Exhibit 99.2

WildFire Energy I LLC

Annual Report 

For the years ended December 31, 2025 and 2024

TABLE OF CONTENTS

GRANT THORNTON LLP 700 Milam St., Suite 300 Houston, TX 77002   D +1 832 476 3600 F +1 713 655 8741		REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS         Board of Managers   WildFire Energy I LLC   Opinion  We have audited the consolidated financial statements of WildFire Energy I LLC (a Delaware limited liability company) and subsidiaries (the “Company”), which comprise the consolidated balance sheets as of December 31, 2025 and 2024, and the related consolidated statements of operations, unit holders’ equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.   In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.   Basis for opinion  We conducted our audits of the consolidated financial statements in accordance with auditing standards generally accepted in the United States of America (US GAAS). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.   Responsibilities of management for the financial statements  Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.   In preparing the consolidated financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for one year after the date the consolidated financial statements are available to be issued.
		Grant Thornton LLP is a U.S. member firm of Grant Thornton International Ltd (GTIL). GTIL and each of its member firms are separate legal entities and are not a worldwide partnership.

		Auditor’s responsibilities for the audit of the financial statements  Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with US GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the consolidated financial statements.   In performing an audit in accordance with US GAAS, we:
		·	Exercise professional judgment and maintain professional skepticism throughout the audit.
		·	Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements.
		·	Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, no such opinion is expressed.
		·	Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the consolidated financial statements.
		·	Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for a reasonable period of time.
		We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.
		Houston, Texas
		April 8, 2026

WildFire Energy I LLC 

Consolidated Balance Sheets 

(In thousands)

The accompanying notes are an integral part of these consolidated financial statements.

WildFire Energy I LLC 

Consolidated Statements of Operations 

(In thousands)

The accompanying notes are an integral part of these consolidated financial statements.

WildFire Energy I LLC 

Consolidated Statements of Unit Holders' Equity 

(In thousands)

The accompanying notes are an integral part of these consolidated financial statements.

WildFire Energy I LLC 

Consolidated Statements of Cash Flows 

(In thousands)

The accompanying notes are an integral part of these consolidated financial statements.

WildFire Energy I LLC 

Notes to the Consolidated Financial Statements

1. Organization and Summary of Significant Accounting Policies

Organization

WildFire Energy I LLC, a Delaware limited liability company (“WildFire” and together with its consolidated subsidiaries, the “Company”) is an independent energy company focused on the acquisition, exploration and production of oil and natural gas properties in the United States, primarily targeting the Eagle Ford, Woodbine and Austin Chalk formation in East Texas, through the application of modern technology and production optimization. The Company's operations are primarily in the upstream segment of the oil and natural gas industry.

As a holding company, WildFire has no operations and conducts all of its business through its consolidated direct wholly owned subsidiary, WildFire Intermediate Holdings LLC, and its consolidated indirect wholly owned subsidiary WildFire Energy Operating LLC.

Basis of Presentation

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial statements include the accounts of the Company and its subsidiaries after elimination of intercompany transactions and balances. WildFire's sole material assets consist of ownership interests in its consolidated wholly owned subsidiary, WildFire Intermediate Holdings LLC, and there is no material difference of the operations, cash flows, material assets or liabilities between WildFire and WildFire Intermediate Holdings, LLC.

Use of Estimates

The preparation of the Company's consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include cash flow estimates used in impairment tests of long-lived assets, asset retirement obligations, assigning fair value and allocation of purchase price in connection with acquisitions, accrued liabilities, valuation of derivative instruments, accrued revenue and related receivables and depreciation, depletion and amortization. Although management believes these estimates are reasonable, actual results could differ from these estimates.

The Company is not aware of any material revisions to any of its estimates; however, there may be future revisions to the Company's estimates as a result of new accounting pronouncements, changes in ownership interests or other corrections and adjustments common in the oil and natural gas industry, which may relate to prior periods. These adjustments cannot be currently estimated but will be recorded in the period in which the adjustments are known.

Cash and Cash Equivalents

The Company considers all liquid investments purchased with an original maturity of three months or less 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

The Company’s accounts receivables consist mainly of trade receivables from commodity sales, joint interest billings due from co-owners of properties operated by the Company, and trade receivables from sand sales generated by the Company's wholly owned subsidiary, Burleson Sand LLC. 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 oil receivables are collected within one month of sale, and gas and NGLs receivables within two months of sale. Proceeds from the sand mine operations are typically collected within three months of sale. The Company assesses the collectability of accounts receivable based on a broad range of reasonable and forward-looking information including historical losses, current economic conditions, future forecasts and contractual terms. The Company's historical credit losses have been immaterial and are expected to remain so in the future assuming no substantial changes to the economic conditions, business or creditworthiness of the Company. The allowance for credit losses is presented as a reduction to the accounts receivable balance in "Accounts receivable, net" on the accompanying consolidated balance sheets.

Inventories

The Company's inventory consists of sand produced from our mining operations, drill pipe, casing, tubing, and other well equipment and materials to be used in our drilling and completion activities. Inventory balances are reduced by material transfers for inventory usage and are recorded at the lower of cost or net realizable value.

Oil and Natural Gas Properties

The method of accounting for oil and natural gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. The Company uses the successful efforts method of accounting for oil and natural gas properties. For more information see Note 5. Oil and Natural Gas properties.

Other Property and Equipment

Other property and equipment primarily consist of equipment and processing facilities used in sand extraction and processing, natural gas gathering pipelines, compressors, and water infrastructure assets ("Other Operating Assets"). These assets are depreciated using the straight-line method over their estimated useful lives, ranging from 10 to 35 years.

The Company evaluates Other Operating Assets for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Factors used to assess recoverability and determine fair value include, but are not limited to, estimated future revenues, capital expenditures, operating costs, and discount rates appropriate to the associated risks.

