) |
Total lease liability | $ 12,155 | $ 12,342 |
LEASES - Weighted Average Remai
LEASES - Weighted Average Remaining Lease Term and Discount Rate (Details) | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Note 8 - Leases - Weighted Average Remaining Lease Term and Discount Rate (Details) | |||
Weighted average remaining lease term: (Year) | 13 years 1 month 6 days | 14 years 1 month 6 days | 14 years 9 months 18 days |
Weighted average discount rate: | 10.10% | 10.10% | 10.20% |
LEASES - Supplemental Cash Flow
LEASES - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Note 8 - Leases - Supplemental Cash Flow Information (Details) | |||
Operating cash outflow from operating leases | $ 1,224 | $ 425 | $ 1,825 |
Right-of-use assets obtained in exchange for new operating lease liabilities | $ 5,142 |
LEASES - Undiscounted Future Mi
LEASES - Undiscounted Future Minimum Payment (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Note 8 - Leases - Undiscounted Future Minimum Payment (Details) | ||
2023 | $ 1,628 | |
2024 | 2,026 | |
2025 | 1,514 | |
2026 | 1,545 | |
2027 | 1,576 | |
Thereafter | 14,242 | |
Total lease payments | 22,531 | |
Present value adjustment | (10,376) | |
Total | $ 12,155 | $ 12,342 |
RESTRICTED DEPOSITS FOR ARO - N
RESTRICTED DEPOSITS FOR ARO - Narrative (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended |
Jun. 30, 2022 | Dec. 31, 2021 | |
Transfer of Escrow Deposit into Cash | $ 11.1 | |
Other Non-operating Income Expense from Asset Retirement Obligation | $ 11.1 | |
South Marsh Island 73 [Member] | ||
Proceeds Received to Cover Future Asset Retirement Obligations | $ 7.8 |
RESTRICTED DEPOSITS FOR ARO (De
RESTRICTED DEPOSITS FOR ARO (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 | |
Restricted deposits for asset retirement obligations | $ 21,483 | $ 16,019 | |
Main Pass 283/Viosca Knoll 734 [Member] | |||
Restricted deposits for asset retirement obligations | [1] | 13,684 | 13,663 |
Eugene Island 205/89 [Member] | |||
Restricted deposits for asset retirement obligations | [2] | 1,880 | |
South Marsh Island 73 [Member] | |||
Restricted deposits for asset retirement obligations | [3] | 7,753 | |
Other [Member] | |||
Restricted deposits for asset retirement obligations | $ 47 | $ 477 | |
[1] In connection with a prior period acquisition of the Main Pass 283 and Viosca Knoll 734 fields, the Company received funds from the previous operator to cover future asset retirement obligations for those fields. The Company is not obligated to contribute additional amounts to these escrowed accounts. In connection with a prior period acquisition of the Eugene Island 205 and 89 fields, the Company received funds from the previous owner to cover future asset retirement obligations for those fields. As of December 31, 2022, the Company has performed the related plugging and abandonment work at both fields. During the first and second quarter of 2022, the Company acquired the South Marsh Island 73 field. As part of the transaction, the Company received a total of $7.8 million from the previous owners to cover future asset retirement obligations. The Company is not obligated to contribute additional amounts to this escrowed account. See Note 6 - Acquisitions for additional information. |
DERIVATIVE FINANCIAL INSTRUME_3
DERIVATIVE FINANCIAL INSTRUMENTS - Summary of Open Commodity Derivative Contracts (Details) | 12 Months Ended |
Dec. 31, 2022 item MMBTU $ / MMBTU | |
NYMEX Natural Gas Henry Hub Call | Jan 2023 - Dec 2023 | |
Average daily volume | MMBTU | 70,000 |
Total Volumes | item | 25,550,000 |
NYMEX Natural Gas Henry Hub Call | Jan 2023 - Dec 2023 | Call Option | |
Weighted Price (in dollars per share) | $ / MMBTU | 7.50 |
NYMEX Natural Gas Henry Hub Call | Jan 2024 - Dec 2024 | |
Average daily volume | MMBTU | 65,000 |
Total Volumes | item | 23,790,000 |
NYMEX Natural Gas Henry Hub Call | Jan 2024 - Dec 2024 | Call Option | |
Weighted Price (in dollars per share) | $ / MMBTU | 6.13 |
NYMEX Natural Gas Henry Hub Call | Jan 2025 - Mar 2025 | |
Average daily volume | MMBTU | 62,000 |
Total Volumes | item | 5,580,000 |
NYMEX Natural Gas Henry Hub Call | Jan 2025 - Mar 2025 | Call Option | |
Weighted Price (in dollars per share) | $ / MMBTU | 5.50 |
NYMEX Natural Gas Henry Hub Swap | Jan 2024 - Dec 2024 | |
Average daily volume | MMBTU | 72,329 |
Total Volumes | item | 26,400,000 |
Weighted Price (in dollars per share) | $ / MMBTU | 2.48 |
NYMEX Natural Gas Henry Hub Swap | Jan 2024 - Dec 2024 | |
