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Summary of Significant Accounting Policies (Policies) | 12 Months Ended
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Dec. 31, 2024
Accounting Policies [Abstract] |
Basis of Presentation [Policy Text Block] | Basis of Presentation The accompanying consolidated financial statements include the accounts of the Company and have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Intercompany accounts and transactions have been eliminated. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying consolidated financial statements.
Use of Estimates in the Preparation of the Financial Statements [Policy Text Block] | Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of DD&A expense, impairment of proved and unproved oil and gas properties, acquisitions of oil and gas properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements.
Cash, Cash Equivalents, and Restricted Cash [Policy Text Block] | Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.
Accounts Receivable [Policy Text Block] | Accounts Receivable The Company’s accounts receivable primarily consist of receivables due from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil, gas, and NGL receivables are collected within 30 to 90 days and the Company has had minimal bad debts. Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. Refer to Note 14 – Accounts Receivable and Accounts Payable and Accrued Expenses for additional disclosure.
Concentration of Credit Risk and Major Customers [Policy Text Block] | Concentration of Credit Risk and Major Customers The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is regularly reviewed. The Company does not believe the loss of any single purchaser of its production would materially affect its operating results, as oil, gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating areas. The following major customers and entities under common control accounted for 10 percent or more of the Company’s total oil, gas, and NGL production revenue for at least one of the periods presented:
| For the Years Ended December 31,
| 2024 |  | 2023 |  | 2022
| Amount |  | % of total |  | Amount |  | % of total |  | Amount |  | % of total
| (in thousands)
Major customer #1 | $ | 899,609 |  |  | 34 | % |  | $ | 580,557 |  |  | 24 | % |  | $ | 848,595 |  |  | 24 | %
Major customer #2 | $ | 248,383 |  |  | 9 | % |  | $ | 260,574 |  |  | 11 | % |  | $ | 255,395 |  |  | 7 | %
Group of entities under common control | $ | 426,248 |  |  | 16 | % |  | $ | 530,131 |  |  | 22 | % |  | $ | 830,276 |  |  | 24 | %
For its commodity derivative instruments, the Company’s policy is to only enter into contracts with affiliates of the lenders under its Credit Agreement as its derivative counterparties, and each counterparty must have certain minimum investment grade senior unsecured debt ratings. The Company maintains its primary bank accounts with a large, multinational bank that has branch locations in the Company’s areas of operation. The Company’s policy is to diversify its concentration of cash and cash equivalent investments among multiple institutions and investment products to limit the amount of credit exposure to any single institution or investment.
Oil and Gas Producing Activities [Policy Text Block] | Proved properties. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, property acquisition costs and development costs are capitalized when incurred. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, are depleted on a pool-by-pool basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated net proved developed oil and gas reserves. Similarly, proved leasehold costs are depleted on the same pool-by-pool basis; however, the units-of-production method is based on estimated total net proved oil and gas reserves. The computation of DD&A expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment.
Oil and Gas Properties Costs [Policy Text Block] | Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, are depleted on a pool-by-pool basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated net proved developed oil and gas reserves. Similarly, proved leasehold costs are depleted on the same pool-by-pool basis; however, the units-of-production method is based on estimated total net proved oil and gas reserves. The computation of DD&A expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. Proved oil and gas property costs are evaluated for impairment on a depletion pool-by-pool basis and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties using a discount rate, price and cost forecasts, and certain reserve risk-adjustment factors, as selected by the Company’s management. The Company uses a discount rate that represents a current market-based weighted average cost of capital. The discount rate typically ranges from 10 percent to 15 percent. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS Mont Belvieu pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties. The partial sale of a proved property within an existing asset group is accounted for as a normal retirement and no gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. Unproved properties. The unproved oil and gas properties line item on the accompanying consolidated balance sheets (“accompanying balance sheets”) consists of the costs incurred to acquire unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be nonproductive prior to lease expiration are recognized as a valuation allowance and amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses an income approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. For the sale of unproved properties where the original cost has been partially or fully amortized by providing a valuation allowance on an asset group basis, neither a gain nor loss is recognized unless the sales price exceeds the original cost of the property, in which case a gain shall be recognized in the accompanying statements of operations in the amount of such excess.
Property, Plant and Equipment, Impairment [Policy Text Block] | Proved oil and gas property costs are evaluated for impairment on a depletion pool-by-pool basis and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties using a discount rate, price and cost forecasts, and certain reserve risk-adjustment factors, as selected by the Company’s management. The Company uses a discount rate that represents a current market-based weighted average cost of capital. The discount rate typically ranges from 10 percent to 15 percent. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS Mont Belvieu pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties. The partial sale of a proved property within an existing asset group is accounted for as a normal retirement and no gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. Unproved properties. The unproved oil and gas properties line item on the accompanying consolidated balance sheets (“accompanying balance sheets”) consists of the costs incurred to acquire unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be nonproductive prior to lease expiration are recognized as a valuation allowance and amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses an income approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants.
