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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 | Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
Business Segments | Segment Information The Company has evaluated how it is organized and managed and has identified only one reportable business segment, which is the E&P of crude oil, NGLs and natural gas. All of the Company’s operations and assets are primarily located in the United States, and substantially all of its revenues are attributable to United States customers. The operating results of the Company’s single reportable segment are evaluated by the Company’s President & Chief Executive Officer, who has been determined to be the Company’s Chief Operating Decision Maker (“CODM”), to make key operating decisions, such as the allocation of resources and the evaluation of operating segment performance. The primary measure of profit and loss evaluated by the Company’s CODM for its single reportable segment is consolidated net income. Consolidated net income, total assets, and all significant segment expense items are presented in the Company’s consolidated financial statements and notes to the consolidated financial statements.
Use of Estimates | Use of Estimates Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to (i) proved crude oil, NGL and natural gas reserves and related cash flow estimates, (ii) assignment of fair value and allocation of purchase price in connection with business combinations, including the determination of any resulting goodwill or bargain purchase, (iii) impairment tests of long-lived assets, (iv) estimates of future development, dismantlement and abandonment costs, (v) estimates relating to certain crude oil, NGL and natural gas revenues and expenses, (vi) income taxes, (vii) valuation of derivative instruments and (viii) estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates. Estimates of crude oil, NGL and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, NGL and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future DD&A expense, dismantlement and abandonment costs and impairment expense.
Risks and Uncertainties | Risks and Uncertainties As a producer of crude oil, NGLs and natural gas, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil, NGLs and natural gas, which are dependent upon numerous factors beyond its control such as economic, geopolitical, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile, and there can be no assurance that the prices for crude oil, NGLs or natural gas will not be subject to wide fluctuations in the future. A substantial or extended decline in prices for crude oil and, to a lesser extent, NGLs and natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows, the quantities of crude oil, NGLs and natural gas reserves that may be economically produced and the Company’s access to capital.
Cash and Cash Equivalents | Cash and Cash Equivalents The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such highly liquid investments with original maturity dates less than 90 days as cash equivalents. While the Company may maintain balances of cash and cash equivalents in excess of amounts that are federally insured by the Federal Deposit Insurance Corporation, the Company invests with financial institutions that it believes are creditworthy and has not experienced any material losses in such accounts.
Accounts Receivable | Accounts Receivable Accounts receivable are carried at cost on a gross basis, with no discounting, which approximates fair value due to their short-term maturities. The Company’s accounts receivable consist mainly of receivables from crude oil, NGL and natural gas purchasers and joint interest owners on properties the Company operates. The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability and if an allowance for credit losses is warranted. The Company estimates credit losses and accrues a reserve on a receivable based on (i) historic loss experience for pools of receivable balances with similar characteristics, (ii) the length of time balances have been outstanding and (iii) the economic status of each counterparty. These loss estimates are then adjusted for current and expected future economic conditions, which may include an assessment of the probability of non-payment, financial distress or expected future commodity prices and the impact that any current or future conditions could have on a counterparty’s credit quality and liquidity. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s crude oil, NGL and natural gas receivables are collected within two months.
Inventory | Inventory The Company’s inventory includes equipment and materials and crude oil inventory. Equipment and materials consist primarily of well equipment, tanks and tubular goods to be used in the Company’s exploration and production activities. Crude oil inventory includes crude oil in tanks and linefill. Linefill represents the minimum volume of product in a pipeline system that enables the system to operate and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Crude oil and NGL linefill in third-party pipelines that is not expected to be withdrawn within one year is included in long-term inventory on the Company’s Consolidated Balance Sheets (see Note 4—Inventory). Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value.