Average daily volume | MMBTU | 65,574 |
Total Volumes | item | 24,000,000 |
Weighted Price (in dollars per share) | $ / MMBTU | 2.46 |
NYMEX Natural Gas Henry Hub Swap | Jan 2025 - Mar 2025 | |
Average daily volume | MMBTU | 63,333 |
Total Volumes | item | 5,700,000 |
Weighted Price (in dollars per share) | $ / MMBTU | 2.72 |
NYMEX Natural Gas Henry Hub Put | Apr 2025 - Dec 2025 | |
Average daily volume | MMBTU | 62,182 |
Total Volumes | item | 17,100,000 |
NYMEX Natural Gas Henry Hub Put | Apr 2025 - Dec 2025 | Put Option | |
Weighted Price (in dollars per share) | $ / MMBTU | 2.27 |
NYMEX Natural Gas Henry Hub Put | Jan 2026 - Dec 2026 | |
Average daily volume | MMBTU | 55,890 |
Total Volumes | item | 20,400,000 |
NYMEX Natural Gas Henry Hub Put | Jan 2026 - Dec 2026 | Put Option | |
Weighted Price (in dollars per share) | $ / MMBTU | 2.35 |
NYMEX Natural Gas Henry Hub Put | Jan 2027 - Dec 2027 | |
Average daily volume | MMBTU | 52,603 |
Total Volumes | item | 19,200,000 |
NYMEX Natural Gas Henry Hub Put | Jan 2027 - Dec 2027 | Put Option | |
Weighted Price (in dollars per share) | $ / MMBTU | 2.37 |
NYMEX Natural Gas Henry Hub Put | Jan 2028 - Apr 2028 | |
Average daily volume | MMBTU | 49,587 |
Total Volumes | item | 6,000,000 |
NYMEX Natural Gas Henry Hub Put | Jan 2028 - Apr 2028 | Put Option | |
Weighted Price (in dollars per share) | $ / MMBTU | 2.50 |
DERIVATIVE FINANCIAL INSTRUME_4
DERIVATIVE FINANCIAL INSTRUMENTS - Fair Value of Open and Closed Contracts Which Had Not Yet Settled (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Derivatives asset, current | $ 4,954 | $ 21,086 |
Derivative Asset, Current, Statement of Financial Position [Extensible Enumeration] | Prepaid expenses and other assets (Note 1) | Prepaid expenses and other assets (Note 1) |
Derivative assets, non-current | $ 23,236 | $ 34,435 |
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Other assets (Note 1) | Other assets (Note 1) |
Derivative liabilities, current | $ 46,595 | $ 81,456 |
Derivative liabilities, non-current | $ 43,061 | $ 37,989 |
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Other liabilities (Note 1) | Other liabilities (Note 1) |
Open Contracts and Closed Contracts Which Had Not Yet Been Settled [Member] | ||
Derivatives asset, current | $ 4,954 | $ 21,086 |
Derivative Asset, Current, Statement of Financial Position [Extensible Enumeration] | Prepaid expenses and other assets (Note 1) | Prepaid expenses and other assets (Note 1) |
Derivative assets, non-current | $ 23,236 | $ 34,435 |
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Other assets (Note 1) | Other assets (Note 1) |
Derivative liabilities, current | $ 46,595 | $ 81,456 |
Derivative Liability, Current, Statement of Financial Position [Extensible Enumeration] | Accrued Liabilities, Current | Accrued Liabilities, Current |
Derivative liabilities, non-current | $ 43,061 | $ 37,989 |
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Other liabilities (Note 1) | Other liabilities (Note 1) |
DERIVATIVE FINANCIAL INSTRUME_5
DERIVATIVE FINANCIAL INSTRUMENTS - Change in fair value and settlement contract (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Derivative Financial Instruments | |||
Realized loss (gain) | $ 125,089 | $ 95,187 | $ (33,415) |
Unrealized (gain) loss | (39,556) | 80,126 | 9,607 |
Derivative loss (gain) | 85,533 | $ 175,313 | $ (23,808) |
Realized gain through restructuring of strike prices | $ 138,000 |
DERIVATIVE FINANCIAL INSTRUME_6
DERIVATIVE FINANCIAL INSTRUMENTS - Cash Receipts on Commodity Derivative Contract Settlements (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Derivative Financial Instruments | |||
Derivative loss (gain) | $ 85,533 | $ 175,313 | $ (23,808) |
Derivative cash (payments) receipts, net | (41,880) | (81,298) | $ 45,196 |
Derivative cash premium payments | (46,111) | $ (40,484) | |
Cash receipts related to natural gas call contracts through restructuring of strike prices | $ 105,300 |
SHARE-BASED AWARDS AND CASH B_3
SHARE-BASED AWARDS AND CASH BASED AWARDS (Details Textual) $ in Millions | 2 Months Ended | 12 Months Ended | ||
Jun. 30, 2022 employee shares | Dec. 31, 2022 USD ($) shares | Dec. 31, 2021 USD ($) shares | Dec. 31, 2020 USD ($) shares | |
Granted, units (in shares) | shares | 12,000 | |||
Cash Based Discretionary Incentive Compensation | $ 11.9 | |||
Amended and Restated Incentive Plan [Member] | ||||
Cash Based Awards Granted In Period | shares | 0 | |||
