BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) |
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Dec. 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Nature of Operations |
Nature of Operations W&T Offshore, Inc. (with subsidiaries referred to herein as the “Company”) is an independent oil, NGL and natural gas producer with substantially all of its operations offshore in the Gulf of America. The Company is active in the exploration, development and acquisition of oil and natural gas properties. The Company operates in one reportable segment. |
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| Basis of Presentation |
Basis of Presentation The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries and a variable interest entity in Monza Energy LLC (“Monza”), which is accounted for under the proportional consolidation method. All significant intercompany accounts and transactions have been eliminated. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (the “SEC”) for annual financial information. Certain reclassifications have been made to the prior year’s consolidated financial statements to conform to the current year’s presentation. On the Condensed Consolidated Balance Sheets, the Company has combined Income tax payable with Accrued liabilities and combined Deferred income taxes with Other liabilities. On the Condensed Consolidated Statements of Cash Flows, the Company has combined lines within operating cash flows and investing cash flows. These reclassifications had no effect on the Company’s results of operations, financial position or cash flows. |
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| Use of Estimates |
Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While the Company believes that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. |
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| Cash Equivalents |
Cash Equivalents The Company 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. |
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| Restricted Cash |
Restricted Cash The Company maintains funds related to collateralized letters of credit. |
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| Accounts Receivable and Allowance for Credit Losses |
Accounts Receivable 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. Payment of the Company’s accounts receivable is typically received within 30-60 days. 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.
Changes to the allowance for credit losses are as follows (in thousands):
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| Derivative Financial Instruments |
Derivative Financial Instruments The Company monitors its exposure to various business risks and uses derivative instruments to manage exposure to commodity price risk from sales of natural gas. The Company has elected not to designate its derivative instruments as hedging instruments. Accordingly, the derivative instruments are recorded in the Consolidated Balance Sheets at fair value with settlements of such contracts, and changes in the unrealized fair value, recorded as Derivative (gain) loss, net in the Consolidated Statements of Operations in each period presented. Although the Company has master netting arrangements with its counterparties, the amounts recorded on the Consolidated Balance Sheets are on a gross basis. The related cash flow impact of the Company’s derivative instruments is reflected as cash flows from operating activities unless the derivative instrument contains a significant financing element, in which case the related cash flow impact is reflected as cash flows from financing activities in the Consolidated Statements of Cash Flows. |
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| Oil and Natural Gas Properties and Other, Net |
Oil and Natural Gas Properties and Other, Net Oil and Natural Gas Properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under full cost accounting, all costs associated with the acquisition, exploration, development and abandonment of oil, NGL and natural gas reserves are capitalized into a full cost pool. 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. Capitalized costs included in the amortization base are amortized using the units-of-production method based on production. Under this method, depreciation and depletion is computed at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost pool plus future development costs by net equivalent proved reserves at the beginning of the period. Costs associated with unproved properties are excluded from the amortization base until the Company has made an evaluation that proved reserves exist or impairment has occurred. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a periodic basis for possible impairment. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and whether the proved reserves can be developed economically. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. As of both December 31, 2024 and 2023, there were no unproved properties included in “Oil and natural gas properties, net.” Under the full-cost method of accounting, total capitalized costs of oil and natural gas properties (including capitalized ARO), net of accumulated depletion and amortization, may not exceed the ceiling limitation. A ceiling limitation calculation is performed quarterly. If the ceiling limitation is exceeded, a write-down of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge and is recorded as an expense on a pretax basis and separately disclosed. Any such write-downs are not recoverable or reversible in future periods. The Company did not record a ceiling test write-down during 2024, 2023 or 2022. 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. 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. Other Property Other property is stated at cost less accumulated depreciation and amortization, which is computed using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from to seven years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred. Significant improvements or betterments are capitalized if they extend the useful life of the asset. Other property is reviewed for possible impairment whenever events or changes in circumstances indicate that estimated future net operating cash flows directly related to the asset or asset group including disposal value is less than the carrying amount of the asset or asset group. Impairment is measured as the excess of the carrying amount of the impaired asset or asset group over its fair value. The Company did not record any impairments related to other property during 2024, 2023 or 2022. |
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| Asset Retirement Obligations |
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. The Company records a separate liability for the present value of an asset retirement obligation (“ARO”) based on the estimated timing and amount to replace, remove or retire the associated assets, with an offsetting increase to oil and natural gas property costs. After initial recording, the liability accretes each period until it is settled, and the liability is removed and the capitalized ARO included in oil and natural gas properties is depreciated on a unit-of-production basis within the full cost pool. Both the accretion and depreciation are included in the consolidated statements of operations. If the Company incurs an amount different from the amount accrued for the associated ARO, the Company recognizes the difference as an adjustment to oil and natural gas properties. In estimating the liability associated with its ARO, 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. |
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| Revenue Recognition |