Other property and equipment also include furniture and fixtures, buildings, automobiles, leasehold improvements, miscellaneous office equipment, and information technology software/licenses, which are recorded at cost. These assets are depreciated on a straight-line basis over their estimated useful lives, typically ranging from five to fifteen years.

When property and equipment are sold or retired, the related capitalized costs and accumulated depreciation are removed from the accounts. Any resulting gain or loss is recognized in the period of disposition.

Debt Issuance Costs

Debt issuance costs associated with line-of-credit arrangements, including arrangements with no outstanding borrowings, are classified as an asset and amortized over the term of the arrangements. The Company’s policy is to capitalize up front commitment fees and other direct expenses associated with its line-of-credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings.

Asset Retirement Obligations

Asset retirement obligations ("AROs") relate to future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred (typically when a well is completed or acquired or an asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion, amortization and accretion expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset. Revisions typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells, and such revisions result in adjustments to the related capitalized asset and corresponding liability.

Fair Value Measurement

ASC 820, defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC 820 establishes a three-level fair value hierarchy that prioritizes and ranks the level of observability of inputs used to measure investments at fair value based upon the transparency of inputs to the valuation of an asset or liability.

The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC 820 is as follows:

Level 1 – Unadjusted, quoted Prices in active markets for Identical assets or liabilities at the measurement date.

Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument's anticipated life.

Level 3 – Valuations that require inputs that are both unobservable and significant to the fair value measurement. Valuation under Level 3 generally involves a significant degree of judgment from management.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level.

Derivative Instruments

The Company enters into derivative contracts, primarily swaps, to manage its exposure to commodity price risk. All derivative instruments are recorded on the balance sheet as either an asset or liability and measured at fair value. Gains and losses from changes in the fair value of derivative instruments are recognized immediately in earnings. The Company does not enter into derivative instruments for speculative or trading purposes.

Acquisitions

The Company accounts for third-party acquisition under the acquisition method, which among other things, requires the Company to determine if an asset or a business has been acquired.

In an asset acquisition, assets acquired and liabilities assumed are recorded at the acquisition cost as of the acquisition date. Any transaction costs related to the acquisition are capitalized as a component of the purchase price.

In a business combination, assets acquired and liabilities assumed are measured and recorded at fair value as of the acquisition date, recording goodwill for amounts paid in excess of fair value. The fair value of the asset acquired and liabilities assumed is measured based on various estimates. These estimates are based on key assumptions related to the business combination, including review of publicly disclosed information for other acquisitions in the industry, historical experience of the company, data that was available through the public domain and due diligence reviews of the acquired businesses. Acquisition related transaction costs and acquisition related restructuring charges are not included as components of consideration transferred but are accounted for as expenses in the period in which the costs are incurred.

Revenue Recognition

The Company's revenues are comprised of revenue from customers and include the sale of oil, natural gas, NGLs and other operating revenues. The Company believes that the disaggregation of revenue into these four major categories, as presented in the consolidated statements of operations, appropriately depicts the nature of each revenue stream.

Oil, Natural Gas, and NGL Sales

Revenues from the sale of oil, natural gas and NGLs are recognized when production is sold to customers in fulfillment of performance obligations under the terms of agreed contracts. The Company fulfills its performance obligations under its customer contracts through delivery of oil, natural gas and NGLs and revenues are recorded on a monthly basis and the Company receives payment from one to two months after delivery. The Company recognizes revenues from the sale of oil, natural gas and NGLs using the sales method of accounting, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced.

Sales of oil, natural gas and NGLs are recognized at the point the control of the commodity is transferred to the customer and the Company has no further obligations to perform related to the sale. The majority of the Company’s contracts contain variable consideration based on pricing provisions that are tied to a commodity market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas and prevailing supply and demand conditions. The nature of the contracts with customers does not require the Company to estimate that variable consideration or to estimate the nature of the transaction price attributable to future performance obligations for accounting purposes. As a result, the price of oil, natural gas and NGLs fluctuate to remain competitive with other available supplies.

Under its oil sales contracts, the Company generally sells oil to the purchaser at the wellhead and collects a contractually agreed upon index price, net of pricing differentials. The Company recognizes revenue based on the contract price when control transfers to the purchaser at the wellhead. The Company has determined that its oil sales contracts represent performance obligations that are satisfied at the point in which control of the oil transfers to the purchaser.

Under the Company’s natural gas sales contracts, the Company delivers the natural gas to the purchaser at an agreed upon delivery point. The purchaser gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas, net of processing costs. In these scenarios, the Company has evaluated the point at which control of the hydrocarbons transfer to the customer. The Company concluded that for its contracts, the midstream processing entity is its customer and controls the hydrocarbons and, as a result, recognizes natural gas and NGLs revenues based on the net amount of the proceeds received from the midstream processing entity. Therefore, the Company has determined that the performance obligation for its natural gas sales contracts is the point at which natural gas is delivered to the purchaser at an agreed upon delivery point.

Revenue from the sale of natural gas is recorded on the basis of natural gas actually sold by the Company. If aggregate sales volumes for a well are greater (or less) than the Company’s proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.

The Company records revenue on its oil, natural gas and NGL sales at the time production is delivered to the purchaser. However, settlement statements for oil, natural gas and NGL sales may not be received for 30 to 60 days after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products. The Company records the differences between the revenue estimated and the actual amounts received for product sales in the month that payment is received from the customer. Differences between revenue estimates and actual revenue received historically have not been significant.

Other Operating Revenues

Other operating revenues primarily consist of sand sales from the Company's wholly owned subsidiary, Burleson Sand LLC . The revenue is generated from processing and selling sand, which is used as a proppant in the hydraulic fracturing process.

Revenues from the sale of sand is recognized when control of the processed sand is transferred to the customer. The Company fulfills its performance obligations under the terms of the customer's contract when control of the processed sand transfers to the customer, which generally occurs when the sand is loaded onto the customer's truck at the loadout facility. The transaction price is determined based on contractual arrangements and is calculated on a per ton basis.