Restricted Stock Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant (in shares) | shares | 9,595,681 | |||
Conversion ratio | 1 | |||
Granted, units (in shares) | shares | 22,000 | 984,394 | 710,441 | 0 |
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other than Options, Granted in Period, Grant Date Fair Value | $ 6.1 | $ 3.3 | $ 0 | |
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Grant Date Fair Value | $ 1.9 | $ 2.4 | $ 2 | |
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period (Year) | 3 years | |||
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total | $ 2.4 | |||
Number of employees retired | employee | 2 | |||
Restricted Stock [Member] | ||||
Granted, units (in shares) | shares | 42,426 | 62,502 | 109,376 | |
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other than Options, Granted in Period, Grant Date Fair Value | $ 0.2 | $ 0.2 | $ 0.3 | |
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Grant Date Fair Value | $ 0.4 | $ 0.5 | 0.2 | |
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period (Year) | 1 year | |||
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total | $ 0.1 | |||
Restricted Stock [Member] | Directors Compensation Plan [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant (in shares) | shares | 368,316 | |||
Performance Share Units [Member] | ||||
Granted, units (in shares) | shares | 1,384,214 | 393,073 | ||
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other than Options, Granted in Period, Grant Date Fair Value | 0 | |||
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Grant Date Fair Value | $ 0.1 | $ 0 | $ 0 | |
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total | $ 9.9 | |||
Performance period | 3 years | 1 year | ||
First Short-term Cash-Based Incentive Compensation [Member] | ||||
Cash Based Discretionary Incentive Compensation | $ 7 | |||
Second Short-term Cash-Based Incentive Compensation [Member] | ||||
Cash Based Discretionary Incentive Compensation | 2.1 | $ 6.4 | ||
Long-term Cash-Based Incentive Compensation [Member] | ||||
Fair value of awards | 1.1 | |||
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total | $ 0.4 | |||
Cash Based Awards Granted In Period | shares | 0 | |||
Performance period | 1 year | |||
Cash-based incentive compensation | $ 0.5 | $ 0.2 |
SHARE-BASED AWARDS AND CASH B_4
SHARE-BASED AWARDS AND CASH BASED AWARDS - Summary of Share Activity Related to Restricted Stock Units (Details) - $ / shares | 2 Months Ended | 12 Months Ended | ||
Jun. 30, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Granted, units (in shares) | 12,000 | |||
Restricted Stock Units [Member] | ||||
Nonvested, beginning of period (in shares) | 698,465 | 763,688 | 1,614,722 | |
Nonvested, beginning of period, weighted average grant date fair value per unit (in dollars per share) | $ 4.71 | $ 4.51 | $ 5.73 | |
Granted, units (in shares) | 22,000 | 984,394 | 710,441 | 0 |
Granted, weighted average grant date fair value per unit (in dollars per share) | $ 6.24 | $ 4.71 | ||
Vested, units (in shares) | (387,285) | (731,095) | (787,203) | |
Vested, weighted average grant date fair value per unit (in dollars per share) | $ 5.20 | $ 4.51 | $ 6.90 | |
Forfeited, units (in shares) | (74,113) | (44,569) | (63,831) | |
Forfeited, weighted average grant date fair value per unit (in dollars per share) | $ 5.24 | $ 4.50 | $ 5.80 | |
Nonvested, end of period (in shares) | 1,221,461 | 698,465 | 763,688 | |
Nonvested, end of period, weighted average grant date fair value per unit (in dollars per share) | $ 5.76 | $ 4.71 | $ 4.51 |
SHARE-BASED AWARDS AND CASH B_5
SHARE-BASED AWARDS AND CASH BASED AWARDS - Schedule of Outstanding Restricted Shares and PSU's Issued to Non-employee Directors (Details) - shares | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Restricted Stock Units [Member] | ||||
Awards expected to vest by period (in shares) | 1,221,461 | 698,465 | 763,688 | 1,614,722 |
Restricted Stock Units [Member] | Vesting in 2023 [Member] | ||||
Awards expected to vest by period (in shares) | 470,750 | |||
Restricted Stock Units [Member] | Vesting in 2024 [Member] | ||||
Awards expected to vest by period (in shares) | 470,699 | |||
Restricted Stock Units [Member] | Vesting in 2025 [Member] | ||||
Awards expected to vest by period (in shares) | 280,012 | |||
Performance Share Units [Member] | ||||
Awards expected to vest by period (in shares) | 1,502,239 | 196,918 | ||