Revenue Recognition The Company revenue is primarily derived from the sale of oil and natural gas production, as well as the sale of NGLs that are extracted from natural gas during processing. Revenue is presented disaggregated in the Consolidated Statements of Operations by major product. Revenue is recognized when the following five steps are completed: (1) the contract with the customer has been identified, (2) the performance obligation (promise) in the contract has been identified, (3) the transaction price has been determined, (4) the transaction price has been allocated to the performance obligations in the contract, and (5) revenue has been recognized when a performance obligation has been satisfied. The Company records revenues from the sale of oil, NGLs and natural gas at the point in time that control of the product is transferred to the customer and collectability is probable. Revenue is measured based on contract consideration allocated to each unit of commodity and excludes amounts collected on behalf of third parties. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction that are collected by the Company from a customer are excluded from revenue. For sales of oil production, the Company recognizes revenue when control transfers at the delivery point at the net price received. Generally, this occurs when the Company (i) sells its oil production at the wellhead where control of the oil transfers to the customer or (ii) delivers its oil production to the customer at a contractual delivery point at which the customer takes custody, title and risk of loss of the product. For sales of NGL and natural gas production, the Company evaluated its natural gas gathering and processing arrangements in place with midstream companies and has determined that control of the natural gas is transferred at the tailgate of the midstream entity’s processing plant. Accordingly, revenues are presented on a gross basis for amounts expected to be received from the midstream company or third-party purchasers through the gathering and treating process. Any fees incurred to gather or process the natural gas are presented separately as “Gathering, transportation and production taxes” on the Consolidated Statements of Operations. The performance obligation is the delivery of the commodity at a point in time. Prices for oil, natural gas and NGLs sales are negotiated based on index or spot price, distance from the well to pipeline, commodity quality and prevailing supply and demand conditions. To the extent that actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties must be estimated. Under its sales contracts, the Company invoices customers once its performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date. The Company recognized amounts due from contracts with customers of $63.6 million and $52.1 million as of December 31, 2024 and 2023, respectively, as Accounts receivable ‒ Oil, natural gas liquids and natural gas sales on the Consolidated Balance Sheet. A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has elected the practical expedient permitting the Company not to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have a contract term greater than one year, the Company has elected the practical expedient permitting the Company not to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally 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. |
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| Share-Based Compensation |
Share-Based Compensation Share-based compensation cost is measured at the date of grant based on the calculated fair value of the award and is recognized over the period during which the recipient is required to provide service in exchange for the award. The compensation cost is determined based on awards ultimately expected to vest; therefore the Company has reduced the compensation cost for estimated forfeitures based on historical forfeiture rates. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods to reflect actual forfeitures. |
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| Income Taxes |
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 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 the related tax benefits will not be realized. |
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| Earnings Per Share |
Earnings Per Share Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes restricted stock units and performance stock units when the effect is dilutive. |
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| Fair Value Measurements |
Fair Value Measurements Fair value is defined as the price the Company would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date. In the absence of active markets for the identical assets or liabilities, such measurements involve developing assumptions based on market observable data and, in the absence of such data, internal information that is consistent with what market participants would use in a hypothetical transaction that occurs at the measurement date. Inputs to valuation techniques are classified as either observable (market data obtained from independent sources) or unobservable (the Company’s market assumptions) within the following hierarchy:
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. |
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| Concentration of Credit Risk |
Concentration of Credit Risk Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents, accounts receivable and derivative instruments. All the Company’s cash and cash equivalents are maintained with several major financial institutions in the United States. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, the Company regularly monitors the financial stability of these financial institutions and believes that it is not exposed to any significant default risk. The Company’s customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and natural gas producers and suppliers. The majority of the Company’s production is sold to customers under short-term contracts at market-based prices. In addition, the Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners are primarily independent oil and natural gas producers. The Company attempts to minimize credit risk exposure to its purchasers and joint interest owners through formal credit policies, monitoring procedures and letters of credit or guarantees when considered necessary. In 2024, two customers accounted for approximately 44% and 12%, respectively, of the Company’s receipts from sales of oil, NGL and natural gas. In 2023, two customers accounted for approximately 41% and 13%, respectively, of the Company’s receipts from sales of oil, NGL and natural gas. In 2022, two customers accounted for approximately 31% and 13%, respectively, of the Company’s receipts from sales of oil, NGL and natural gas. The loss of any of the customers above is not expected to 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. The Company is exposed to credit loss in the event of nonperformance by the derivative counterparties; however, the Company currently anticipates that the derivative counterparties will be able to fulfill their contractual obligations. The Company is not required to provide additional collateral to the derivative counterparties and does not require collateral from the derivative counterparties. |
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| Accounting Standards |
Recently Adopted Accounting Standards The Company adopted Accounting Standards Update No. 2023-07, Improvements to Reportable Segment Disclosures (“ASU 2023-07”) for the year ended December 31, 2024. ASU 2023-07 enhances the disclosures required for operating segments in the Company’s annual and interim consolidated financial statements. The adoption of ASU 2023-07 did not have an impact on our consolidated financial statements but required additional disclosures (see Note 15 – Segment Information). Accounting Standards to be Adopted In December 2022, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update No. 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”), which is intended to enhance transparency of income tax disclosures. ASU 2023-09 requires specified categories in the annual rate reconciliation that meet quantitative thresholds and further disaggregation of income taxes paid by jurisdictional categories (federal (national), state and foreign). ASU 2023-09, which allows for early adoption, is effective for the Company prospectively to all annual periods beginning after December 15, 2024. The Company is currently assessing the impact of ASU 2023-09; however, it is not expected to have a material impact on the Company’s consolidated financial statements. In November 2024, the FASB issued Accounting Standards Update No. 2024-03, Disaggregation of Income Statement Expenses (“ASU 2024-03”) to enhance the disclosures required for certain expense captions in the Company annual and interim consolidated financial statements. ASU 2024-03 is effective prospectively or retrospectively for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company continues to evaluate the impact of ASU 2024-03 on its disclosures however, it is not expected to have a material impact on the Company’s consolidated financial statements. No other new accounting pronouncements issued or effective during 2024 have had or are expected to have a material impact on the Company’s consolidated financial statements. |
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