MACH NATURAL RESOURCES LP

2. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The consolidated financial statements included herein were prepared from records of the Company in accordance with generally accepted accounting principles in the United States (“US GAAP”) and include accounts of our wholly owned subsidiaries. Intercompany accounts and transactions have been eliminated upon consolidation. In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair statement of the financial information, have been included.

Our financial and operating data for the year ended December 31, 2023 includes BCE-Mach III for the entire period and BCE-Mach LLC and BCE-Mach II LLC from October 25, 2023, the effective date of the acquisition as a result of the Corporate Reorganization.

Use of Estimates

The preparation of the financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the fair value determination of acquired assets and liabilities assumed in business combinations and the fair value estimates of commodity derivatives.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, partners’ capital, results of operations or cash flows.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the financial statements. The Company maintains cash at financial institutions which may at times exceed federally insured amounts. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk in this area.

Accounts Receivable

Accounts receivable primarily consists of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments for production are received within three months after the production date.

Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for credit losses. The Company extends credit to joint interest owners and generally does not require collateral, but typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due.

As of December 31, 2025, the Company had three customers that represented approximately 20.0%,13.5% and 13.2% of our total joint interest receivables. As of December 31, 2024, the Company had one customer that represented approximately 22.6% of our total joint interest receivables.

The Company establishes its allowance for credit losses equal to the estimable portions of accounts receivable for which failure to collect is expected to occur primarily based on a historical loss rate analysis. The Company estimates uncollectible amounts based on a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s expected ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company considers forecasts of future economic conditions in its estimate of expected credit losses and adjusts its allowance for expected credit losses when necessary. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for credit losses. At December 31, 2025 and December 31, 2024, the allowance for credit losses related to joint interest receivables was $9.1 million and $3.9 million, respectively, and the credit losses related to sales of oil and natural gas properties were not material. The increase in the allowance for credit losses was driven primarily by amounts billed to a royalty trust that owns a net profits interest on the properties acquired in the XTO Acquisition, for which collectibility is uncertain. The increase in the allowance for credit losses is presented as Other (expense) income, net in the Company’s consolidated statement of operations.

Derivative Instruments

The Company is required to recognize its derivative instruments on the balance sheet as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments in the statement of operations.

Oil and Natural Gas Operations

The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, costs of both successful and unsuccessful exploration and development activities are capitalized as proved oil and natural gas properties. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities, which are expensed as incurred. Capitalized costs are depreciated using the unit of production method. Under this method, depletion is computed at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by a net equivalent proved reserves at the beginning of the period. The average depletion rate per barrel equivalent unit of production was$7.11, $8.03 and $6.86 for the years ended December 31, 2025, 2024 and 2023, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $268.2 million, $254.7 million and $126.4 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Under the full cost method, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization, may not exceed the full cost “ceiling” at the end of each reporting period. The ceiling is calculated based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10%. The estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and natural gas properties. Estimated future net cash flows are calculated using the preceding 12-months’ average price based on closing prices on the first day of each month. The net book value is compared to the ceiling limitation on a quarterly basis. The excess, if any, of the net book value above the ceiling limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. The ceiling limitation computation is determined without regard to income taxes due to the Internal Revenue Service (“IRS”) recognition of the Company as a flow-through entity. For the year ended December 31, 2025, the Company recorded an impairment as a result of the ceiling test calculation of $90.4 million. No impairments on proved oil and natural gas properties were recorded for the years ended December 31, 2024 and 2023.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. As of December 31, 2025, and December 31, 2024, the Company had no properties excluded from the full cost pool.

Sales of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas, and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center.

Other Property and Equipment, Net

Other property and equipment primarily consists of gathering systems, processing plants, and a salt water disposal system. Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed as incurred. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range fromtwo to 39 years. Depreciation expense for other property and equipment was $12.3 million, $9.0 million and $6.5 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. No impairment was recorded for the years ending December 31, 2025, 2024 and 2023.

Inventories

Inventories are stated at the lower of cost or net realizable value and consist of production and midstream equipment not placed in service as of December 31, 2025, and 2024, and crude oil held in storage. The Company’s production equipment primarily comprises oil and natural gas drilling or repair items such as tubing, casing and pumping units, as well as pipe for midstream operations, and are valued primarily using a weighted average cost method applied to specific classes of inventory items. Crude oil inventories are valued using the first-in, first-out inventory method. The components of inventory consisted of the following as of December 31, 2025 and 2024:

Debt Issuance Costs

The Company capitalized $14.8 million of new debt issuance costs related to the New Credit Agreement (as defined in Note 6) in the first half of 2025. The remaining unamortized debt issuance costs of $0.5 million from the Revolving Credit Agreement were retained and added to the additional amount of debt issuance costs associated with the New Credit Agreement and are being amortized over the New Credit Agreement’s term.

The Company capitalized $3.8 million of new debt issuance costs related to the First Amendment to the New Credit Agreement (as defined in Note 6) on September 12, 2025.

Other assets include capitalized costs related to the New Credit Agreement of $19.1 million, net of accumulated amortization of $3.5 million as of December 31, 2025. As of December 31, 2024, other assets include capitalized costs related to the Revolving Credit Agreement of $2.6 million, net of accumulated amortization of $2.0 million. These costs are being amortized over the terms of the related credit agreements and are reported as interest expense on the Company’s statements of operations.

The Company capitalized $6.5 million of new debt issuance costs related to the aggregate term loan commitments under the First Amendment to the New Credit Agreement (as defined in Note 6) on September 12, 2025.

Debt issuance costs and the discount associated with the Company’s term loan are presented as a reduction of the carrying value of long-term debt on the Company’s balance sheet. As of December 31, 2025, the Company had unamortized debt issuance costs of $5.9 million in relation to the aggregate term loan commitments under the First Amendment to the New Credit Agreement. As of December 31, 2024, the Company had unamortized debt issuance costs and discount of $11.8 million, in relation to the Term Loan Credit Agreement. On February 27, 2025, the Company wrote-off the remaining unamortized balance of the debt issuance costs and discount associated with the Term Loan Credit Agreement. See Note 6 for further discussion.

Income Taxes

The Company is a limited partnership treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of the Company passed through to partners. As such, with the exception of the state of Texas, we are not a taxable entity, we do not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for our operations, except as described below. Net income for financial statement purposes may differ from taxable income reported to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

Limited partnerships are subject to state income taxes in the state of Texas. Due to immateriality, income taxes related to the Texas franchise tax have been included in general and administrative expenses on the statement of operations and no deferred tax amounts were calculated.

The Company disallows the recognition of tax positions not deemed to meet a “more-likely-than not” threshold of being sustained by the applicable tax authority. The Company’s policy is to reflect interest and penalties related to uncertain tax positions in general and administrative expense, when and if they become applicable. The Company did not recognize any potential interest or penalties in its financial statements for the year ended December 31, 2025. The Company’s tax years 2024, 2023 and 2022 remain open for examination by state authorities.

Asset Retirement Obligations

The Company records the fair value of the future legal liability for an asset retirement obligation (“ARO”) in the period in which the liability is incurred (at the time the wells are drilled or acquired), with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the well is sold, at which time the liability is satisfied.

The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future downhole plugging, dismantlement and removal of production equipment and facilities, and the restoration and reclamation of a field’s surface to a condition similar to that existing before oil and natural gas extraction or saltwater disposal began.