Performance Share Units [Member] | Vesting in 2023 [Member] | ||||
Awards expected to vest by period (in shares) | 161,418 | |||
Performance Share Units [Member] | Vesting in 2025 [Member] | ||||
Awards expected to vest by period (in shares) | 1,340,821 |
SHARE-BASED AWARDS AND CASH B_6
SHARE-BASED AWARDS AND CASH BASED AWARDS - Summary of Share Activity Related to Performance Share Units (Details) - $ / shares | 2 Months Ended | 12 Months Ended | |
Jun. 30, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Granted, units (in shares) | 12,000 | ||
Performance Share Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Nonvested, beginning of period (in shares) | 196,918 | ||
Nonvested, beginning of period, weighted average grant date fair value per unit (in dollars per share) | $ 5.55 | ||
Granted, units (in shares) | 1,384,214 | 393,073 | |
Granted, weighted average grant date fair value per unit (in dollars per share) | $ 10.29 | $ 5.56 | |
Vested, units (in shares) | (15,264) | ||
Vested, weighted average grant date fair value per unit (in dollars per share) | $ 5.57 | ||
Forfeited, units (in shares) | (63,629) | (196,155) | |
Forfeited, weighted average grant date fair value per unit (in dollars per share) | $ 8.84 | $ 5.57 | |
Nonvested, end of period (in shares) | 1,502,239 | 196,918 | |
Nonvested, end of period, weighted average grant date fair value per unit (in dollars per share) | $ 9.78 | $ 5.55 |
SHARE-BASED AWARDS AND CASH B_7
SHARE-BASED AWARDS AND CASH BASED AWARDS - Summary of Assumptions Used to Calculate Fair Value of PSUs granted (Details) - Performance Share Units [Member] - USD ($) $ in Thousands | May 26, 2022 | Jun. 28, 2021 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Expected term for performance period (in years) | 2 years 7 months 6 days | 6 months |
Expected volatility | 84.40% | 67.90% |
Risk-free interest rate | 2.50% | 0.10% |
Fair value | $ 14,240 | $ 1,852 |
SHARE-BASED AWARDS AND CASH B_8
SHARE-BASED AWARDS AND CASH BASED AWARDS - Summary of Restricted Stock Activity (Details) - $ / shares | 2 Months Ended | 12 Months Ended | ||
Jun. 30, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Granted, units (in shares) | 12,000 | |||
Restricted Stock [Member] | ||||
Nonvested, beginning of period (in shares) | 70,226 | 154,128 | 123,180 | |
Nonvested, beginning of period, weighted average grant date fair value per unit (in dollars per share) | $ 3.65 | $ 3.64 | $ 4.55 | |
Granted, units (in shares) | 42,426 | 62,502 | 109,376 | |
Granted, weighted average grant date fair value per unit (in dollars per share) | $ 4.95 | $ 3.36 | $ 2.56 | |
Vested, units (in shares) | (70,226) | (146,404) | (78,428) | |
Vested, weighted average grant date fair value per unit (in dollars per share) | $ 3.65 | $ 3.51 | $ 2.38 | |
Nonvested, end of period (in shares) | 42,426 | 70,226 | 154,128 | |
Nonvested, end of period, weighted average grant date fair value per unit (in dollars per share) | $ 4.95 | $ 3.65 | $ 3.64 |
SHARE-BASED AWARDS AND CASH B_9
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Share-based compensation expense | $ 7,922 | $ 3,364 | $ 3,959 |
Restricted Stock Units [Member] | |||
Share-based compensation expense | 4,192 | 2,579 | 3,555 |
Performance Share Units [Member] | |||
Share-based compensation expense | 3,504 | 412 | |
Restricted Stock [Member] | |||
Share-based compensation expense | $ 226 | $ 373 | $ 404 |
SHARE-BASED AWARDS AND CASH _10
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Share-based compensation expense | $ 7,922 | $ 3,364 | $ 3,959 |
Total charged to operating income (loss) | 22,431 | 16,950 | 8,827 |
General and Administrative Expense [Member] | |||
Share-based compensation expense | 7,922 | 3,364 | 3,959 |
Total charged to operating income (loss) | 10,697 | 10,086 | 4,019 |
Lease Operating Expense [Member] | |||
Cash-based incentive compensation | $ 3,812 | $ 3,500 | $ 849 |
EMPLOYEE BENEFIT PLAN (Details)
EMPLOYEE BENEFIT PLAN (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Note To Financial Statement Details Textual | |||
Defined Contribution Plan, Employer Matching Contribution, Percent of Match | 100% | ||
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent | 6% | ||
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage | 20% | ||
Defined Contribution Plan, Cost | $ 2.4 | $ 2 | $ 2.3 |
INCOME TAXES (Details)
INCOME TAXES (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Note To Financial Statement Details Textual | |||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21% | 21% | 21% |