Revenues are recognized when control of the processed sand is transferred to customer trucks at the loadout facility of the sand mine. For the years ended December 31, 2025 and 2024, revenue from the Company's sand mine operations were $30.1 million and $27.6 million, respectively.

Leases

The Company currently has leases associated with contracts for office space, vehicle fleet, drilling rigs, and the use of well equipment. For leases with a primary term of more than 12 months, a right-of-use asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. All of the Company's leases are operating leases.

Right-of-use assets and lease liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. The majority of leases do not include an implicit interest rate. When the lease contract does not contain an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. Leased assets may be used in joint operations with other working interest owners. When the Company is the operator in a joint arrangement, the right-of-use assets and lease liabilities are determined on a gross basis. Certain leases contain variable costs above the minimum required payments and are not included in the right-of-use assets or lease liabilities. Options to extend or terminate a lease are included in the lease term when it is reasonably certain the Company will exercise that option.

For operating leases, lease cost is recognized on a straight-line basis over the term of the lease. Leases with an initial term of 12 months or less are not recorded on the consolidated balance sheet. The Company elected a practical expedient to not separate non-lease components from lease components for the following asset types: office space, drilling rigs, and field equipment.

Concentration of Credit Risk

The Company’s cash and cash equivalents, accounts receivable, long-term debt and derivative contracts are exposed to concentrations of credit risk. The Company manages and controls this risk by placing these funds with major institutions and monitoring the creditworthiness of the Company’s counterparties.

The derivative contracts held by the Company are with counterparties who are a participant in the Company’s credit facility and have investment-grade ratings from Moody’s and Standard and Poor’s. At times, cash balances held at commercial banks may exceed the Federal Deposit Insurance Corporation limit. The Company has not experienced any credit losses to date.

The Company is exposed to credit risk in the event of nonpayment by counterparties, all of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to continuing review. For the year ended December 31, 2025, Energy Transfer Crude Marketing, LLC accounted for approximately 85% of the Company’s total net revenues and approximately 64% of the Company's accrued oil and gas revenue receivables. For the year ended December 31, 2024, Energy Transfer Crude Marketing, LLC accounted for approximately 90% of the Company’s total net revenues and approximately 76% of the Company's accrued oil and gas revenue receivables.

Commitment and Contingencies

Accruals for loss contingencies arising from claims, assessments, litigation, environmental, and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information become available or circumstances change. Refer to Note 9 - Commitments and Contingencies for additional information.

Income Taxes

The Company is a Limited Liability Company (LLC) and is treated as a pass-through entity for U.S. federal income tax purposes. As a result, federal income taxes are the responsibility of its individual members, and the accompanying financial statements do not include a provision or liability for federal income taxes.

The Company is subject to the Texas margin tax, which qualifies as an income tax under ASC 740. The Texas margin tax is imposed at a statutory rate of up to 0.75% on the portion of income apportioned to Texas. Accordingly, the Company recognizes current and deferred taxes for temporary differences between the book and tax basis of assets and liabilities to the extent applicable to this tax.

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The Company files state tax returns in jurisdictions where it has tax obligations and an informational federal return, as required for a pass-through entity.

Segment Reporting

The Company operates as a single reportable segment focused on the acquisition, development, exploration, and production of oil and natural gas properties (the “Operating Segment”). The Company's operations are concentrated in one geographic area, the United States. Revenues from the Operating Segment, including sales of oil, natural gas, and NGLs, are disaggregated and presented in the consolidated statements of operations.

The Company’s Chief Operating Decision Maker (“CODM”), the Chief Executive Officer, evaluates performance and makes key operating decisions using net income and significant expenses reported in the consolidated statements of operations. Additionally, the CODM utilizes cash flows reported in the consolidated statement of cash flows to guide investment decisions, including future development and capital expenditures, evaluating potential acquisitions, optimizing capital returns, and managing strategic sources and uses of capital.

Recent Accounting Pronouncements

In March 2024, the FASB issued ASU 2024-01, Compensation-Stock Compensation (Topic 718): Scope Application of Profits Interest and Similar Awards, which provides illustrative guidance to help entities determine whether profits interest and similar awards should be accounted for as share-based payment arrangements within the scope of ASC 718, Compensation-Stock Compensation. The guidance is effective for the Company for annual and interim periods beginning after December 15, 2025. The Company is evaluating the impact of this standard on its financial statements and disclosures.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosure. The guidance aims to improve the effectiveness of income tax disclosure primarily through improvements to the income tax rate reconciliation disclosure along with information on income taxes paid. The guidance is effective for the Company for annual and quarterly periods beginning after December 15, 2025, with early adoption permitted. The Company elected to adopt this guidance for the year ended December 31, 2025. As the Company is a pass-through entity for federal income tax purposes and is primarily subject to state franchise taxes, the adoption of this standard did not have a material impact on its consolidated financial statements or disclosures.

2. Acquisitions and Divestitures

2025 Bolt-on Asset Acquisitions

During the year ended December 31, 2025, WildFire completed eight bolt-on acquisitions of oil and natural gas properties for a cumulative adjusted purchase price of approximately $4.1 million. These transactions were recorded as asset acquisitions in accordance with ASC Topic 805, Business Combinations.

Apache Acquisition

On June 12, 2024, WildFire closed on a purchase and sale agreement ("Apache Acquisition") to purchase Apache Corporation's ("Apache") interest in certain oil and natural gas producing properties in the Eagle Ford Basin in East Texas, including approximately 213,000 net acres and 156 net wells. WildFire closed on the Apache Acquisition for cash consideration of approximately $302.0 million due at closing, subject to certain purchase price adjustments.

The Apache Acquisition was accounted for as an asset acquisition. The purchase price was allocated to the underlying assets acquired and liabilities assumed at the closing date. Costs directly related to the acquisition were capitalized as a component of the purchase price.