In general, the amount of ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an estimated credit adjusted rate. If the estimated ARO changes materially, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. The following is a reconciliation of ARO activity for the years ended December 31, 2025 and 2024 (in thousands):

Revenue Recognition

Sales of oil, natural gas and NGLs are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The Company’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and NGL fluctuates to remain competitive with other available oil, natural gas and NGL supplies. The payment date is usually within 30 to 90 days of the end of the calendar month in which the commodity is delivered.

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production is historically volatile and unpredictable, and the Company expects this volatility to continue in the future. The prices the Company receives for production depend on many factors outside of our control. See Note 7 for the Company’s management of price volatility.

Oil Sales

The Company’s oil sales contracts are structured where it delivers oil to the purchasers at the wellhead, where the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s statement of operations.

Natural Gas and NGL Sales

Under the Company’s natural gas and NGL sales contracts, it first delivers wet natural gas to a midstream processing entity. After processing, the residue gas is transported to the purchaser at the inlet to certain natural gas pipelines, where the purchaser takes control, title and risk of loss of the product. The NGL are delivered to the purchaser at the tailgate of the midstream processing plant, where the purchaser takes control, title and risk of loss of the product. For both natural gas sales and NGL sales, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with gathering and processing fees presented as an expense in its statement of operations.

Midstream Revenue and Product Sales

The Company’s gathering and processing revenue is generated from owned gathering and compression systems and processing plants acquired in the Company’s acquisitions. The Company charges a gathering, compression, processing rate per MMBtu transported through the gathering system and processing plant. The Company also gathers and disposes of salt water from producing wells through an owned pipeline system and disposal wells. The Company charges a fixed rate per barrel of water for gathering and disposal. Fees are recognized as revenue based on measured volume at the specified delivery points when the associated service is performed.

Product sales are generated from the Company’s sale of natural gas, oil and NGL production purchased from third parties and subsequently gathered and processed through the Company’s owned midstream facilities. Product sales include activity from certain third-party percent-of-proceeds contracts where the Company keeps a contractually based percentage of proceeds from the sale of natural gas and NGL production, as payment for processing natural gas from the third parties. The Company retains control of the purchased natural gas and NGLs prior to delivery to the purchaser and satisfies its performance obligations by transferring control of the product at the delivery point and recognizes revenue based on the contract price received from the purchaser. The costs of buying natural gas, oil and NGL production from third-party shippers are included as costs of product sales on the statement of operations.

Transaction Price Allocated to Remaining Performance Obligations

For the Company’s product sales that are short-term in nature with a contract term of one year or less, the Company has utilized the practical expedient that exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Prior-Period Performance Obligations

The Company records revenue in the month production is delivered and control passes to the customer. However, settlement statements and payment may not be received for 30 to 90 days after the date production occurs, and as a result, the Company is required to estimate the amount of production that was delivered and the price that will be received for the sale of the product. The Company records variances between its estimates and actual amounts received in the month payment is received and such variances have historically not been significant.

Concentrations

The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. The following purchasers each accounted for more than 10% of the Company’s revenues for the periods indicated:

• Purchaser did not account for greater than 10% of oil, natural gas, and NGL sales for the year.

The Company’s receivables as of December 31, 2025 and 2024 from oil and gas sales are typically concentrated with the same counterparties noted above. The Company does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Contract Balances

Cash received relating to future performance obligations is deferred and recognized when all revenue recognition criteria are met. Receivables from contracts with customers were $160.2 million, $132.9 million and $78.1 million as of December 31, 2025, 2024 and 2023, respectively, and are included in accounts receivable – oil, gas, and NGL sales in the Company’s consolidated balance sheets. Contract liabilities generated from such deferred revenue are not considered to be material as of December 31, 2025, 2024 and 2023. The Company's product sales and marketing contracts do not give rise to contract assets.

Revenue Disaggregation

The following table displays the revenue disaggregated and reconciles disaggregated revenue to the revenue reported (in thousands):

Earnings per Common Unit

The Company’s basic earnings per unit (“EPU”) is computed based on the weighted average number of common units outstanding for the period. Diluted EPU includes the effect of the Company’s phantom units if the inclusion of these units is dilutive. See Note 13 for additional information on the Company’s EPU.

Supplemental Cash Flow Information

Supplemental disclosures to the statements of cash flows are presented below (in thousands):

Recent Accounting Pronouncements

In November 2024, the FASB issued ASU 2024-03, which requires disclosure of certain costs and expenses on an interim and annual basis in the notes to the financial statements. The guidance is effective for the first annual reporting period beginning after December 15, 2026, and interim reporting periods within annual reporting periods beginning after December 15, 2027. The amendments in this update are to be applied on a prospective basis, with the option for retrospective application. Early adoption is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s disclosures, but does not believe the adoption of the update will impact the Company’s financial position, results of operations or liquidity.

3. Acquisitions and Divestitures

2025 Acquisitions

IKAV Acquisition

On July 9, 2025, the Company entered into a membership interest purchase agreement (the “IKAV Purchase Agreement”) with VEPU Inc. and Simlog Inc. (collectively, the “IKAV Sellers”), pursuant to which the Company would acquire one hundred percent (100%) of the IKAV Sellers’ membership interests in certain rights, titles and interests in oil and gas properties, rights and related assets located in certain designated lands in the San Juan Basin of New Mexico and Colorado. The transaction closed on September 16, 2025 for consideration of approximately $759.6 million comprised of (i) $349.8 million in cash and (ii)30.6 million common units (the “IKAV Unit Consideration”), subject to certain customary purchase price adjustments (the “IKAV Acquisition”). The IKAV Unit Consideration had a value of approximately $409.9 million. The Company plans to finalize all such adjustments and complete the purchase price allocation in 2026 based on the terms of the IKAV Purchase Agreement.

This purchase was accounted for as a business combination, under the acquisition method, as the Company obtained control of a business by obtaining the legal right to use and develop the oil and natural gas properties included in the IKAV Purchase Agreement, as well as additional oil and gas related assets that can be used to enhance the value of the business. The table below reflects the preliminary fair value estimates of the assets acquired and liabilities assumed as of the acquisition date. Any adjustments to preliminary amounts (such as accrued liabilities or other long-term liabilities) or recognition of additional assets acquired or liabilities assumed, may occur as additional information is obtained about facts and circumstances that existed as of the acquisition date during the measurement period, which will not exceed 12 months form the date of the IKAV Acquisition. See Note 8 for additional information regarding fair value measurements. Below is a reconciliation of the assets acquired and liabilities assumed (in thousands):

For the year ending December 31, 2025, the Company has recognized$87.2 million in revenues and earnings of $29.3 million related to the IKAV Acquisition. As of December 31, 2025, the Company has recognized transaction and advisory related expenses of $14.5 million, which are presented in general and administrative expense on the Company’s statement of operations. Additionally, the Company capitalized certain debt issuance costs associated with the Company’s New Credit Agreement in connection with the acquisition as discussed in Note 2.