Effective Income Tax Rate Reconciliation, Percent, Total | 18.80% | 16.30% | |
Deferred Tax Assets, Valuation Allowance, Total | $ 15,311 | $ 24,359 | |
Federal tax paid | 8,198 | $ 152 | $ 159 |
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount | $ (9,000) |
INCOME TAXES - Components of In
INCOME TAXES - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Note 13 - Income Taxes - Components of Income Tax Expense (Benefit) (Details) | |||
Current | $ 8,476 | $ 132 | $ 134 |
Deferred | 45,184 | (8,189) | (30,287) |
Total income tax expense (benefit) | $ 53,660 | $ (8,057) | $ (30,153) |
INCOME TAXES - Reconciliation o
INCOME TAXES - Reconciliation of Income Taxes Computed to Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Note 13 - Income Taxes - Reconciliation of Income Taxes Computed to Income Tax Expense (Benefit) (Details) | |||
Income tax expense (benefit) at the federal statutory rate, amount | $ 59,810 | $ (10,402) | $ 1,604 |
Compensation adjustments, amount | 599 | 559 | 1,373 |
State income taxes, amount | 2,418 | (330) | 75 |
Impact of U.S. legislative changes | (21,345) | ||
Valuation allowance, amount | (9,117) | 1,863 | (12,018) |
Other, amount | (50) | 253 | 158 |
Total income tax expense (benefit) | $ 53,660 | $ (8,057) | $ (30,153) |
INCOME TAXES - Significant Comp
INCOME TAXES - Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Deferred tax liabilities: | ||
Property and equipment | $ 80,616 | $ 55,170 |
Investment in non-consolidated entity | 3,951 | 4,659 |
Other | 2,948 | 2,817 |
Total deferred tax liabilities | 87,515 | 62,646 |
Deferred tax assets: | ||
Derivatives | 25,969 | 21,026 |
Asset retirement obligations | 103,910 | 91,850 |
Contingent asset retirement obligations | 4,540 | 980 |
Right of use liability | 2,964 | 2,976 |
Federal net operating losses | 281 | 42,127 |
State net operating losses | 5,691 | 7,612 |
Interest expense limitation carryover | 9,620 | 18,628 |
Share-based compensation | 1,546 | 312 |
Valuation allowance | (15,311) | (24,359) |
Other | 5,513 | 3,886 |
Total deferred tax assets | 144,723 | 165,038 |
Net deferred tax assets | $ 57,208 | $ 102,392 |
INCOME TAXES - Net Operating Lo
INCOME TAXES - Net Operating Loss, Interest and Tax Credit Carryovers (Details) $ in Thousands | Dec. 31, 2022 USD ($) |
Net operating loss, amount | $ 43,139 |
Domestic Tax Authority [Member] | |
Net operating loss, amount | 1,339 |
State and Local Jurisdiction [Member] | |
Net operating loss, amount | $ 96,054 |
EARNINGS PER SHARE - Schedule o
EARNINGS PER SHARE - Schedule of Basic and Diluted (Loss) Earnings Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
EARNINGS PER SHARE - Schedule of Basic and Diluted (Loss) Earnings Per Common Share (Details) | |||
Net income (loss) | $ 231,149 | $ (41,478) | $ 37,790 |
Weighted average common shares outstanding - basic (in shares) | 143,143 | 142,271 | 141,622 |
Dilutive effect of securities (in shares) | 1,947 | 1,655 | |
Weighted average common shares outstanding - diluted (in shares) | 145,090 | 142,271 | 143,277 |
Earnings per common share - Basic (in dollars per share) | $ 1.61 | $ (0.29) | $ 0.26 |
Earnings per common share - Diluted (in dollars per share) | $ 1.59 | $ (0.29) | $ 0.26 |
Shares excluded due to being anti-dilutive (weighted-average) (in shares) | 1,370 |
SUPPLEMENTAL CASH FLOW INFORM_3
SUPPLEMENTAL CASH FLOW INFORMATION - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Supplemental cash items: | |||
Cash and cash equivalents | $ 461,357 | $ 245,799 | $ 43,726 |
Restricted cash and restricted cash equivalents | 4,417 | 4,417 | |
Cash paid for interest | 71,126 | 64,805 | 59,183 |
Cash paid for income taxes | 8,198 | 152 | 159 |
Cash refunds received for income taxes | 1 | 2,007 | |
Cash received for interest income | 5,909 | 112 | 603 |
Non-cash investing activities: | |||
Accruals of property and equipment | 6,636 | 9,464 | 3,035 |
ARO - additions, dispositions and revisions, net | $ 91,652 | $ 36,175 | $ 17,928 |
COMMITMENTS (Details)
COMMITMENTS (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Expense Relating To Surety Bonds Paid | $ 8,300 | $ 6,000 | $ 5,400 |
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. | 100,400 | ||
Escrow Deposit | 0 | ||
Bonding Requirement Related to Purchase of Properties Amount, Fifth Anniversary. | 103,000 | ||
Surety Bonds [Member] | Exxon [Member] | |||