Pro Forma Condensed Results of Operations

The following unaudited supplemental pro forma condensed results of operations present consolidated information for the year ended December 31, 2024 as if the Apache Acquisition had been completed on January 1, 2024. This information was derived from the historical statements of revenues and direct operating expenses of Apache, and the consolidated statements of operations of WildFire, with adjustments to include:

These unaudited supplemental pro forma results are provided for illustrative purposes only and are not indicative of the actual results that would have been achieved for the periods presented or that may be achieved in the future. Actual future results may differ significantly from those presented in these unaudited pro forma results (in thousands):

3. Derivative Financial Instruments

The Company is exposed to certain risks relating to its ongoing business operations and uses derivative instruments to manage its commodity price risk.

Commodity Derivative Instruments

The Company enters into derivative contracts, primarily swaps, to achieve a more predictable cash flow by reducing its exposure to commodity price volatility. The derivative instruments are not formally designated as hedges for accounting purposes. Commodity derivative contracts are thereby used to ensure adequate cash flow to fund the Company’s capital programs and to manage returns on acquisitions and drilling programs. Swaps are designed to establish a fixed price for anticipated future oil and natural gas production. The Company does not enter into derivative contracts for speculative or trading purposes.

The Company had the following open crude oil and natural gas derivative contracts at December 31, 2025:

Balance Sheet Presentation

The Company’s commodity derivatives are measured at fair value and are included in the accompanying consolidated balance sheets as a derivative asset or liability. The Company had a net derivative asset of $112.2 million as of December 31, 2025, and a net derivative liability of $27.8 million as of December 31, 2024. The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet as of December 31, 2025 and 2024 (in thousands). There was no cash collateral received or pledged associated with our derivative instruments since the counterparties to our derivative contracts are lenders under our collective credit agreements.

None of the Company’s derivative instruments contain credit-risk-related contingent features. The counterparties to the Company’s derivative contracts are high credit-quality financial institutions that are lenders under the Company’s credit agreement. The Company uses only credit agreement participants to hedge with, since these institutions are secured equally with the holders of the Company’s bank debt, which eliminates the potential need to post collateral when the Company is in a derivative liability position.

Gain & (Loss) on Derivatives

All gains and losses, including changes in the derivative instruments’ fair values, are included as a component of “Other income (expense)” in the Consolidated Statements of Operations. The following table details the gains and losses related to derivative instruments for the years ended December 31, 2025 and 2024 (in thousands):

4. Fair Value Measurements

Fair Value on a Recurring Basis

Derivative Financial Instruments

Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of fixed price and basis swap agreements. The Company’s commodity price hedges are valued based on discounted future cash flow models that are primarily based on published forward commodity price curves. These inputs are designated as Level 2 within the valuation hierarchy.

The fair values of derivative instruments in asset positions include measures of counterparty nonperformance risk, and the fair values of derivative instruments in liability positions include measures of the Company’s nonperformance risk. These measurements were not material to the Consolidated Financial Statements.

The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair value hierarchy (in thousands):

Commodity derivative instrument models consider various assumptions, including quoted forward prices for commodities, time value and volatility. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The discount rates used in the fair values of these instruments include a measure of either the Company’s or the counterparty’s nonperformance risk, as appropriate. The Company utilizes its counterparty’s valuations to assess the reasonableness of its own valuations.

There were no transfers between fair value hierarchy levels for the years ended December 31, 2025 and 2024.

Fair Value on a Nonrecurring Basis

The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and natural gas properties, business combination and asset retirement obligations. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value estimation when acquisitions occur or asset retirement obligations are recorded. These are considered Level 3 valuations. See further discussion in Note 2, "Acquisitions and Divestitures".

Asset retirement obligations are recorded at fair value 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. To estimate the future ARO, management must make judgments and estimates regarding the timing and existence of a liability and what constitutes sufficient restoration under the current regulatory requirements. Fair value calculations inherently involve numerous assumptions and judgments such as the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.

Items Not Recorded at Fair Value

The carrying amounts reported on the consolidated balance sheets for cash, accounts receivable, prepaid expenses, other current assets, accounts payable, revenues and royalties payable, accrued expenses and other current liabilities approximate their fair values.

The Company has not elected to account for its debt instruments at fair value. Borrowing under the revolving credit facility bear interest at floating market rates, therefore the carrying amount and fair value were approximately equal as of December 31, 2025 and 2024. The 7.5% Unsecured Senior Notes due 2029 had a carrying value of $589.6 million, net of $10.4 million in deferred financing costs, and an estimated fair value of $605.7 million as of December 31, 2025.

5. Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas properties. Under this method, costs to acquire oil and natural gas properties, drill and equip exploratory wells that discover proved reserves, and drill and equip development wells are capitalized. Costs of drilling exploratory wells are capitalized as wells-in-progress until a determination is made as to whether the well has found proved reserves. Exploration costs, such as geological and geophysical expenses, delay rentals, and exploration overhead, are expensed as incurred. During the year ended December 31, 2025, the Company successfully completed one exploratory well. Total costs of $10.0 million associated with this well were capitalized and transferred to proved oil and natural gas properties during the period. As of December 31, 2025 and 2024, there were no exploratory well costs capitalized pending the determination of proved reserves.

Proceeds from the sale of individual properties and the related capitalized costs are credited to the net book value of the amortization group, provided this does not materially impact the depletion rate of the group. Generally, no gain or loss is recognized unless an entire depletion group is sold. However, a gain or loss may be recognized on the sale of less than an entire depletion group if the transaction is significant enough to materially affect the depletion rate of the remaining properties in the group.

Costs incurred to maintain wells and related equipment, lease and well operating costs, and other exploration costs are expensed as incurred.

Lease acquisition costs and development costs of proved oil and natural gas properties are depleted using the units-of-production method at the depletion group level. Total proved reserves are used as the basis for depleting lease acquisition costs, while proved developed reserves are used for depleting development costs. Properties are grouped based on reasonable aggregation of those with a common geological structure or stratigraphic condition, such as a reservoir or field.