Sabinal Acquisition

On July 9, 2025, the Company entered into a Purchase and Sale Agreement (the “Sabinal PSA”) with Sabinal Energy Operating, LLC, Sabinal Resources, LLC and Sabinal CBP, LLC, pursuant to which the Company would acquire certain oil and gas assets located in certain designated lands in the Permian Basin. The transaction closed on September 16, 2025 for consideration of approximately $444.4 million comprised of (i) $199.3 million in cash and (ii)19.2 million common units (the “Sabinal Unit Consideration”), subject to certain customary purchase price adjustments (the “Sabinal Acquisition”). On February 7, 2026,0.2 million common units were cancelled from the Sabinal Unit Consideration as part of customary purchase price adjustments related to the final settlement, and the equity consideration had a final value of approximately $253.9 million.

This purchase was accounted for as an asset acquisition as substantially all of the fair value of acquired assets could be allocated to a single identified asset group of proved oil and natural gas properties. The table below reflects the fair value estimates of the assets acquired and liabilities assumed as of the acquisition date. See Note 8 for additional information regarding fair value measurements. Below is a reconciliation of the assets acquired and liabilities assumed (in thousands):

b. Adjustment reflects a cancellation of shares transferred. The initial purchase price allocation considered available data at the time of disclosure.

XTO Acquisition

On March 25, 2025, the Company entered into an Equity Interest Purchase Agreement (“XTO EIPA”), pursuant to which the Company would acquire certain oil and gas assets located in Oklahoma, Kansas and Wyoming, for consideration of $60.0 million in cash, subject to certain customary purchase price adjustments (the “XTO Acquisition”).

The transaction closed on April 30, 2025. This purchase was accounted for as a business combination, under the acquisition method, as the Company obtained control of a business by obtaining the legal right to use and develop the oil and natural gas properties included in the XTO EIPA, as well as additional oil and gas related assets that can be used to enhance the value of the business. The table below reflects the fair value estimates of the assets acquired and liabilities assumed as of the acquisition date. See Note 8 for additional information regarding fair value measurements. Below is a reconciliation of the assets acquired and liabilities assumed (in thousands):

Flycatcher Acquisition

On December 20, 2024, the Company entered into a Purchase and Sale Agreement (the “Flycatcher PSA”) to purchase certain oil and gas assets near our recently acquired oil and gas assets located in the Ardmore Basin of Oklahoma for consideration of $29.8 million in cash, subject to certain customary purchase price adjustments (the “Flycatcher Acquisition”). The Company plans to finalize all such adjustments and complete the purchase price allocation in 2026 based on terms of the Flycatcher PSA. The Company does not expect post-closing adjustments to be material and they would primarily affect the value of proved oil and gas properties.

The transaction closed on January 31, 2025 and the Company borrowed $23.0 million on the Revolving Credit Agreement to fund the Flycatcher Acquisition. This purchase was accounted for as an asset acquisition as substantially all of the fair value of acquired assets could be allocated to a single identified asset group of proved oil and natural gas properties. The table below reflects the preliminary fair value estimates of the assets acquired and liabilities assumed as of the acquisition date. See Note 8 for additional information regarding fair value measurements. Below is a reconciliation of the assets acquired and liabilities assumed (in thousands):

2024 Acquisitions

Ardmore Basin Acquisition

On August 26, 2024, the Company entered into a Consent Agreement with the purchaser under a Purchase and Sale Agreement (the “Ardmore Basin PSA”) to acquire oil and gas properties in the Ardmore Basin of Oklahoma for consideration of approximately $98.0 million in cash, subject to certain customary purchase price adjustments (the “Ardmore Basin Acquisition”).

The transaction closed on October 1, 2024. This purchase was accounted for as an asset acquisition as substantially all of the fair value of acquired assets could be allocated to a single identified asset group of proved oil and natural gas properties. The table below reflects the fair value estimates of the assets acquired and liabilities assumed as of the acquisition date. See Note 8 for additional information regarding fair value measurements. Below is a reconciliation of the assets acquired and liabilities assumed (in thousands):

Western Kansas Acquisition

On August 9, 2024, the Company executed a purchase and sale agreement (the “Western Kansas PSA”) to purchase certain oil and gas properties in Kansas and Oklahoma for consideration of $38.0 million in cash, subject to certain customary purchase price adjustments (the “Western Kansas Acquisition”).

The transaction closed on September 25, 2024. This purchase was accounted for as an asset acquisition as substantially all of the fair value of acquired assets could be allocated to a single identified asset group of proved oil and natural gas properties. The table below reflects the fair value estimates of the assets acquired and liabilities assumed as of the acquisition date. See Note 8 for additional information regarding fair value measurements. Below is a reconciliation of the assets acquired and liabilities assumed (in thousands):

2023 Acquisitions

Paloma Partners IV, LLC

On November 10, 2023, the Company entered into a purchase and sale agreement (the “Paloma PSA”) with Paloma Partners IV, LLC pursuant to which the Company agreed to purchase certain interests in oil and gas properties, rights and related assets located in Blaine, Caddo, Canadian, Custer, Dewey, Grady, Kingfisher and McClain Counties, Oklahoma (the “Paloma Assets”).

On December 28, 2023, the Company completed the acquisition of the Paloma Assets (the “Paloma Acquisition”) in accordance with the terms of the Paloma PSA for a purchase price of approximately $815,000,000 in cash. The Company utilized borrowings under the Term Loan Credit Agreement to fund the Paloma Acquisition.

The Paloma Acquisition was accounted for as an asset acquisition as substantially all of the gross fair value of the Paloma Assets was concentrated in proved oil and natural gas properties, which were considered to be a group of similar identifiable assets. The table below reflects the fair value of the assets acquired and liabilities assumed as of the acquisition date. See Note 8 for additional information regarding fair value measurements. Below is a reconciliation of assets acquired and liabilities assumed (in thousands):

BCE-Mach LLC and BCE-Mach II LLC

On October 25, 2023, as part of the Corporate Reorganization, the Existing Owners contributed all of their equity interests in BCE-Mach, BCE-Mach II and the Predecessor to the Company in exchange for 100% of the limited partnership interests in the Company to effectuate the acquisition. While there was a high degree of common ownership, the Mach Companies were not under common control for financial reporting purposes. The Predecessor was identified as the accounting acquirer of BCE-Mach and BCE-Mach II which have been accounted for as business combinations under the acquisition method of accounting under U.S. GAAP.

The following table presents the fair value of consideration transferred by the Company for each of the acquisitions (amounts in thousands, except unit and per unit amounts):

The tables below reflect the fair value estimates of the assets acquired and liabilities assumed as of the acquisition date. See Note 8 for additional information regarding fair value measurements. Below is a reconciliation of assets acquired and liabilities assumed (in thousands):

Proved properties were valued using an income approach based on underlying reserves projections as of the acquisition date. The income approach is considered a Level 3 fair value estimate and includes significant assumptions of future production, commodity prices, operating and capital cost estimates, the weighted average cost of capital for industry peers, which represents the discount factor and risk adjustment factors based on reserve category. Price assumptions were based on observable market pricing, adjusted for historical differentials, while cost estimates were based on current observable costs inflated based on historical and expected future inflation.

The results of operations attributable to the BCE-Mach acquisition from the acquisition date through December 31, 2023 have been included in the consolidated statement of operations for the year ended December 31, 2023, and include $26.3 million of total revenue and $6.8 million of net income. The results of operations attributable to the BCE-Mach II acquisition from the acquisition date through December 31, 2023 have been included in the consolidated statement of operations for the year ended December 31, 2023, and include $5.1 million of total revenue and $22 thousand of net income.