Bonding Requirement, Related To Purchase of Properties Minimum Amount | 36,300 | ||
Other Commitment, Fiscal Year Maturity [Abstract] | |||
2023 | 40,000 | ||
2024 | 44,000 | ||
2025 | 48,300 | ||
2026 | 53,200 | ||
2027 | 58,500 | ||
Thereafter | 114,000 | ||
Surety Bonds [Member] | Exxon [Member] | Minimum [Member] | |||
Annual Increase In Other Commitment | 5,900 | ||
Surety Bonds [Member] | Exxon [Member] | Maximum [Member] | |||
Annual Increase In Other Commitment | 10,400 | ||
Surety Bonds [Member] | Conoco [Member] | |||
Bonding Requirement, Related To Purchase of Properties Minimum Amount | 49,000 | ||
Heidelberg Field [Member] | |||
Other Commitment Expense | $ 1,600 | $ 2,100 | $ 4,500 |
RELATED PARTIES (Details)
RELATED PARTIES (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2018 | |
Debt issuance costs and other | $ 1,675 | $ 9,810 | $ 0 | |
Maximum | ||||
Related party transaction, administrative costs | $ 100 | |||
Senior Second Lien Note Issuance [Member] | ||||
Debt instrument, interest rate, stated percentage | 9.75% | 9.75% | ||
Calculus Lending Facility [Member] | ||||
Commitment fees | $ 1,500 | 1,000 | ||
Commitment fee percentage for unused Portion | 3% | |||
Airplane Services [Member] | ||||
Related Party Transaction, Amounts of Transaction | $ 1,700 | 600 | $ 300 | |
Marine Transportation and Logistic Services [Member] | ||||
Related Party Transaction, Amounts of Transaction | 100 | 100 | 100 | |
Repayments of Related Party Debt | 20,000 | 12,000 | $ 14,400 | |
CEO and Largest Shareholder [Member] | Senior Second Lien Note Issuance [Member] | ||||
Debt Instrument, Face Amount | $ 8,000 | |||
Debt instrument, interest rate, stated percentage | 9.75% | |||
CEO and Largest Shareholder [Member] | Calculus Lending Facility [Member] | ||||
Debt issuance costs and other | 1,100 | 800 | ||
Legal Fees | $ 100 | $ 200 |
CONTINGENCIES (Details)
CONTINGENCIES (Details) | 1 Months Ended | ||||
Jan. 31, 2021 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Jul. 25, 2017 USD ($) | Dec. 31, 2010 USD ($) | |
Additional Royalty Due To Disallowed Deductions | $ 15,400,000 | $ 4,500,000 | $ 4,700,000 | ||
Bonds Posted To Appeal IBLA Decision | $ 7,200,000 | ||||
Collateral For Bonds Posted Related To Appeal With IBLA | $ 8,500,000 | $ 6,900,000 | |||
BSEE [Member] | |||||
Loss Contingency Number Of Claims Filed | 9 | ||||
Proposed Civil Penalties | $ 7,700,000 | ||||
Settlement Agreement Annual Instalments Value | $ 720,000 |
SUPPLEMENTAL OIL AND GAS DISC_3
SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 USD ($) MMBTU | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Note To Financial Statement Details Textual | |||
Asset Retirement Obligation, Period Increase (Decrease) Due To Acquisitions Incurred and Revisions | $ 88.8 | $ 36.2 | $ 15.2 |
Proved Undeveloped Reserve Net Energy Converted Outside of Five Years (Millions of Barrels of Oil Equivalent) | MMBTU | 2.5 | ||
Proved Developed and Undeveloped Reserve, Net (Energy), Ending Balance (Millions of Barrels of Oil Equivalent) | MMBTU | 20.5 | ||
Seismic Costs | $ 5.6 | 0.1 | 0.3 |
Geological And Geophysical Costs | $ 5.5 | $ 5.7 | $ 4.5 |
Percentage Of Proved Undeveloped Reserves Expected To Be Developed | 12% | ||
Present Value Discounted Percentage | 10% |
SUPPLEMENTAL OIL AND GAS DISC_4
SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED - Capitalized Costs Related to Oil and Natural Gas (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 USD ($) $ / Boe | Dec. 31, 2021 USD ($) $ / Boe | Dec. 31, 2020 USD ($) $ / Boe | |
Note 19 - Supplemental Oil and Gas Disclosures - Unaudited - Capitalized Costs Related to Oil and Natural Gas (Details) | |||
Proved oil and natural gas properties and equipment | $ 8,813,404 | $ 8,636,408 | $ 8,567,509 |
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities | (8,088,271) | (7,981,271) | (7,890,889) |
Net capitalized costs related to producing activities | $ 725,133 | $ 655,137 | $ 676,620 |
Depreciation, depletion and amortization ($/Boe) | $ / Boe | 7.32 | 6.50 | 6.34 |
SUPPLEMENTAL OIL AND GAS DISC_5
SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED - Cost Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Costs incurred: (1) | ||||
Proved properties acquisitions | [1] | $ 78,565 | $ 2,197 | $ 8,118 |
Exploration (2) | [2] | 24,498 | 18,444 | 7,727 |
Development | [1] | 77,282 | 47,218 | 23,528 |
Total costs incurred in oil and gas property acquisition, exploration and development activities | [1] | $ 180,345 | $ 67,859 | $ 39,373 |