Depletion expense for oil and natural gas properties and related equipment was $264.2 million and $234.1 million for the years ended December 31, 2025 and 2024, respectively.

Proved oil and natural gas properties

The Company assesses its proved oil and natural gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment charge reduces the carrying value of the assets to their estimated fair value. These fair value measurements are classified as Level 3 in the fair value hierarchy and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and natural gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets.

Unproved properties

Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. Unproved oil and natural gas leases are generally for a primary term of three to five years. In most cases, the term of the unproved leases can be extended by paying delay rentals, meeting contractual drilling obligations, or by the presence of producing wells on the leases. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and natural gas properties. Costs of maintaining and retaining unproved properties, as well as impairment of unsuccessful leases, are included in “Exploration expenses” in the consolidated statements of operations.

Unproved properties are assessed for impairment at least annually on a property-by-property basis based on the Company's current exploration plans, and based on remaining lease terms, commodity price outlook, future plans to develop acreage, drilling results and reservoir performance of wells in the area.

Impairment to oil and natural gas properties

The Company recorded no non-cash asset impairment charges for the years ended December 31, 2025 and 2024.

6. Asset Retirement Obligations

The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage, and land restoration in accordance with applicable local, state and federal laws. The Company determines its asset retirement obligation amounts by calculating the present value of the estimated future cash outflows associated with its plug and abandonment obligations. The associated asset retirement costs are capitalized as part of the carrying amount of proved properties. Subsequent to initial measurement, the ARO liability is required to be accreted each period. The following table provides a reconciliation of the Company’s asset retirement obligations (in thousands):

7. Long–Term Debt

Long-term debt consisted of the following as of December 31, 2025 and 2024 (in thousands):

Wildfire Revolving Credit Facility

The Company has a credit agreement with a syndicate of 19 banks, including JPMorgan Chase Bank, N.A., as the administrative agent, that provides for a secured revolving credit facility, maturing on March 19, 2029 ("the "Credit Agreement"). The Company may extend the maturity date by providing written notice to the administrative agent. As of December 31, 2025, the Credit Agreement had a borrowing base and an elected commitment of $1.5 billion. As of December 31, 2025, the Company had $70.0 million drawn and over $1.4 billion in available borrowing capacity under the revolving credit facility.

The borrowing base is determined at the discretion of the lenders and is subject to scheduled redeterminations semiannually on May 1 and November 1. The Credit Agreement also allows for two optional interim borrowing base redeterminations, one at the request of the Company and one at the request of the lenders. The borrowing base depends on, among other factors, the quantities of the Company's proved oil and natural gas reserves, their associated cash flows, and hedge positions. Upon a redetermination, if the outstanding borrowings exceed the revised borrowing base, the Company could be required to immediately repay a portion of the outstanding balance. The next scheduled redetermination is expected to occur on May 1, 2026. Borrowings under the Credit Agreement are collateralized by substantially all of the Company's assets.

Pursuant to the Senior Notes Offering in September 2024, the Company entered into the First Amendment to its Credit Agreement (the "First Amendment"). The First Amendment, among other things, permits the issuance of up to $650 million in senior notes without a reduction to the borrowing base, provided that 75% of the net cash proceeds from the issuance are used to repay a portion of the outstanding borrowings under the revolving credit facility.

In November 2025, in connection with the fall borrowing base redetermination, the Company entered into the third amendment (the “Third Amendment”) to its senior secured revolving credit facility. Among other things, the Third Amendment extended the maturity date of the facility from March 19, 2027, to March 19, 2029, reduced the applicable interest rate margins, allowed for more flexibility for term loan borrowings, and reaffirmed both the borrowing base and elected commitments at $1.5 billion.

Borrowings under the Credit Agreement may be Term Benchmark Loans or Alternate Base Loans. Interest is payable at the end of the applicable interest period for Term Benchmark Loans and quarterly for Alternate Base Loans. Term Benchmark Loans bear interest at SOFR plus an applicable margin that varies based on the percentage of elected commitments utilized, plus an additional 10 basis point credit spread adjustment. Alternate Base Loans bear interest at a rate per annum equal to the greatest of (i) the prime rate, (ii) the federal funds effective rate plus 0.5%, or (iii) the adjusted Term SOFR rate for a one-month interest period plus 1%, plus an applicable margin that varies based on the percentage of elected commitments utilized. Commitment fees are 0.50%, regardless of the utilization level. The following table provides the Borrowing Base Utilization Margins as defined in the Fourth Amendment:

The Credit Agreement contains restrictive covenants that may limit the Company’s ability to, among other things, incur additional indebtedness, sell assets, make loans, make investments, enter into mergers, enter into hedging contracts, incur liens, and engage in certain other transactions without prior lender consent. Additionally, it limits the Company’s ability to make distributions to investors unless it maintains certain financial covenants as defined in the Credit Agreement.

The Credit Agreement also requires the Company to maintain compliance with the following financial ratios as of the end of each quarter:

(i) a current ratio, which is the ratio of consolidated current assets (including an add-back of unused commitments under the revolving credit facility and excluding non-cash derivative assets) to consolidated current liabilities (excluding non-cash derivative liabilities), of not less than 1.0 to 1.0; and

(ii) a Consolidated Total Leverage Ratio, as defined in the Credit Agreement, which is the ratio of total debt to the last four quarters' consolidated EBITDAX for the rolling period then ending, of not greater than 3.0 to 1.0.

The Company was in compliance with the covenants and the applicable financial ratios described above as of December 31, 2025 and 2024.

For the years ended December 31, 2025 and 2024, interest expense and commitment fees incurred on the revolving credit facility were $15.8 million and $61.4 million, respectively, net of capitalized interest of $3.3 million and $1.5 million, respectively. For years ended December 31, 2025 and 2024, the weighted average interest rate on borrowings under the revolving credit facility averaged 6.88% and 8.73% per annum, respectively, which excluded commitment fees and amortization of deferred financing costs.