Hinkle Oil and Gas, Inc.

On June 28, 2023 the Company executed a purchase and sale agreement with Hinkle Oil and Gas, Inc. for the sale of certain oil and gas properties in Oklahoma for $20.0 million, subject to certain customary adjustments. The transaction closed on August 11, 2023. This purchase was accounted for as an asset acquisition as substantially all of the fair value of acquired assets could be allocated to a single identified asset group of proved oil and natural gas properties.

Business Combination Pro Forma Disclosures

The following table summarizes the unaudited pro forma consolidated financial information of the Company for the years ended December 31, 2025, 2024 and 2023 as if the IKAV Acquisition had occurred on January 1, 2024 and the acquisitions of BCE-Mach and BCE-Mach II had occurred on January 1, 2022 (in thousands):

The unaudited pro forma financial information is not necessarily indicative of the operating results that would have occurred had the business combinations been completed on the dates indicated and is not necessarily indicative of future results of operations of the combined company. The unaudited pro forma financial information for the years ended December 31, 2025, 2024 and 2023 is a result of combining the statements of operations of the Company with the pre-acquisition results of the acquired operations, with pro forma adjustments for revenues and expenses. The unaudited pro forma financial information excludes any anticipated cost savings as a result of the acquisitions.

Divestitures

On June 26, 2024, the Company executed a purchase and sale agreement to sell certain acreage not attributable to the Company’s proved developed reserves. The proceeds from the sale were approximately $38.0 million, and were applied as a credit against the full cost pool with no gain or loss recognized.

4. Property and Equipment

The Company’s property and equipment consists of the following (in thousands):

5. Accrued Liabilities

Accrued liabilities consist of the following (in thousands):

6. Long-Term Debt

New Credit Agreement

On February 27, 2025, the Company entered into the New Credit Agreement, among the Company, the lenders and issuing banks party thereto from time to time and Truist Bank, as the administrative agent and collateral agent. The New Credit Agreement is secured by substantially all of our assets.

The New Credit Agreement has (i) an initial borrowing base and elected commitment amount of $750.0 million, with a maximum commitment amount of $2.0 billion subject to borrowing base availability, (ii) a maturity date of February 27, 2029 and (iii) an interest rate equal to, at the Company’s election, (a) term SOFR (subject to a 0.10% per annum adjustment) plus a margin ranging from 3.00-4.00% per annum or (b) a base rate plus a margin ranging from 2.00-3.00% per annum, with the margin dependent upon borrowing base utilization at the time of determination. The Company is also required to pay a commitment fee of 0.50% per annum on the daily unused portion of the current aggregate commitments under the New Credit Agreement.

The New Credit Agreement’s borrowing base is redetermined semi-annually, in April and October. The New Credit Agreement requires the Company to maintain as of the last day of each fiscal quarter (i) a consolidated total net leverage ratio of less than or equal to 3.00 to 1.00 and (ii) a current ratio of no less than 1.00 to 1.00.

The Company used borrowings from the New Credit Agreement, together with cash on hand and proceeds from the February 2025 Offering, to repay the Term Loan Credit Agreement and the Revolving Credit Agreement in full.

On September 12, 2025, the Company entered into the First Amendment. The First Amendment, among other things, (a) removes the 0.10% per annum credit spread adjustment otherwise applicable to the determination of Term SOFR (as defined in the New Credit Agreement), (b) excludes up to $750.0 million in principal amount of Borrowing Base Reduction Debt (as defined in the New Credit Agreement) issued prior to December 31, 2025 from the provisions otherwise requiring a borrowing base reduction as a result of the issuance of such indebtedness and (c) provides for (i) a $700.0 million aggregate increase in the borrowing base under the Credit Agreement and (ii) the establishment of aggregate term loan commitments (prior to giving effect to any prior funding of term loans) in an amount of $450.0 million and the funding of any unfunded term loan commitments thereunder and increase the Aggregate Elected Revolving Commitment Amount (as defined in the Credit Agreement) to $1.0 billion.

The Company used increased borrowings from the amended Credit Agreement, together with the IKAV Unit Consideration and the Sabinal Unit Consideration, to fund the IKAV Acquisition and the Sabinal Acquisition.

As of December 31, 2025, there were $1.15 billion of outstanding borrowings under the New Credit Agreement with $5.0 million in outstanding letters of credit, and the remaining availability under the New Credit Agreement was $295.0 million. The effective interest rate as of December 31, 2025 was 7.7%.

Prior Credit Facilities

Term Loan Credit Agreement and Revolving Credit Agreement

On December 28, 2023, the Company entered into (i) a senior secured term loan credit agreement (the “Term Loan Credit Agreement”) with the lenders party thereto, Texas Capital Bank, as agent, and Chambers Energy Management, LP, as arranger, and (ii) a senior secured revolving credit agreement (the “Revolving Credit Agreement,” and together with the Term Loan Credit Agreement, the “Credit Agreements”) with a syndicate of lenders, including MidFirst Bank as the administrative agent.

Loans advanced to the Company under the Term Loan Credit Agreement were secured by a first-priority security interest on substantially all of our assets. The Term Loan Credit Agreement had (i) an aggregate principal amount of $825.0 million, (ii) a maturity date of December 31, 2026 and (iii) an interest rate equal to the three-month SOFR plus 6.50% plus a credit spread adjustment equal to 0.15%, provided that the three-month SOFR will not be less than 3.00%. As of December 31, 2024, there were $763.1 million of outstanding borrowings under the Term Loan Credit Agreement. The effective interest rate as of December 31, 2024 was 12.3%.

On February 27, 2025, the Company used borrowings from the New Credit Agreement, together with cash on hand and proceeds from the February 2025 Offering, to repay the existing amounts outstanding under, and terminate, the Term Loan Credit Agreement. The termination of the Term Loan Credit Agreement was treated as a debt extinguishment. Accordingly, the Company recorded $18.5 million in debt extinguishment costs, which included $10.8 million related to the write-off of all unamortized discount and debt issuance costs and $7.7 million related to prepayment penalties.

Loans advanced to the Company under the Revolving Credit Agreement were secured by a super-priority security interest on substantially all of our assets. The Revolving Credit Agreement had (i) a maximum available principal amount of $75.0 million, with maximum commitments currently equal to $75.0 million, (ii) a maturity date of December 28, 2026 and (iii) an interest rate equal to the one, three, or six month SOFR, at the Company’s election, plus a credit spread adjustment equal to 0.10%,0.15%, or 0.25%, respectively, in each case, plus 3.00%, provided that the applicable tenor SOFR will not be less than 3.50%. The Revolving Credit Agreement included customary covenants, mandatory repayments and events of default of financings of this type. The Company was also required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Revolving Credit Agreement. As of December 31, 2024, the Revolving Credit Agreement was undrawn, and there was $5.0 million in outstanding letters of credit, which reduce the amount available to borrow under the Revolving Credit Agreement.

On January 31, 2025, the Company borrowed $23.0 million under the Revolving Credit Agreement to fund the Flycatcher Acquisition.