Property, Plant and Equipment | Property, Plant and Equipment Proved Oil and Gas Properties Crude oil, NGL and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and gas properties are capitalized at their estimated net present value. The provision for depletion of oil and gas properties is calculated using the unit-of-production method. All capitalized well costs (including future abandonment costs, net of salvage value) and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of crude oil. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized. The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties by field and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of proved reserves, future commodity prices and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, the Company’s estimated undiscounted future cash flows, the timing and pace of development and the discount rate commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges for proved oil and gas properties will be recorded. Unproved Oil and Gas Properties Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in the Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses its unproved properties periodically for impairment on a prospect-by-prospect basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties: •the remaining amount of unexpired term under its leases; •its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration; •its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development; •its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and •its evaluation of the continuing successful results from the development of properties by the Company or by other operators in areas adjacent to or near the Company’s unproved properties. For sales of entire working interests in unproved properties, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. Capitalized Interest The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off. The Company capitalized interest costs of $4.9 million, $4.1 million and $4.6 million for the years ended December 31, 2024, 2023 and 2022, respectively. Capitalized interest costs are amortized over the life of the related assets. Other Property and Equipment Other property and equipment consists primarily of field office buildings, oilfield equipment, furniture, software, and leasehold improvements, and is recorded at cost and depreciated using the straight-line method based on expected lives of the individual assets (ranging from two years to 30 years) and net of estimated salvage values. The cost of assets disposed of and the associated accumulated DD&A are removed from the Company’s Consolidated Balance Sheets with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statements of Operations. Exploration Expenses Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred. Costs from drilling exploratory wells are initially capitalized but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or the necessary approvals are actively being sought. Impairment The Company reviews its property, plant and equipment for impairment by asset group whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. If events occur that indicate an asset group may not be recoverable, the asset group is tested for recoverability. Proved oil and gas properties. The Company estimates the expected undiscounted future cash flows of its proved oil and gas properties by field and then compares such amount to the carrying amount of the proved oil and gas properties in the applicable field to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company adjusts the carrying amount of the proved oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production volume estimates, the timing and pace of development, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows. These assumptions represent Level 3 inputs,
Goodwill | Goodwill Goodwill represents the excess of consideration paid over the fair value of identified tangible and intangible assets. Goodwill and intangible assets with indefinite lives are not amortized, but are evaluated for impairment annually as of October 1 or more frequently if events or changes in circumstances indicate that the carrying amount might be impaired. For the purpose of the goodwill impairment test, the Company first assesses qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, the Company determines the drivers of fair value of the reporting unit and evaluates whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. This evaluation includes, but is not limited to, assessment of macroeconomic trends, capital accessibility, operating income trends and industry conditions, as well as the Company’s share performance. If an initial qualitative assessment identifies that it is more likely than not that the carrying value of a reporting unit exceeds its estimated fair value, a quantitative evaluation is performed. The quantitative goodwill impairment assessment involves determining the fair value of the reporting unit and comparing it to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, including goodwill, then an impairment charge would be recorded to write down goodwill to its implied fair value. A reporting unit, for the purpose of the impairment test, is at or below the operating segment level, and constitutes a business for which discrete financial information is available and regularly reviewed by segment management. The Company’s single reportable business segment which is the E&P of crude oil, NGLs and natural gas, is the reporting unit that carries the Company’s goodwill balance as of December 31, 2024. The fair value of the reporting unit is estimated using an income approach. Significant inputs used are subject to the judgment and expertise of the Company’s management and include, but are not limited to, future production volumes based upon estimates of reserves prepared by the Company’s reserve engineers, future operating and development costs, future commodity prices (adjusted for basis differentials) and a market-based weighted average cost of capital discount rate. As of October 1, 2024, the Company performed a quantitative assessment as part of its annual goodwill impairment test, and determined that the fair value of the reporting unit substantially exceeded its carrying value. As a result, the Company determined that no adjustment to the carrying value of goodwill was necessary.
Business Combinations | Business Combinations The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed measured at the estimated acquisition date fair value. Transaction and integration costs associated with business combinations are expensed as incurred. The Company makes various assumptions in estimating the fair value of the assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair value of proved and unproved oil and gas properties. The fair value of the oil and gas properties was calculated by a third party valuation expert using an income approach based on the net discounted future cash flows that utilized inputs requiring significant judgment and assumptions, including future production volumes based upon estimates of reserves prepared by the Company’s reserve engineers, future commodity prices (adjusted for basis differentials), future operating and development costs and a market-based weighted average cost of capital discount rate. In addition, when appropriate, the Company reviews comparable transactions between market participants for the purchase and sale of oil and gas properties within the same region to measure fair value, which illustrates the amount a willing buyer and seller would enter into in exchange for such properties. The Company records goodwill for any amount of the consideration transferred in excess of the estimated fair value of the net assets acquired and a bargain purchase gain for any amount of the estimated fair value of net assets acquired in excess of the consideration transferred. Deferred taxes are recorded for any difference between the acquisition date fair value and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. The Company may adjust the provisional amounts recorded in a business combination during the measurement period which extends for up to one year after the acquisition date.