Exploratory [Policy Text Block] | Exploratory. Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method of accounting for oil and gas properties, exploratory well costs are initially capitalized pending the determination of whether proved reserves have been discovered. If proved reserves are discovered, exploratory well costs will be capitalized as proved properties and will be accounted for following the successful efforts method of accounting described above. If proved reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of capital expenditures within the accompanying statements of cash flows. Refer to Note 8 – Fair Value Measurements for additional information.
Other Property and Equipment [Policy Text Block] | Other Property and Equipment Other property and equipment such as facilities, equipment inventory, office furniture and equipment, buildings, and computer hardware and software, are recorded at cost. The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes software design, configuration, testing, and installation activities. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from three to 30 years, or the unit of output method when appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the Company’s accounts. Facilities and equipment inventory costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. To measure the fair value of facilities and equipment inventory, the Company uses an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. For facilities, the valuation includes consideration of the proved and unproved assets supported by the facilities, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets.
Asset Retirement Obligations [Policy Text Block] | Asset Retirement Obligations The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in the proved oil and gas properties line item in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated lives of the respective long-lived assets. Asset retirement obligation liability accretion expense is included in the depletion, depreciation, and amortization line on the accompanying statements of operations. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows. The Company’s estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s plugging and abandonment liabilities range from 5.5 percent to 12 percent. In periods subsequent to initial measurement of the liability, the Company must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or economic life, changes in inflation factors, or the Company’s credit-adjusted risk-free rate as market conditions warrant. Refer to Note 15 – Asset Retirement Obligations for a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2024, and 2023.
Derivatives Financial Instruments [Policy Text Block] | Derivative Financial Instruments The Company regularly enters into commodity derivative contracts to mitigate a portion of its exposure to oil, gas, and NGL price volatility and location differentials for its expected future oil, gas, and NGL production, and the associated effect on cash flows. All commodity derivative contracts that the Company enters into are for other-than-trading purposes. The Company’s commodity derivative contracts generally consist of price swap, collar, and basis swap arrangements. Commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The fair value of the Company’s commodity derivative contracts is measured based on, among other things, option pricing models, futures prices, volatility, time to maturity, and credit risk. The Company does not designate its commodity derivative contracts as hedging instruments. Accordingly, the Company reflects gains and losses from changes in the fair value of its commodity derivative contracts in the accompanying statements of operations as such changes occur, rather than deferring any such amounts in accumulated other comprehensive income (loss). Gains and losses on net derivative settlements are included within the cash flows from operating activities section of the accompanying statements of cash flows. Refer to Note 7 – Derivative Financial Instruments for additional discussion.
Revenue Recognition [Policy Text Block] | Revenue Recognition The Company derives revenue predominately from the sale of produced oil, gas, and NGLs. Revenue is recognized at the point in time when custody and title (“control”) of the product transfers to the purchaser, which may differ depending on the applicable contractual terms. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. The Company uses knowledge of its properties, contractual arrangements, historical performance, NYMEX, local spot market, and OPIS prices, and other factors as the basis of these estimates. Variances between estimates and the actual amounts received are recorded in the month payment is received. Refer to Note 2 – Revenue from Contracts with Customers for additional discussion.
Stock-based Compensation [Policy Text Block] | Stock-Based Compensation At December 31, 2024, the Company had stock-based employee compensation plans that included RSUs and Performance Share Units (“PSU or “PSUs”) issued to employees, RSUs and restricted stock issued to non-employee directors, and an employee stock purchase plan available to eligible employees. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant, and is included within the general and administrative and exploration expense line items in the accompanying statements of operations. For stock-based compensation awards containing non-market based performance conditions, the Company evaluates the probability of the number of shares that are expected to vest, and then adjusts the expense to reflect the number of shares expected to vest and the cumulative vesting period met to date. Further, the Company accounts for forfeitures of stock-based compensation awards as they occur. Refer to Note 10 – Compensation Plans for additional discussion.
Income Taxes [Policy Text Block] | Income Taxes The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the accompanying consolidated financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. Judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. The Company’s federal and state income tax returns are not filed before the consolidated financial statements are prepared. Therefore, the Company estimates the tax basis of its assets and liabilities at the end of each period, as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates used and actual amounts reported are recorded in the periods in which the income tax returns are filed. The cumulative effect of enacted tax rate changes on the net balance of reported amounts of assets and liabilities is recognized in the period of enactment. The Company’s policy is to record interest related to income taxes in the interest expense line item in the accompanying statements of operations, and to record penalties related to income taxes in the other non-operating expense line item in the accompanying statements of operations. Refer to Note 4 – Income Taxes for additional discussion.