On February 27, 2025, the Company used borrowings under the New Credit Agreement to repay the existing amounts outstanding under and terminate the existing Revolving Credit Agreement. The termination of the Revolving Credit Agreement was treated as a debt modification based on the composition of the bank syndication in the New Credit Agreement and the change in borrowing capacity.

We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in consolidated debt or losses.

BCE-Mach III Credit Facility

On May 19, 2020, the Predecessor entered into a credit agreement for a revolving credit facility (the “BCE-Mach III Credit Facility”) with a syndicate of banks, including MidFirst Bank (“MidFirst”), who served as administrative agent and issuing bank. The BCE-Mach III Credit Facility provided for a maximum of $300.0 million, subject to commitments of $100.0 million and was scheduled to mature in May 2026. Outstanding obligations under the BCE-Mach III Credit Facility were secured by substantially all of the Predecessor’s assets. The amount available to be borrowed under the BCE-Mach III Credit Facility was subject to a borrowing base that was redetermined semiannually each May and November in an amount determined by the lenders.

The credit agreement contained various affirmative, negative and financial maintenance covenants. These covenants, among other things, limited additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios. The BCE-Mach III Credit Facility required mandatory payments when the consolidated cash balance of the Predecessor exceeded $20.0 million.

At the Predecessor’s election, outstanding borrowings under the credit agreement bore interest at a per annum rate elected by the Predecessor that was equal to an alternative base rate (which was equal to the greatest of the most recent prime rate, the Federal Funds effective rate plus 0.5%, and 1-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranged from 2.0% to 3.0% in the case of the alternate base rate and from 3.25% to 4.25% in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding. The Predecessor was obligated to pay a quarterly commitment fee of 0.50% per year on the unused portion of the commitment, which fee was also dependent on the amount of loans and letters of credit outstanding. The effective interest rate as of December 31, 2023 was 7.7%.

On November 10, 2023, there was $91.9 million outstanding under the BCE-Mach III Credit Facility, which was repaid and terminated when the Company entered into the November 2023 Credit Facility. The termination of the BCE-Mach III Credit Facility was treated as a debt modification, due to the makeup of banks in each credit facility syndicate. The Company wrote off the issuance costs associated with banks exiting the credit facility, and evaluated the change in borrowing capacity with remaining syndicate members and determined no additional issuance cost write offs were necessary. Total write offs of issuance costs were $14.0 thousand, and were included in the Company’s interest expense on the statement of operations.

BCE-Mach Credit Facility

On October 25, 2023, the Company assumed the revolving credit facility (the “BCE-Mach Credit Facility”) between BCE-Mach and a syndicate of banks, including MidFirst Bank who served as sole book runner and lead arranger. Outstanding obligations under the BCE-Mach Credit Facility were secured by substantially all of BCE-Mach’s assets. The credit agreement provided for a revolving credit facility in a maximum outstanding amount of $200.0 million, subject to commitments of $100.0 million. As of October 25, 2023, $65.0 million was outstanding under the BCE-Mach Credit Facility along with $5.0 million in outstanding letters of credit, which reduced the availability under the credit facility on a dollar-for-dollar basis. On November 10, 2023, the Company repaid all amounts outstanding under the BCE-Mach Credit Facility and entered into the November 2023 Credit Facility and terminated the BCE-Mach Credit Facility.

BCE-Mach II Credit Facility

On October 25, 2023, the Company assumed the revolving credit facility (the “BCE-Mach II Credit Facility”) between BCE-Mach II and a syndicate of banks, including East West Bank, who served as sole book runner and lead arranger. Outstanding obligations under the BCE-Mach II Credit Facility were secured by substantially all of BCE-Mach II’s assets. The credit agreement provided for a revolving credit facility in a maximum outstanding amount of $250.0 million, subject to a borrowing base of $26.0 million. As of October 25, 2023, $17.1 million was outstanding under the BCE-Mach II Credit Facility. On October 31, 2023, the Company repaid all amounts outstanding under the BCE-Mach II Credit Facility. On November 10, 2023, the Company entered into the November 2023 Credit Facility and terminated the BCE-Mach II Credit Facility.

November 2023 Credit Facility

On November 10, 2023, Holdco, a subsidiary of the Company, entered into the November 2023 Credit Facility with a syndicate of banks, including MidFirst Bank who served as sole book runner and lead arranger. Outstanding obligations under the November 2023 Credit Facility were secured by substantially all of Holdco’s assets, comprising the assets of the Mach Companies. In connection with entering into the November 2023 Credit Facility, each of the Pre-IPO Credit Facilities were terminated.

The aggregate principal amount of loans outstanding under the November 2023 Credit Facility as of November 10, 2023 was $125.0 million, in addition to $5.0 million of issued letters of credit. The November 2023 Credit Facility provided for a revolving credit facility in an aggregate maximum amount of $1.0 billion, with an initial borrowing base of $600.0 million, subject to commitments of $200.0 million. On December 28, 2023, the Company entered into the Credit Agreements and terminated the November 2023 Credit Facility. The termination of the November 2023 Credit Facility was treated as a debt modification, due to the makeup of banks in each credit facility syndicate. The Company wrote off the issuance costs associated with banks exiting the credit facility, and evaluated the decrease in borrowing capacity with remaining syndicate members to write off the proportional amount of issuance costs in comparison to the reduction in borrowing capacity. Total write offs of issuance costs were $1.5 million, and were included in the Company’s interest expense on the statement of operations.

7. Derivative Contracts

The Company uses derivative contracts to reduce exposure to fluctuations in commodity prices. These transactions are in the form of fixed price swaps, basis swaps and costless collars. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. The Company does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.

The Company reports the fair value of derivatives on the balance sheet in derivative contracts assets and derivative contracts liabilities as either current or noncurrent based on the timing of expected future cash flows of individual trades. See Note 8 for additional information regarding fair value measurements.

Under fixed price swap contracts, the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. Crude oil derivative contracts are indexed and settled based on NYMEX WTI pricing. Natural gas derivative contracts are indexed and settled based on NYMEX Henry Hub (“NYMEX HH”) pricing and EP San Juan (“EP SJ”).

The following table summarizes the open fixed price swap positions as of December 31, 2025, related to oil production:

The following table summarizes the open fixed price swap positions as of December 31, 2025, related to natural gas production:

Each two-way costless collar has a set floor and ceiling price for the hedged production. They are settled monthly based on differences between the floor and ceiling prices specified in the contract and the referenced settlement price. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the collar contracts, the Company will cash-settle the difference with the hedge counterparty. When the referenced settlement price is less than the floor price in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the hedged contract volume. Similarly, when the referenced settlement price exceeds the ceiling price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the hedged contract volume. No payment is due from either party if the referenced settlement price is within the range set by the floor and ceiling prices. Crude oil derivative contracts are indexed and settled based on NYMEX WTI pricing.

The following table summarizes the open costless collar positions as of December 31, 2025, related to oil production:

In addition, the Company has entered into oil basis swap positions. These instruments are arrangements that guarantee a fixed price differential to Argus WTI Midland TMA from a specified delivery point. The Company receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity.