Discontinued Operations | Discontinued Operations The OMP Merger (defined in Note 10—Divestitures) represented a strategic shift for the Company and qualified for reporting as a discontinued operation on February 1, 2022, in accordance with FASB ASC 205-20, Presentation of financial statements – Discontinued Operations (“ASC 205-20”). Accordingly, the results of operations of OMP (defined in Note 10—Divestitures) were classified as discontinued operations in the Consolidated Statements of Operations for the year ended December 31, 2022. There were no discontinued operations for the years ended December 31, 2024 or 2023. The Consolidated Statements of Cash Flows were not required to be reclassified for discontinued operations for any period.
Investment in Unconsolidated Affiliate | Investment in Unconsolidated Affiliate On February 1, 2022, the Company completed the OMP Merger (defined in Note 10—Divestitures) and received common units representing limited partner interests of Crestwood Equity Partners LP, a Delaware limited partnership (“Crestwood”). The Company elected to account for its investment in Crestwood using the fair value option under FASB ASC 825-10, Financial Instruments. Under the fair value option, the Company measures the carrying amount of its investment in Crestwood at fair value each reporting period, with changes in fair value recorded to net gain from investment in unconsolidated affiliate on the Consolidated Statement of Operations. Cash distributions from Crestwood are recorded to net gain from investment in unconsolidated affiliate on the Consolidated Statement of Operations and distributions from investment in unconsolidated affiliate on the Consolidated Statement of Cash Flows. In August 2023, Crestwood and Energy Transfer LP (“Energy Transfer”) entered into a definitive merger agreement to which Energy Transfer would acquire Crestwood. On November 3, 2023, Energy Transfer completed their acquisition of Crestwood, and holders of Crestwood common units received 2.07 Energy Transfer common units for each Crestwood unit held.
Deferred Financing Costs | Deferred Financing Costs The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the Company’s Consolidated Statements of Operations. Deferred financing costs related to the Credit Facility (defined in Note 13—Long-Term Debt) are included in other assets on the Company’s Consolidated Balance Sheets, while deferred financing costs related to the Senior Notes (defined in Note 13—Long-Term Debt) are included as a reduction of long-term debt on the Company’s Consolidated Balance Sheets.
Asset Retirement Obligations | Asset Retirement Obligations In accordance with the FASB’s authoritative guidance on ARO, the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties and produced water disposal wells, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable laws and regulations. The liability is accreted to its present value each period, and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of DD&A in the Company’s Consolidated Statements of Operations. The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 6—Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Revenue Recognition | Revenue Recognition The Company recognizes revenue in accordance with FASB ASC 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Disclosures in accordance with ASC 606 have been provided in Note 3—Revenue Recognition. The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or a bundle of goods or services) at a point in time or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied. The Company’s revenues are predominantly derived from contracts for the sale of crude oil, NGLs and natural gas. Generally, for the crude oil, NGL and natural gas contracts: (i) each unit of commodity product is a separate performance obligation, as the Company’s promise is to sell multiple distinct units of commodity product at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on the Company’s right to invoice at month end for the value of commodity product sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s standalone selling price and recognized as revenue at a point in time, which is typically when production is delivered and title or risk of loss transfers to the customer. The sales prices for crude oil, NGLs and natural gas are market-based and are adjusted for transportation and other related fees and deductions. Fees included in the contract that are incurred after the transfer of control to the customer are included as a reduction of the transaction price, while fees that are incurred prior to the transfer of control to the customer are classified as gathering, processing and transportation expenses in the Company’s Consolidated Statements of Operations. The sales of crude oil, NGL and natural gas as presented on the Company’s Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling crude oil, NGL and natural gas on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. Substantially all of the Company’s crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and the Company’s NGL production is generally sold to purchasers under long-term (more than 12-month) contracts at market-based prices. The Company sells the majority of its production soon after it is produced at various locations, and, as a result, the Company maintains a minimum amount of product inventory in storage. For sales of commodities, the Company records revenue in the month that the production or purchased product is delivered to the purchaser. However, settlement statements and payments are typically not received for 20 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company uses knowledge of its properties, its properties’ historical performance, spot market prices and other factors as the basis for these estimates. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. In certain cases, the Company is required to estimate these volumes during a reporting period and record any differences between the estimated volumes and actual volumes in the following reporting period. Differences between estimated and actual revenues have historically not been significant. Revenue recognized related to performance obligations satisfied in prior reporting periods was not material for the periods presented. The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from third parties. Revenues and expenses from these sales and purchases are recorded on a gross basis when the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with FASB ASC 845, Nonmonetary Transactions. The Company has elected practical expedients, pursuant to ASC 606, to exclude from the presentation of remaining performance obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services and (ii) contracts with an original expected duration of one year or less.