7.5% Unsecured Senior Notes due 2029

On September 26, 2024, WildFire issued $600 million aggregate principal amount of unsecured 7.5% senior notes due 2029 (the "Notes") for net proceeds of $588.0 million, after deducting commissions and transaction costs (the "Notes Offering"). The net proceeds from the offering were used to repay a portion of the outstanding borrowing under the revolving credit facility.

In connection with the completion of the Notes Offering, WildFire, entered into an indenture, dated as of September 26, 2024 (the "Indenture"), among WildFire, its subsidiaries ("Guarantors"), and U.S. Bank Trust Company, National Association, as Trustee.

The notes will mature on October 15, 2029 with interest accruing at a rate of 7.5% per annum in cash in arrears on April 15 and October 15 of each year, commencing April 15, 2025. Before October 15, 2026, the Company may redeem some or all of the Notes at a redemption price equal to 100% of the aggregate principal amount of the Notes redeemed plus applicable premium, as defined in the Indenture, and any accrued and unpaid interest. Alternatively, the Company can redeem up to 40% of the aggregate principal amount with equity offering proceeds at a redemption price equal to 107.5% of the aggregate principal amount of the Notes plus accrued and unpaid interest if at least 60% of the aggregate principal amount of the Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such offering. The Company may redeem, at its option, all or part of the Notes at any time on or after October 15, 2026, at the redemption price of 103.75% and 101.87% in 2026 and 2027, respectively, and at a redemption price of 100.00% thereafter plus accrued and unpaid interest. Upon a Change of Control event, as defined in the indenture, the Company may be required to offer to repurchase the Notes on terms and conditions set forth in detail in the Indenture.

The Notes are guaranteed on a senior unsecured basis by the Company and its subsidiaries and may be guaranteed by the Company's future restricted subsidiaries. The Notes are unsecured, rank equally in right of payment with all existing and future senior unsecured indebtedness of the Company and the Guarantors, and rank senior in right of payment to any future subordinated indebtedness of the Company and the Guarantors. The Notes will rank effectively subordinated in right of payment to all of our existing and future secured indebtedness of the Company and the Guarantors, including indebtedness under the revolving credit facility, to the extent of the value of the assets securing such indebtedness. The Notes will rank structurally subordinated to all existing and future indebtedness, claims of holders of preferred stock and other liabilities of any non-guarantor subsidiaries (other than indebtedness and other liabilities owed to the Company).

The Indenture restricts the Company's ability and the ability of its restricted subsidiaries, as defined in the indenture, including the Guarantors, to: (i) incur or guarantee additional indebtedness; (ii) pay dividends or make any other distributions to any of the restricted subsidiaries that is a guarantor; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) consolidate, merge or transfer all or substantially all of its assets; (vii) engage in transactions with affiliates; and (viii) create unrestricted subsidiaries. These restrictions will be suspended if the Notes achieve an investment grade Rating, as defined in the indenture, or better from two of three of Moody’s Investors Service, Inc., S&P Global Ratings, or Fitch Ratings, Inc.

The Indenture contains customary events of default (each an “Event of Default”). If an Event of Default occurs and is continuing, the Trustee or the holders of not less than 25% in aggregate principal amount of the outstanding Notes may declare the unpaid principal of, premium, if any, and accrued but unpaid interest on, all the Notes then outstanding to be due and payable immediately. Upon such a declaration, such principal, premium, if any, and interest will be due and payable immediately. If an Event of Default relating to certain events of bankruptcy or insolvency of the Company or any Significant Subsidiary (as defined in the Indenture) occurs, the principal of, premium, if any, and the interest on, all the Notes will become immediately due and payable without any declaration or other act on the part of the Trustee or any holders of the Notes. Under certain circumstances, the holders of a majority in principal amount of the outstanding Notes may rescind any such acceleration with respect to the Notes and its consequences.

In connection with the offering, the Company incurred commissions and transaction costs of approximately $13.3 million. These costs are capitalized and amortized using the effective interest rate method over the term of the Notes and are included in Consolidated Statement of Operations. The unamortized portion of these deferred financing costs is included as a reduction to the carrying value of the Notes.

For the years ended December 31, 2025 and 2024, the Company recorded a total interest expense of $47.3 million and $12.3 million, respectively, associated with the notes, including the amortization of commissions and issuance costs.

Deferred Acquisition Costs

In connection to the Chesapeake Acquisition, the Company recognized a debt obligation for deferred payments of $60 million due on each of March 1 of 2024, 2025 and 2026, and $45 million due on March 1, 2027. These payments were recorded at their present value, upon the acquisition close date. The present value of the deferred payments was calculated using an appropriate discount rate, reflecting the time value of money. Subsequent to the initial recognition, the balances are being accreted to their face value using the effective interest method, and an interest expense is recognized in the statement of operations. Any changes in the carrying amount of the debt due to accretion are recognized as interest expense in the period incurred. For the years ended December 31, 2025 and 2024, interest expense incurred on the deferred acquisition costs was $8.0 million and $11.6 million, respectively.

Maturities of Long-Term Debt

Long-term debt maturities are based on contractual agreements and do not reflect any potential refinancing, prepayments, or amendments that may occur in the future. Borrowings under the Company’s revolving credit facility are presented based on their contractual maturity date, although the Company has the ability to extend or refinance such obligations.

The following table summarizes the scheduled maturities of principal payments on the Company's outstanding Long-Term Debt as of December 31, 2025 (in thousands):

8. Leases

The table below provides consolidated balance sheet information related to leases as of December 31, 2025 and 2024 (in thousands):

For the years ended December 31, 2025 and 2024, the Company incurred $1.1 million and $0.9 million, respectively, of operating lease costs, which were included in General and administrative expenses. For the years ended December 31, 2025 and 2024, the Company incurred $0.8 million and $0.5 million, respectively, of operating lease costs, which were included in lease operating expenses. The Company’s short-term leases are primarily composed of drilling rigs and certain field equipment. During the years ended December 31, 2025, the Company’s gross lease costs related to its short-term leases were $25.8 million and $22.1 million, respectively, of which $13.8 million and $11.0 million were capitalized as part of oil and natural gas properties with the remainder charged to lease operating expenses, respectively. A portion of these costs was reimbursed to the Company by other working interest owners. The remaining weighted average lease term for our operating leases is 4.44 years with a weighted average discount rate of 7.51% as of December 31, 2025.