[1] Includes net additions from capitalized ARO of $88.8 million, $36.2 million, and $15.2 million during 2022, 2021, and 2020, respectively. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates. Includes seismic costs of $5.6 million, $ 0.1 million, and $0.3 million incurred during 2022, 2021, and 2020, respectively. Includes geological and geophysical costs charged to expense of $5.5 million, $5.7 million, and $4.5 million during 2022, 2021, and 2020, respectively. |
SUPPLEMENTAL OIL AND GAS DISC_6
SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED - Estimated Quantities of Net Proved, Proved Developed and Proved Undeveloped Oil, NGLs and Natural Gas Reserves (Details) ft³ in Billions | 12 Months Ended | ||
Dec. 31, 2022 MMBoe MMBTU ft³ MMBbls | Dec. 31, 2021 MMBoe MMBbls ft³ | Dec. 31, 2020 MMBoe MMBbls ft³ | |
Proved reserves, balance (Millions of Barrels of Oil Equivalent) | MMBTU | 20.5 | ||
Oil [Member] | |||
Proved reserves, balance (Million Barrels of Oil) | 37.2 | 32.2 | 37.8 |
Revisions of previous estimates (Million Barrels of Oil) | 4.5 | 10 | (0.9) |
Extensions and discoveries (Million Barrels of Oil) | 0.2 | ||
Purchase of minerals in place (Million Barrels of Oil) | 4.5 | 0.7 | |
Production (Million Barrels of Oil) | (5.6) | (5) | (5.6) |
Proved reserves, balance (Million Barrels of Oil) | 40.6 | 37.2 | 32.2 |
Proved reserves, ending balance (Million Barrels of Oil) | 31.1 | 27.6 | 24 |
Undeveloped reserves, ending balance (Million Barrels of Oil) | 9.5 | 9.6 | 8.2 |
Natural Gas Liquids [Member] | |||
Proved reserves, balance (Million Barrels of Oil) | 19.1 | 17.4 | 24.5 |
Revisions of previous estimates (Million Barrels of Oil) | 1.2 | 3.1 | (5.9) |
Purchase of minerals in place (Million Barrels of Oil) | 0.2 | 0.5 | |
Production (Million Barrels of Oil) | (1.6) | (1.4) | (1.7) |
Proved reserves, balance (Million Barrels of Oil) | 18.9 | 19.1 | 17.4 |
Proved reserves, ending balance (Million Barrels of Oil) | 17.6 | 17.8 | 16.5 |
Undeveloped reserves, ending balance (Million Barrels of Oil) | 1.3 | 1.3 | 0.9 |
Natural Gas [Member] | |||
Proved reserves, balance (Million Barrels of Oil) | ft³ | 607.6 | 569.3 | 571.1 |
Revisions of previous estimates (Million Barrels of Oil) | ft³ | 64.3 | 83 | 31.6 |
Extensions and discoveries (Million Barrels of Oil) | ft³ | 0.2 | ||
Purchase of minerals in place (Million Barrels of Oil) | ft³ | 7.5 | 0.1 | 14.8 |
Production (Million Barrels of Oil) | ft³ | (44.8) | (44.8) | (48.4) |
Proved reserves, balance (Million Barrels of Oil) | ft³ | 634.6 | 607.6 | 569.3 |
Proved reserves, ending balance (Million Barrels of Oil) | ft³ | 576 | 549.2 | 550.2 |
Undeveloped reserves, ending balance (Million Barrels of Oil) | ft³ | 58.6 | 58.4 | 19.1 |
Oil Equivalent [Member] | |||
Proved reserves, balance (Millions of Barrels of Oil Equivalent) | MMBoe | 157.6 | 144.4 | 157.4 |
Revisions of previous estimates (Millions of Barrels of Oil Equivalent) | MMBoe | 16.3 | 27.1 | (1.4) |
Extensions and discoveries (Millions of Barrels of Oil Equivalent) | MMBoe | 0.2 | ||
Purchase of minerals in place (Millions of Barrels of Oil Equivalent) | MMBoe | 6 | 3.6 | |
Production (Millions of Barrels of Oil Equivalent) | MMBoe | (14.6) | (13.9) | (15.4) |
Proved reserves, balance (Millions of Barrels of Oil Equivalent) | MMBoe | 165.3 | 157.6 | 144.4 |
Proved reserves, ending balance (Millions of Barrels of Oil Equivalent) | MMBoe | 144.8 | 137 | 132.2 |
Undeveloped reserves, ending balance (Millions of Barrels of Oil Equivalent) | MMBoe | 20.5 | 20.6 | 12.2 |
SUPPLEMENTAL OIL AND GAS DISC_7
SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2018 |
Standardized Measure of Discounted Future Net Cash Flows | ||||
Future cash inflows | $ 8,855,730,000 | $ 5,178,215,000 | $ 2,561,189,000 | |
Production | (2,894,652,000) | (2,061,752,000) | (1,257,421,000) | |
Development and abandonment | (990,329,000) | (976,500,000) | (707,357,000) | |
Income taxes | (1,005,917,000) | (358,954,000) | (60,503,000) | |
Future net cash inflows before 10% discount | 3,964,832,000 | 1,781,009,000 | 535,908,000 | |
10% annual discount factor | (1,701,871,000) | (625,019,000) | (42,202,000) | |
Total | $ 2,262,961,000 | $ 1,155,990,000 | $ 493,706,000 | $ 986,900,000 |
SUPPLEMENTAL OIL AND GAS DISC_8
SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED - Schedule of Prices Weighted by Field Production Related to Proved Reserves (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Oil [Member] | |||