Leases | Leases The Company accounts for leases in accordance with FASB ASC 842, Leases (“ASC 842”). In accordance with ASC 842, the Company determines whether an arrangement is a lease at its inception. The Company’s long-term operating and finance leases consist primarily of office space, vehicles and other property and equipment used in its operations. The operating lease right-of-use (“ROU”) asset also includes any lease incentives received in the recognition of the present value of future lease payments. The Company considers renewal and termination options in determining the lease term used to establish its ROU assets and lease liabilities to the extent the Company is reasonably certain to exercise the renewal or termination. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments. The Company determines the incremental borrowing rate based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases. The Company’s share of operating, variable and short-term lease costs are either capitalized and included in property, plant and equipment on the Company’s Consolidated Balance Sheets or are recognized in the Company’s Consolidated Statements of Operations in lease operating expenses and general and administrative expenses, as applicable. The finance lease costs for the amortization of ROU assets are included in depreciation, depletion and amortization and the interest on lease liabilities is included in interest expense, net of capitalized interest, on the Company’s Consolidated Statements of Operations. The Company has elected practical expedients under ASC 842, including the practical expedient to not reassess under the new standard any prior conclusions about lease identification, lease classification and initial direct costs; the use-of-hindsight practical expedient; the practical expedient to not reassess the prior accounting treatment for existing or expired land easements; and the practical expedient pertaining to combining lease and non-lease components for all asset classes. In addition, the Company elected not to apply the recognition requirements of ASC 842 to leases with terms of one year or less, and as such, recognition of lease payments for short-term leases are recognized in net income on a straight-line basis.
Fair Value Measurement | Fair Value Measurements As defined in FASB ASC 820, Fair Value Measurement (“ASC 820”), fair value is 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 (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows: Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 3 — Pricing inputs are generally unobservable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value. Financial Assets and Liabilities Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The fair value of the Company’s non-financial assets and liabilities measured on a non-recurring basis are determined using valuation techniques that include Level 3 inputs. Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, environmental and regulatory environments. Oil and gas and other properties. The Company records its properties at fair value when acquired in a business combination or upon impairment for proved oil and gas properties and other properties. Fair value is determined using a discounted cash flow model. The inputs used are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials), estimates of future operating and development costs and a risk-adjusted discount rate. Business Combinations. For the following acquisitions, the fair value of the oil and gas properties acquired was calculated using an income approach based on the net discounted future cash flows from the oil and gas properties and related assets acquired. The inputs utilized in the valuation of the oil and gas properties acquired included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the properties’ reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials), operating and development costs, expected future development plans for the properties and the utilization of a discount rate based on a market-based weighted-average cost of capital. The Company also recorded ARO assumed in these acquisitions at fair value. The inputs utilized in valuing the assumed ARO were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of the acquisition date, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk-free rate to discount such costs.
Concentrations of Market and Credit Risk | Concentrations of Market and Credit Risk The future results of the Company’s operations will be affected by the market prices of crude oil, NGLs and natural gas. The availability of a ready market for crude oil, NGL and natural gas products in the future will depend on numerous factors beyond the Company’s control, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, NGLs and natural gas, the regulatory environment, the economic environment and other regional and political events, none of which can be predicted with certainty. Commodity prices have been volatile in recent years and could be volatile in the future. A substantial or extended decline in the price of crude oil could have a material adverse effect on the Company’s financial position, cash flows and results of operations. The Company’s receivables include amounts due from purchasers of its crude oil, NGL and natural gas production and amounts due from joint interest partners for their respective portions of operating expenses and development costs. While certain of these customers and joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long term. The Company manages market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments, which potentially subject the Company to credit risk, consist principally of cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally-insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk.