As of December 31, 2025, minimum annual lease commitments for the remaining calendar years are as follows (in thousands):

9. Commitments and Contingencies

Legal

From time to time, the Company may be involved in various legal proceedings and claims in the ordinary course of business. In management’s opinion, the outcome of any such currently pending legal action will not have a material adverse effect on our financial positions or results of operations.

Environmental and Governmental Regulation

Many aspects of the oil and natural gas industry are extensively regulated by federal, state, and local governments in the area in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, royalty rates, and various other matters, including taxation. Oil and natural gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2025 and 2024, the Company has not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon its financial condition.

In 2024, the Company recorded an accrual of $2.0 million related to the methane waste emissions charge established under the Inflation Reduction Act and the U.S. Environmental Protection Agency's (“EPA”) implementing rule, which was included in accrued liabilities and other operating expenses. On February 27, 2025, the United States Senate passed a joint resolution disapproving of the EPA’s rule implementing this charge. The resolution was signed into law on March 14, 2025, rendering the rule ineffective. As a result, the Company reversed the $2.0 million accrual during the first quarter of 2025, resulting in a corresponding reduction to other operating expenses for the year ended December 31, 2025. We continue to monitor federal legislative and regulatory developments, including recent budget and appropriations measures, which may further impact future methane-related obligations.

Lease Commitments:

Refer to Note 8 - Leases for details on the Company's operating lease agreements.

10. Income Taxes

The Company has calculated a state income tax expense of $4.0 million and $4.3 million for the years ended December 31, 2025 and 2024, respectively, which included a deferred income tax expense of $3.8 million and $2.7 million, respectively.

The Company had no significant uncertain tax positions and has not recorded any liabilities as of December 31, 2025 and December 31, 2024. As of December 31, 2025 and 2024, the Company made no provision for interest or penalties related to uncertain tax positions.

There are currently no federal or state income tax examinations under way and tax returns for the periods ended December 31, 2019 through the current year are still open to examination.

11. Defined Contribution Plan

The Company sponsors a 401(k) defined contribution plan for the benefit of all employees at the date of hire. The plan allows employees to make contributions of their annual compensation up to the annual limits established by the federal government. The Company makes contributions of 6% of an employee’s compensation up to annual limits established by the federal government and employees are fully vested in the employer contribution upon receipt. The Company contributed $0.7 million and $0.5 million for the years ended December 31, 2025 and 2024, respectively. These amounts were recorded as “General and administrative expenses” on the accompanying consolidated statements of operations.

12. Incentive Units

The Limited Liability Company Agreement (the "Company Agreement") allows for the sharing of gain upon monetization either through a return of capital contributions, plus multiples of capital, through recapitalization, sale or merger or through a return of capital to the unit holders through other means.

The Company Agreement allows for the sharing of gain upon monetization through Series B units (“incentive units”). From time to time, the Board of Directors has and may issue incentive units in consideration of services rendered by employees. The payout is generally dependent upon monetization achieved by the incentive unit holders’, with payments in the form of cash.

The amount of participation by incentive unit holders can vary depending upon the level of monetization achieved by the unit holders. The incentive units are being accounted for as liability-classified awards as achievement of the payout conditions are required for settlement of such awards by transferring cash to the incentive unit holder. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date.

For the years ended December 31, 2025 and 2024, the Board of Directors authorized cash distributions of $156.8 million and $78.4 million, respectively, to unit holders as a return of contributed capital. For the year ended December 31, 2025 the board authorized special advance distributions to incentive unit holders of $3.2 million, which was recorded as compensation expense. No other special distributions to incentive unit holders were declared by the Board of Directors as of December 31, 2025.

13. Related Party Transactions

The Company has not identified any related party transactions during the years ended December 31, 2025 and 2024.

14. Subsequent Events

The Company evaluated subsequent events occurring after December 31, 2025 through April 8, 2026, the date our consolidated financial statements were available for issuance.

In January 2026, the Company restructured its 2028 crude oil derivative contracts by entering into offsetting purchase contracts and simultaneously executing new crude oil sale contracts for the 2026 calendar year. The transaction was designed to monetize the value of the 2028 positions to support 2026 cash flows. The Company is finalizing its evaluation of the accounting treatment and the resulting impact on the 2026 consolidated financial statements and cash flow classifications.

On January 14, 2026, the Company made cash distributions of $49.0 million to unit holders as a return of contributed capital and made special advance distributions of $1.0 million to incentive unit holders. The distributions were authorized by the Board of Directors and recorded as unit holders’ distributions and compensation expense, respectively, in 2026.

On February 27, 2026, the Company made its third deferred payment of $60.0 million in connection with the Chesapeake Acquisition, which was completed on March 20, 2023. The payment was part of the consideration for the acquisition and was accounted for as a liability at its present value on the acquisition date.

15. Supplemental Disclosures

Accounts Receivable

The following table summarizes the Company's accounts receivable as of December 31, 2025 and 2024 (in thousands):

The following table reflects the Company's beginning and ending balances of its accounts receivables from purchasers of its oil, natural gas and NGLs for the years ended December 31, 2025 and 2024 (in thousands):

The following table summarizes the activity in the balance of allowance for credit losses related to account receivable (in thousands):

Revenue and Royalties Payable

The following table summarizes the Company's revenues held in suspense and royalties payable as of December 31, 2025 and 2024 (in thousands):

Accrued Expenses

The following table summarizes the Company's current accrued expenses as of December 31, 2025 and 2024 (in thousands):

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2025 and 2024 (in thousands):

16. Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

The Company operates in one reportable segment engaged in the acquisition, development, exploration, and production of oil and natural gas properties located in the United States.