The following table summarizes the open basis swap positions as of December 31, 2025, related to oil production:

Balance Sheet Presentation. The Company has master netting agreements with all of its derivative counterparties and presents its derivative assets and liabilities with the same counterparty on a net basis on the balance sheet. The following tables presents the gross amounts of recognized derivative assets, the amounts that are subject to offsetting under master netting arrangements and the net recorded fair values as recognized on the balance sheet (in thousands):

The following tables presents the gross amounts of recognized derivative liabilities, the amounts that are subject to offsetting under master netting arrangements and the net recorded fair values as recognized on the balance sheet (in thousands):

Gains and Losses. The following table presents the settlement and mark-to-market (“MTM”) gains and losses on oil and natural gas derivatives presented as a gain or loss on derivatives in the statement of operations for the years ended December 31, 2025, 2024 and 2023 (in thousands):

8. Fair Value Measurements

Fair value measurement is established by a hierarchy of inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1 — Quoted prices are available in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 2 — Quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets.

Level 3 — Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.

Assets and liabilities that are measured at fair value are classified 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 to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Fair Value on a Recurring Basis

Derivative Contracts. The Company determines the fair value of its derivative contracts using industry standard models that consider various assumptions including current market and contractual prices for the underlying instruments, time value, and nonperformance risk. Substantially all of these inputs are observable in the marketplace throughout the full term of the contract and can be supported by observable data.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2025 and 2024 (in thousands):

Fair Value on a Non-Recurring Basis

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted with proved oil and natural gas properties using the unit of production method.

Business combinations

Proved properties acquired as a result of business combinations were valued using an income approach based on underlying reserves projections as of the acquisition date. The income approach is considered a Level 3 fair value estimate and includes significant assumptions of future production, commodity prices, operating and capital cost estimates, the weighted average cost of capital for industry peers, which represents the discount factor, and risk adjustment factors based on reserve category. Price assumptions were based on observable market pricing, adjusted for historical differentials, while cost estimates were based on current observable costs inflated based on historical and expected future inflation.

Fair Value of Other Financial Instruments

The carrying amounts of the Company’s cash and cash equivalents, accounts receivable, accounts payable, revenue payable, accrued interest payable, and other current liabilities approximate fair value due to the short-term maturities of these instruments.

The carrying amount of the Company’s Credit Agreements approximate fair value, as the current borrowing base rate does not materially differ from market rates of similar borrowings.

9. Equity Compensation Plans

Equity-based compensation includes unit-based payment awards that are issued to employees and non-employees in exchange for services provided to the Company. Equity-classified unit-based payment awards are recognized at fair value on the grant date and amortized over the requisite service period. For awards with service-based vesting conditions only, the Company recognizes compensation cost using straight-line attribution. The Company uses accelerated attribution for awards that contain market or performance-based vesting conditions. The Company recognizes forfeitures as they occur. Equity-based compensation is presented within general and administrative expense on our consolidated statements of operations.

Post-Offering Grants

On October 27, 2023, the Company adopted a new long-term incentive plan (the “Long-Term Incentive Plan”) for employees, consultants and directors in connection with the Offering. The Company issues phantom units (“Time-Based

Phantom Units”) to certain employees of Mach Resources LLC (“Mach Resources”) and directors of the Company as compensation for services rendered to the Company. The Time-Based Phantom Unit awards for all employees of Mach Resources vest ratably on the first three anniversaries of the date of the grant, subject to the employee’s continued employment. Within 60 days of the vesting of a Time-Based Phantom Unit, the employee will receive a common unit of the Company. Each Time-Based Phantom Unit was granted with a corresponding distribution equivalent right (“DER”), which entitles the employee to receive a payment equal to the total distributions paid by the Company in respect of a common unit of the Company during the time the applicable phantom unit is outstanding. Payment of a DER occurs when its corresponding phantom unit vests, and in the event such phantom unit is forfeited, the corresponding DER is also forfeited.

Total non-cash compensation cost related to the Time-Based Phantom Units was $8.5 million and $6.1 million for the years ended December 31, 2025 and December 31, 2024, respectively. As of December 31, 2025, there was $22.5 million of unrecognized compensation cost related to phantom units that is expected to be recognized over a weighted average period of approximately 2.26 years.

The aggregate fair value of share based awards that vested during the year ended December 31, 2025 was approximately $5.3 million based on the unit price at the time of vesting.

The Company has awarded performance based phantom units (“Performance Phantom Units”) to certain of its executive officers under the Long-Term Incentive Plan. The number of common units issued pursuant to each Performance Phantom Unit award agreement will be from 0% to 200% of the target number of Performance Phantom Units thereunder based on a combination of the Company’s (i) total shareholder return (“TSR”), (ii) relative TSR compared to the TSR of the companies in the Company’s designated peer group and (iii) total recordable incident rate, in each case, for the applicable performance period. The Performance Phantom Unit awards are broken intotwo categories: long-term performance units, which have athree-year performance period, and short-term performance units, which are broken into three separateone-year tranches with performance periods in eachone-year period. Performance Phantom Units vest based on the achievement of the applicable performance metrics at the end of the applicable performance period, subject generally to the applicable executive officer’s continued employment through such performance period. Within 60 days of the vesting of a Performance Phantom Unit, the executive officer will receive a common unit of the Company. Each Performance Phantom Unit was granted with a corresponding DER. Payment of any such DER occurs when its corresponding Performance Phantom Unit vests, and in the event such Performance Phantom Unit is forfeited, the corresponding DER is also forfeited. The grant date fair values of the Performance Phantom Units with market conditions were determined using the Monte Carlo simulation method and are being recorded ratably from the grant date to the end of the applicable performance period.

The table below summarizes the assumptions used in the Monte Carlo simulation to determine the grant date fair value of Performance Phantom Units granted during the years ended December 31, 2025 and 2024:

Total non-cash compensation cost related to the Performance Phantom Units was $0.9 million and $0.4 million for the years ended December 31, 2025 and December 31, 2024, respectively. As of December 31, 2025, there was $1.0 million of unrecognized compensation cost related to phantom units that is expected to be recognized over a weighted average period of approximately 1.64 years. The Long-Term Incentive Plan initially authorized the Company to issue 9.5 million units, and the total amount authorized increases by 5% of the outstanding units at the end of each year.

Predecessor Grants

As part of the Predecessor’s amended and restated LLC agreement as of March 25, 2021, incentive units (Class B Units) and Class A-2 Units were issued to certain employees of Mach Resources as compensation for services to be rendered to the Predecessor. In determining the appropriate accounting treatment, the Predecessor considered the characteristics of the awards in terms of treatment as stock-based compensation.

The incentive units were subject to graded vesting over a period of approximately 3 years (subject to accelerated vesting, as defined by the incentive unit agreement) and a holder of incentive units would forfeit unvested incentive units upon ceasing to be an employee of Mach Resources, excluding limited exceptions. Holders of incentive units were able to participate in distributions upon the Predecessor meeting a certain requisite financial internal rate of return threshold as defined in the Predecessor’s amended LLC agreement.

A summary of the Predecessor’s incentive unit awards as of December 31, 2025 is as follows:

On October 25, 2023, all unvested Class B Units immediately vested and were exchanged for common units in the Company as part of the Corporate Reorganization. Total consideration transferred in the exchange of Class B Units for common units was $302.7 million. All unrecognized compensation costs were expensed upon the vesting of the Class B Units. As of December 31, 2025, there wasno unrecognized compensation cost related to incentive units.