Risk Management | Risk Management The Company utilizes derivative financial instruments to manage risks related to changes in crude oil, NGL and natural gas prices. As of December 31, 2024, the Company utilized fixed-price swaps and collars to reduce the volatility of crude oil, NGL and natural gas prices on future expected production. See Note 7—Derivative Instruments for additional information. The Company records all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated fair value. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all existing counterparty contracts provide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported in the other income (expense) section of the Company’s Consolidated Statements of Operations and as operating activities in the Company’s Consolidated Statement of Cash Flows. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows. Derivative financial instruments that hedge the price of crude oil, NGL and natural gas are executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. At December 31, 2024, the Company had derivatives in place with 15 counterparties, all of which are secured parties under the Credit Facility (defined in Note 13—Long-Term Debt), which eliminates the need to post or receive collateral associated with its derivative positions. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from the counterparties to its commodity derivative contracts. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions. The Company’s derivative contracts are documented with industry-standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross-collateralization with the properties securing the Credit Facility (defined in Note 13—Long-Term Debt).
Contingencies | Contingencies Certain conditions may exist as of the date the Company’s consolidated financial statements are issued that may result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. The Company’s management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves judgment. In assessing loss contingencies related to legal proceedings that are pending against the Company or unasserted claims that may result in proceedings, the Company’s management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can be estimated, then the estimated undiscounted liability is accrued in the Company’s consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed. Actual results could vary from these estimates and judgments. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.
Environmental Costs | Environmental Costs Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable, and the costs can be reasonably estimated.
Equity-Based Compensation | Equity-Based Compensation The Company has the Chord Energy Corporation Long Term Incentive Plan (the “2020 LTIP”), which provides for the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents, other stock-based awards, cash awards, performance awards or any combination of the foregoing. In connection with the Merger, the Company assumed the Whiting Petroleum Corporation 2020 Equity Incentive Plan (the “Whiting Equity Incentive Plan”), which provides for the grant of incentive stock options, nonstatutory stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and annual incentive awards or any combination of the foregoing. The Company determines the compensation expense for share-settled awards based on the grant date fair value, and such expense is recognized ratably over the requisite service period, which is generally the vesting period. The Company recognizes compensation expense using the straight-line attribution method for service-based awards with a graded vesting feature. Compensation expense for cash-settled awards is recognized over the requisite service period and is remeasured at the fair value of such awards at the end of each reporting period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. Equity awards that settle in shares of common stock are generally net settled by withholding shares of common stock to satisfy income tax withholding obligations due upon vesting. The fair values of awards are determined based on the type of award and may utilize market prices on the date of grant (for service-based equity awards) or at the end of the reporting period (for liability-classified awards), Monte Carlo simulations or other acceptable valuation methodologies, as appropriate for the type of award. A Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. See Note 16—Equity-Based Compensation for additional information. Any excess tax benefit arising from the Company’s equity-based compensation plans is recognized as a credit to income tax expense or benefit in the Company’s Consolidated Statements of Operations.
Treasury Stock | Treasury Stock Treasury stock purchases are recorded at cost and represent shares of common stock repurchased under the Company’s share repurchase program.
Income Taxes | Income Taxes The Company’s provision for taxes includes U.S. federal and state income taxes as well as Canadian federal and provincial income taxes. The Company records its income taxes in accordance with FASB ASC 740 which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from the Company’s estimates, which could impact its financial position, results of operations and cash flows. The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. All deferred tax assets and liabilities, along with any related valuation allowance, are classified as non-current on the Company’s Consolidated Balance Sheets.
Recent Accounting Pronouncements | Recent Accounting Pronouncements In November 2023, the FASB issued ASU No. 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures” (“ASU 2023-07”). This standard clarifies that single reportable segment entities are subject to the disclosure requirements under Topic 280 in its entirety. This ASU is effective for fiscal years beginning after December 15, 2023 and interim periods within those fiscal years beginning after December 15, 2024. The Company adopted this ASU effective December 31, 2024, and applied the amendments retrospectively to all prior periods presented in its consolidated financial statements (see Basis of Presentation above). In December 2023, the FASB issued ASU 2023-09 “Income Taxes (Topic 740): Improvements to Income Tax Disclosures” (“ASU 2023-09”). This standard expands the disclosure requirements for income taxes, specifically relating to the effective tax rate reconciliation and additional disclosures on income taxes paid . ASU 2023-09 is effective for annual reporting periods beginning January 1, 2025, with early adoption permitted. The Company expects to adopt this ASU effective January 1, 2025, and the adoption is not expected to affect the Company’s financial position or results of operations, but will result in additional disclosures. 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”). This standard requires that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating this ASU to determine its impact on the Company’s annual financial statement disclosures.

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