Earnings Per Share [Policy Text Block] | Earnings per Share The Company uses the treasury stock method to determine the effect of potentially dilutive instruments. Refer to Note 9 – Earnings Per Share for additional discussion.
Comprehensive Income (Loss) [Policy Text Block] | Comprehensive Income (Loss) Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that, under GAAP, are reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income. The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach. Refer to Note 12 – Pension Benefits for detail on adjustments impacting other comprehensive income.
Fair Value of Financial Instruments [Policy Text Block] | Fair Value of Financial Instruments The Company’s financial instruments, including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The Company’s Senior Notes, as defined in Note 5 – Long-Term Debt, are recorded at cost, net of unamortized deferred financing costs, and their respective fair values are disclosed in Note 8 – Fair Value Measurements. Additionally, the Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivative instruments. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty. Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any commodity derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current revolving credit facility margins, and any change in such margins since the last measurement date. The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.
Leases [Policy Text Block] | Leases The Company accounts for leases in accordance with ASC Topic 842, Leases, (“Topic 842”), which requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component. Certain leases may contain both lease and non-lease components. The Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Certain assumptions and judgments made by the Company when evaluating a contract that meets the definition of a lease under Topic 842 include those to determine the discount rate and lease term. Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception. The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a right-of-use (“ROU”) asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Exercising an early termination option may result in an early termination penalty depending on the terms of the underlying agreement. The Company excludes from the balance sheet leases with terms that are less than one year. An ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of an ROU asset and corresponding lease liability are certain variable lease payments, such as payments made that vary depending on actual usage or performance. Subsequent to initial measurement, costs associated with the Company’s operating leases are either expensed or capitalized depending on how the underlying ROU asset is utilized and in accordance with GAAP requirements. When calculating the Company’s ROU asset and liability for a contractual arrangement that qualifies as an operating lease, the Company considers all of the necessary payments made or that are expected to be made upon commencement of the lease. As discussed above, excluded from the initial measurement are certain variable lease payments, which for the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs. Refer to Note 13 – Leases for additional discussion.
Industry, Geographic, and Segment Information [Policy Text Block] | Industry, Geographic, and Segment Information The Company operates in the oil and gas extraction industry, focused on exploration and production activities, onshore in the United States. The Company has one reportable segment. Refer to Note 11 – Segment Reporting for additional discussion.
Off-Balance Sheet Arrangements [Policy Text Block] | Off-Balance Sheet Arrangements The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or SPEs, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that the Company is the primary beneficiary of a variable interest entity, that entity is consolidated into the Company’s consolidated financial statements. The Company has not been involved in any unconsolidated SPE transactions during 2024 or 2023, or through the filing of this report.
Recently Issued Accounting Standards [Policy Text Block] | Recently Issued Accounting Guidance Accounting Standards Updates. In November 2024, the FASB issued ASU No. 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”). ASU 2024-03 was issued to improve disclosures about a public business entity’s expenses and address requests from investors for more detailed information about the types of expenses in commonly presented expense captions. ASU 2024-03 is effective for the fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. The guidance is to be applied on a prospective basis; however, retrospective application is permitted. The Company is within the scope of this ASU and expects to adopt ASU 2024-03 on January 1, 2027, on a prospective basis, and adoption will result in new disclosures as prescribed by the guidance. In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 was issued to improve the disclosures about a public entity’s reportable segments and to provide additional, more detailed information about a reportable segment’s expenses. The Company adopted ASU 2023-07 on December 31, 2024, on a retrospective basis. Refer to Note 11 – Segment Reporting for additional discussion. In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 was issued to improve the disclosures related to rate reconciliations and income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, with early adoption permitted. The guidance is to be applied on a prospective basis; however, retrospective application is permitted. The Company adopted ASU 2023-09 on January 1, 2025, on a prospective basis, and will present the required new disclosures in the 2025 Form 10-K. SEC Final Rule to Enhance and Standardize Climate-Related Disclosures. On March 6, 2024, the SEC adopted final rules to require registrants to disclose certain climate-related information in registration statements and annual reports. On April 4, 2024, the SEC issued an order staying the final rules pending completion of judicial review of the petitions challenging the final rules. The order does not amend the compliance dates contemplated by the final rules, which are applicable to the Company for fiscal years beginning with the Company’s annual report on Form 10-K for the fiscal year ended December 31, 2025. The Company is currently evaluating the potential impact of the final rules on its financial statements and related disclosures. As of December 31, 2024, and through the filing of this report, no other accounting guidance has been issued and not yet adopted that are applicable to the Company and that would have a material effect on the Company’s consolidated financial statements and related disclosures.
Derivatives, Offsetting Fair Value Amounts, Policy [Policy Text Block] | The Company’s accounting policy is to not offset

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