Costs Incurred Related to Oil and Gas Activities

Capitalized costs represent the costs incurred for properties, equipment, and facilities related to oil and natural gas producing activities. For proved oil and natural gas properties, these include the costs of acquiring oil and natural gas leaseholds with identified proved reserves, development wells, related equipment, and facilities, as well as development wells in progress. For unproved oil and natural gas properties, capitalized costs consist of expenditures for acquiring leaseholds where no proved reserves have yet been identified.

The table below summarizes costs incurred in oil and natural gas producing activities for the years ended December 31, 2025 and 2024 (in thousands):

For the years ended December 31, 2025 and 2024, additions to oil and natural gas properties included $10.6 million and $14.7 million, respectively, for estimated future abandonment costs associated with newly drilled or acquired wells. Additionally, it included $3.3 million and $1.5 million of capitalized interest on debt, respectively, for the same periods.

Capitalized Costs

Capitalized costs, impairment, and depreciation, depletion, and amortization related to the Company’s oil and natural gas producing activities as of December 31, 2025 and 2024 are summarized as follows (in thousands):

Oil and Natural Gas Reserves

The process of estimating quantities of proved and proved developed oil and natural gas reserve is a complex process, requiring significant subjective decisions while assessing all available geological and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Therefore, revisions to existing reserve estimates may occur. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from oil and natural gas properties. The proved reserve estimates provided below have been prepared by Netherland, Sewell & Associates, Inc ("NSAI"), an independent petroleum engineering company. In preparing the reserve reports, NSAI evaluated 100% of the Company's properties.

The proved reserves shown herein for the years ended December 31, 2025 and 2024 were estimated in accordance with the guidelines established by the SEC, which require reserves estimates be prepared under existing economic and operating conditions based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices.

The reserve information shown in these Consolidated Financial Statements represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. As a result, estimates by different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The reliability of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced.

The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed and proved undeveloped reserves for the years ended December 31, 2025 and 2024. Oil prices as of December 31, 2025 and 2024 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate (“WTI”) spot prices of $66.01 per barrel and $76.32 per barrel, respectively. Natural gas prices as of December 31, 2025 and 2024 are based on the respective 12-month unweighted average of the first of the month prices of the Henry Hub spot price of $3.39 per MMBtu and $2.13 per MMBtu, respectively. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics. NGLs prices used to value reserves as of December 31, 2025 and 2024 averaged $20.26 per barrel and $19.50 per barrel, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials, to estimate oil, natural gas and NGLs reserves. As of December 31, 2025, oil, natural gas and NGLs reserves were valued using prices of $65.20 per barrel, $2.72 per MMBtu and $20.26 per barrel, respectively. As of December 31, 2024, oil, natural gas and NGLs reserves were valued using prices of $75.70 per barrel, $1.58 per MMBtu and $19.50 per barrel, respectively. All prices are held constant in accordance with SEC guidelines.

A summary of the Company's changes in quantities of proved reserves for the years ended December 31, 2025 and 2024 are as follows:

1) Barrels of oil equivalents have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (Boe).

For the years ended December 31, 2025 and 2024, acquisitions contributed to proved reserves approximately 0.2 MMBoe and 36.7 MMBoe, respectively. For the year ended December 31, 2025, the acquired reserves were related to eight bolt-on acquisitions of oil and natural gas properties. For the year ended December 31, 2024, the acquired reserves were primarily related to oil and natural gas properties acquired from Apache Corporation in the Eagle Ford Basin in East Texas.

For the years ended December 31, 2025 and 2024, extensions contributed to proved reserves approximately 50.3 MMBoe and 16.5 MMBoe, respectively. These were primarily related to the development of new well locations.

For the years ended December 31, 2025 and 2024, the Company had negative revisions to proved reserves of approximately 16.5 MMBoe and 10.3 MMBoe, respectively. For the year ended December 31, 2025, the negative revisions were comprised of 6.1 MMBoe due to the impact of lower year-end 2025 SEC prices and 10.3 MMBoe due to performance and other economic factors. For the year ended December 31, 2024, the negative revisions were comprised of 1.40 MMBoe due to impact of lower year-end 2024 SEC prices and 9.00 MMBoe due to performance and other economic factors.

For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lack sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics.

A summary of the Company's changes in quantities of proved undeveloped reserves for the years ended December 31, 2025 and 2024 are as follows:

1) Barrels of oil equivalents have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (Boe).

Standardized Measure of Discounted Future Net Cash Flows

The following Standardized Measure of Discounted Future Net Cash Flows ("Standardized Measure") has been developed utilizing FASB ASC Topic 932, Extractive Activities - Oil and Gas ("ASC 932") procedures and is based on oil and natural gas reserves and production volumes estimated by the Company's third-party petroleum engineering company. The Standardized Measure is not intended to present fair market value of the Company's oil and natural gas reserves, or to be used to assess its performance. The following table may not represent realistic assessment as it does not consider, among other things, the recovery of reserves in excess of proved reserves, future changes in prices and costs, an allowance for return on investment, and the risks inherent in reserves estimates.

As of December 31, 2025 and 2024, the prices used in the calculation of the Standardized Measure were the 12-month unweighted arithmetic average for the first day of the month prices, as specified by the SEC. Prices used in the reserve estimates are provided in the Oil and Natural Gas Reserves supplemental disclosure above. Estimates of future income taxes are computed using current statutory income tax rates. The resulting net cash flows are discounted to present value by applying a 10% discount rate.

The Standardized Measure as of December 31, 2025 and 2024 is as follows (in thousands):

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following table is a summary of the changes in the Standardized Measure for the Company's oil and natural gas reserves for the years ended December 31, 2025 and 2024 (in thousands):