10. Commitments and Contingencies

Legal Matters. In the ordinary course of business, the Company may at times be subject to claims and legal actions including, but not limited to, title disputes, royalty disputes, contract claims, personal injury claims and employment claims. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters. Nevertheless, actual outcomes may differ significantly from the Company’s assessment. The Company recognized $8.2 million of expense pertaining to these matters during the second quarter of 2025 and it is presented in other income (expense), net in the statement of operations for the year ended December 31, 2025. As of December 31, 2025 the Company hasno amounts accrued pertaining to these matters. As of December 31, 2024, the Company had accrued approximately $1.5 million in accrued liabilities pertaining to these matters. Management does not expect that the impact of such matters will have a materially adverse effect on the Company’s financial position, results of operations or cash flows.

Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.

The Company accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.

NGL Sales and Gas Transportation Commitments. The Company is party to a NGL sales contract, which includes certain NGL volume commitments in the event the Company elects not to reduce its committed quantity, at its option. To the extent the Company does not deliver NGL volumes in sufficient quantities to meet the commitment and does not elect to reduce its committed quantity, it would be required to pay a deficiency fee. The Company is currently delivering at least the minimum volumes. For the years ended December 31, 2025, 2024 and 2023, the Company incurred approximately $0.4 million, $3.4 million and $1.0 million, respectively, of transportation charges under these agreements. As of December 31, 2025, the Company has no material amounts remaining under these agreements.

Future Firm Sales Commitments. As part of the IKAV Acquisition, the Company is now party to a firm sales contract to deliver and sell a certain amount of natural gas at a fixed price of $1.72 per MMbtu through 2030. The Company expects to fulfill its delivery commitments primarily with production from proved developed reserves. The Company’s production has been sufficient to satisfy its delivery commitments during the periods presented, and it expects its future production will continue to be the primary means of fulfilling its future commitments. However, if the Company’s production is not sufficient to satisfy its delivery commitments, it can and may use spot market purchases to satisfy the commitments.

A summary of these volume commitments as of December 31, 2025 is set forth in the table below (in MMbtu):

Contributions to 401(k) Plan. The Company sponsors a 401(k) plan under which eligible employees may contribute a portion of their total compensation up to the maximum pre-tax threshold through salary deferrals. The plan provides a company match on 100% of salary deferrals that do not exceed 10% of compensation. The Company contributed $5.0 million, $3.7 million and $1.7 million for the years ended December 31, 2025, 2024 and 2023, respectively.

11. Leases

Nature of Leases

The Company has operating leases on office spaces, various vehicles and compressors with remaining lease durations in excess ofone year. These leases have various expiration dates through 2030. The vehicles are used for field operations and leased from third parties. The Company recognizes right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year. Short-term leases that have an initial term of one year or less are not capitalized.

Discount Rate

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 the commencement date in determining the present value of lease payments. The Company’s incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow an amount equal to the lease payments on a collateralized basis over a similar term and in a similar economic environment.

Future amounts due under operating lease liabilities as of December 31, 2025, were as follows (in thousands):

The following table summarizes our total lease costs before amounts are recovered from our joint interest partners, where applicable, for the years ended December 31, 2025, 2024 and 2023 (in thousands):

The Company does not have any material leases that are short term. The weighted-average remaining lease term as of December 31, 2025 was 3.16 years. The weighted-average discount rate used to determine the operating lease liability as of December 31, 2025 was 7.82%.

12. Partners’ Capital and Members’ Equity

Partners’ Capital

The Company was formed to effectuate the Corporate Reorganization, the Offering and related transactions thereto, as described in Note 1. Nature of Business. On October 25, 2023, the Company issued 88.8 million common units to Existing Owners of the Mach Companies. See Note 3 for additional information on the merger transactions related to the acquisitions of BCE-Mach and BCE-Mach II. On October 27, 2023, the Company completed the Offering and issued 10.0 million common units to public unitholders. Contemporaneously, the Company used a portion of the proceeds from the Offering to repurchase 3.8 million common units from certain Existing Owners of the Mach Companies.

On September 16, 2025, the Company closed the IKAV Acquisition and Sabinal Acquisition, which included the issuance of 30.6 million and 19.2 million common units, respectively, as part of the total consideration for each transaction. As of

September 15, 2025, the IKAV Unit Consideration and the Sabinal Unit Consideration had a value of approximately $409.9 million and $256.9 million, respectively.

On February 7, 2025, the Company completed a public offering of 12.9 million common units at a price to the public of $15.50 per common unit, less underwriting discounts and commissions (the “February 2025 Offering”). On February 12, 2025, the underwriters of the public offering fully exercised their option to purchase an additional 1.9 million common units at a price to the public of $15.50 per common unit, less underwriting discounts and commissions. The sale of the Company’s common units resulted in gross proceeds of $230.0 million and net proceeds of $221.1 million, after deducting underwriting fees and offering expenses. Proceeds from the offering were used to repay a portion of the Term Loan Credit Agreement and Revolving Credit Agreement.

On September 9, 2024, the Company completed a public offering of 7.3 million common units at a price of $16.50 per common unit. On September 24, 2024, the underwriters of the public offering partially exercised their option to purchase an additional 1.0 million common units at a price to the public of $16.50 per common unit, less underwriting discounts and commissions. The sale of the Company’s common units resulted in gross proceeds of $136.8 million and net proceeds of $128.9 million, after deducting underwriting fees and offering expenses. Proceeds from the offering were used to fund the Western Kansas Acquisition and the Ardmore Basin Acquisition.

As of December 31, 2025 and December 31, 2024, the Company had 168.4 million and 103.5 million common units outstanding, respectively. On February 7, 2026,0.2 million common units were cancelled as part of post closing adjustments associated with the Sabinal Acquisition, which reduced total reported units outstanding on the Statement of Partners’ Capital as of December 31, 2025. As of December 31, 2025 there was 49.6 million units outstanding that were issued as part of the IKAV and Sabinal Acquisitions that were restricted by a 180-day lockup period.

For the years ended December 31, 2025 and 2024, the Company distributed $1.94 and $3.20 per unit, respectively, for total cash distributions of $244.5 million and $309.8 million, respectively.

Members’ Equity

Members’ equity of the Predecessor initially consisted of a single class of common interests, that were all owned by BCE-Mach Intermediate Holdings III LLC. On March 25, 2021, per the Predecessor’s amended and restated LLC agreement and the Class A-2 Issuance Agreement, the Predecessor issued 150,000 Class A-1 Units to its initial member, and 1,349 Class A-2 Units to an employee of Mach Resources for services performed for the Predecessor. Additional Class A-2 Units were granted to the employee on a quarterly basis throughout 2021 for a total of 3,504 Class A-2 Units granted, which have substantially all the same rights as the initial member. As part of a long-term incentive plan for certain employees,20,000 Class B Units were issued and outstanding as of December 31, 2023. The Class B Units represented a non-voting interest in the Company that allowed the holder to participate in distributions once the Predecessor’s Class A units met a certain requisite financial internal rate of return in accordance with the Predecessor’s LLC agreement. See Note 9 for additional information on equity grants by the Predecessor. All of the equity interests in the Predecessor were exchanged for common units of the Company as part of the Corporate Reorganization.

Contributions from the Company’s predecessor members were $20.0 million for the year ended December 31, 2023. Distributions to the Company’s predecessor members were $101.4 million for the years ended December 31, 2023.