Weighted price | $ 91.50 | $ 65.25 | $ 37.78 |
Natural Gas Liquids [Member] | |||
Weighted price | 41.92 | 26.83 | 10.29 |
Natural Gas [Member] | |||
Weighted price | $ 6.85 | $ 3.68 | $ 2.05 |
SUPPLEMENTAL OIL AND GAS DISC_9
SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED - Change in Standard Measure of Discounted Future Net Cash Flows (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Changes in Standardized Measure | |||
Standardized measure, beginning of year | $ 1,155,990,000 | $ 493,706,000 | |
Sales and transfers of oil and gas produced, net of production costs | (672,665,000) | (370,456,000) | $ (168,563,000) |
Net changes in price, net of future production costs | 1,368,626,000 | 980,922,000 | (503,676,000) |
Extensions and discoveries, net of future production and development costs | 2,767,000 | ||
Changes in estimated future development costs | (18,617,000) | (25,357,000) | (15,881,000) |
Previously estimated development costs incurred | 3,313,000 | 613,000 | 1,384,000 |
Revisions of quantity estimates | 249,117,000 | 289,637,000 | (65,218,000) |
Accretion of discount | 138,077,000 | 43,993,000 | 111,760,000 |
Net change in income taxes | (369,307,000) | (181,795,000) | 87,713,000 |
Purchases of reserves in-place | 225,205,000 | 319,000 | 44,621,000 |
Sales of reserves in-place | 0 | ||
Changes in production rates due to timing and other | 183,222,000 | (75,592,000) | 11,899,000 |
Net (decrease) increase | 1,106,971,000 | 662,284,000 | (493,194,000) |
Standardized measure, end of year | $ 2,262,961,000 | $ 1,155,990,000 | $ 493,706,000 |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Feb. 08, 2023 | Jan. 27, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Oct. 18, 2018 | |
Subsequent Events | ||||||
Principal | $ 700,400 | |||||
9.75% Senior Second Lien Notes Due November 2023 [Member] | ||||||
Subsequent Events | ||||||
Debt Instrument, Face Amount | $ 625,000 | |||||
Debt instrument, interest rate, stated percentage | 9.75% | 9.75% | 9.75% | 9.75% | 9.75% | |
Principal | $ 552,460 | $ 552,460 | ||||
9.75% Senior Second Lien Notes Due November 2023 [Member] | CEO and Largest Shareholder [Member] | ||||||
Subsequent Events | ||||||
Repayments of Debt | $ 8,000 | |||||
11.75% Senior Second Lien Notes Due 2026 [Member] | ||||||
Subsequent Events | ||||||
Debt instrument, interest rate, stated percentage | 11.75% | |||||
Repayments of Debt | $ 296,100 | |||||
Proceeds from Issuance of Debt | $ 270,800 | |||||
Subsequent Event | Redemption Prior to August 1, 2024 With Applicable Premium [Member] | ||||||
Subsequent Events | ||||||
Debt Instrument, Redemption Price, Percentage | 100% | |||||
Subsequent Event | Redemption Prior to August 1, 2024 [Member] | ||||||
Subsequent Events | ||||||
Debt Instrument, Redemption Price, Percentage | 111.75% | |||||
Subsequent Event | Redemption On or After August 1, 2024 [Member] | ||||||
Subsequent Events | ||||||
Debt Instrument, Redemption Price, Percentage | 105.875% | |||||
Subsequent Event | Redemption On or After August 1, 2025 [Member] | ||||||
Subsequent Events | ||||||
Debt Instrument, Redemption Price, Percentage | 100% | |||||
Subsequent Event | Maximum [Member] | Redemption Prior to August 1, 2024 [Member] | ||||||
Subsequent Events | ||||||
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed | 35% | |||||
Subsequent Event | 9.75% Senior Second Lien Notes Due November 2023 [Member] | ||||||
Subsequent Events | ||||||
Debt instrument, interest rate, stated percentage | 9.75% | |||||
Debt Instrument, Redemption Price, Percentage | 100% | |||||
Subsequent Event | 9.75% Senior Second Lien Notes Due November 2023 [Member] | Alter Domus (US) LLC and Calculus [Member] | ||||||
Subsequent Events | ||||||
Debt instrument, interest rate, stated percentage | 9.75% | |||||
Subsequent Event | 11.75% Senior Second Lien Notes Due 2026 [Member] | ||||||
Subsequent Events | ||||||
Debt Instrument, Face Amount | $ 275,000 | |||||
Debt instrument, interest rate, stated percentage | 11.75% | |||||
Subsequent Event | 11.75% Senior Second Lien Notes Due 2026 [Member] | CEO and Largest Shareholder [Member] | ||||||
Subsequent Events | ||||||
Repayments of Debt | $ 21,000 | |||||
Subsequent Event | 11.75% Senior Second Lien Notes Due 2026 [Member] | Alter Domus (US) LLC and Calculus [Member] | ||||||
Subsequent Events | ||||||
Debt instrument, interest rate, stated percentage | 11.75% |