13. Earnings Per Common Unit

The Company has a single class of common units. The Company has potentially dilutive securities as of December 31, 2025, which consist of phantom units issued under the Company’s long-term incentive plan. The treasury stock method is used to determine the dilutive impact for the Company’s phantom units. As of December 31, 2025, 2024 and 2023, there were 29.8 thousand,10.4 thousand and 0.7 million phantom units, respectively, that were considered antidilutive and thus excluded from the calculation of diluted earnings per common unit.

The following represents the computation of basic and diluted earnings per common unit for the years ended December 31, 2025, 2024 and 2023 (in thousands, except per unit data):

14. Related Party Transactions

Management Services Agreement

On October 27, 2023, in connection with the closing of the Offering, the Company entered into a new management services agreement (the “MSA,” and together with the Predecessor MSA, the “MSAs”) with Mach Resources and terminated the Predecessor MSA. Under the MSAs, Mach Resources manages and performs all aspects of oil and gas operations and other general and administrative functions for the Company and (i) will pay Mach Resources an annual management fee of approximately $7.4 million and (ii) reimburse Mach Resources for the costs and expenses of the services provided. On a monthly basis, the Company distributes funding to Mach Resources for performance under the MSA. During the years ended December 31, 2025, 2024 and 2023, the Company paid Mach Resources $135.7 million (inclusive of $7.4 million in management fees presented as general and administrative expense - related party in the statement of operations), $112.9 million (inclusive of $7.4 million in management fees presented as general and administrative expense - related party in the statement of operations) and $52.3 million (inclusive of $4.8 million in management fees presented as general and administrative expense - related party in the statement of operations), respectively. As of December 31, 2025 and 2024, the Company owed $0.9 million and $2.0 million, respectively, to Mach Resources, presented as accounts payable - related party.

Transition Services Agreements

In connection with the closing of the IKAV and Sabinal Acquisitions, the Company entered into a transition services agreement with each respective counterparty. For the year ended December 31, 2025, the Company paid the IKAV Sellers and the Sabinal Sellers $1.6 million and $4.3 million, respectively for continued assistance in transitioning processes to the Company.

Common units purchased by BCE-Mach Aggregator

In connection with the February 2025 Offering, BCE-Mach Aggregator, an affiliate of our General Partner, purchased 5,161,290 common units at the public offering price, which accounted for $79.2 million of the net proceeds received by the Company in the February 2025 Offering, after deducting underwriting fees. In connection therewith, the underwriters received a reduced underwriting discount on such common units purchased by BCE-Mach Aggregator compared to other common units sold to the public in the February 2025 Offering.

BCE-Mach and BCE-Mach II

BCE-Mach and BCE-Mach II were two related parties that previously entered into a MSA with Mach Resources. These entities had shared ownership, but were not under common control, with the Company prior to the Corporate Reorganization on October 25, 2023. See Note 1 and Note 3 for further discussion of the transactions involving these entities. As of December 31, 2023 and for periods subsequent to the Corporate Reorganization, all account balances and activities between the Company and these entities have been eliminated as intercompany transactions.

15. Segment Information

Management has evaluated that the Company is organized and managed as a single reportable segment, which is the exploration and production of oil, natural gas and NGLs (“E&P Segment”). All of the Company’s operations and assets are located in the United States, and its revenues are attributable to United States customers.

The accounting policies of the E&P Segment are the same as those described in Note 2.

The Company’s chief operating decision maker (“CODM”) is the Chief Executive Officer and Director. The CODM uses consolidated net income as presented on the accompanying statements of operations to measure E&P Segment profit or loss, and to evaluate income generated from E&P Segment assets in deciding whether to reinvest profits into operational activities or to use profits for other purposes, such as debt reduction, acquisitions, or distributions to unitholders. Additionally, consolidated net income is used in assessing budget versus actual results and in benchmarking to the Company’s competitors.

The following table summarizes total revenues, significant expenses, net income, total assets and capital expenditures related to the E&P Segment for time periods presented below (in thousands):

16. Subsequent Events

Distribution Declaration

On February 12, 2026, the Company declared its quarterly distribution for the fourth quarter of 2025 of $0.53 per common unit, which will be paid on March 12, 2026.

The Company has evaluated subsequent events through the date of issuance of these financial statements to ensure that any subsequent events that met the criteria for recognition and disclosure in this Annual Report have been properly included.

17. Supplementary Financial Information for Oil and Gas Producing Activities (Unaudited)

The following tables provide historical cost information regarding the Company’s oil and gas operations located entirely in the United States:

Capitalized Costs related to Oil and Gas Producing Activities

Costs Incurred in Oil and Gas Property Acquisition and Development Activities

Results of Operations for Producing Activities

The following table includes revenue and expenses related to the production and sale of oil, natural gas, and NGLs. It does not include any derivative activity, interest costs or general and administrative costs.

Proved Reserves

Our proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.

Proved reserves. Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data.

Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.

Proved undeveloped reserves or PUDs. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Standardized Measure

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the US GAAP. Such assumptions include the use of 12-month average prices for oil and gas, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% rate. No provision is included for federal income taxes since our future net cash flows are not subject to taxation.

Estimated well abandonment costs, net of salvage values, are deducted from the standardized measure using year-end costs and discounted at the 10% rate. Such abandonment costs are recorded as a liability on the consolidated balance sheet, using estimated values as of the projected abandonment date and discounted using a risk-adjusted rate at the time the well is drilled or acquired. See Note 2 for additional information related to asset retirement obligations.

The standardized measure does not represent management’s estimate of our future cash flows or the fair value of proved oil and natural gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, prices used to determine the standardized measure are influenced by supply and demand as affected by recent economic conditions as well as other factors and may not be the most representative in estimating future revenues or reserve data.

Proved Reserves Summary

All of the Company’s reserves are located in the United States. The following table sets forth the changes in the Company’s net proved reserves (including developed and undeveloped reserves) for the years ended December 31, 2025, 2024 and 2023. Reserves estimates as of December 31, 2025 were estimated by our independent petroleum consulting firms Cawley, Gillespie & Associates, Inc and Netherland, Sewell & Associates, Inc. Reserve estimates as of December 31, 2024 and prior were estimated by Cawley, Gillespie & Associates, Inc.

In 2023, the 194,208 MBoe of acquisitions represents the reserves acquired from several acquisitions that closed in 2023. See Note 3 for more information. The 30,462 MBoe of downward revisions in proved reserves were the result of lower commodity prices (-20,408 MBoe), the addition of PUDs within proven areas of development (23,014 MBoe), the deletion of PUDs due to changes in the corporate development plan (-36,762 MBoe) and the addition of proved developed producing reserves associated with the drilling of wells within proved areas that were not booked as PUD at prior year-end (8,672 MBoe). The remainder was associated with revisions to reflect current lease operating expenses and production pricing differentials.

In 2024, the 13,934 MBoe of acquisitions represents the reserves acquired from several acquisitions that closed in 2024. See Note 3 for more information. The 9,404 MBoe of upward revisions in proved reserves were the result of lower commodity prices (-16,859 MBoe), the addition of PUDs within proven areas of development (25,385 MBoe) and the addition of proved developed producing reserves associated with the drilling of wells within proved areas that were not booked as PUD at prior year-end (1,431 MBoe). The remainder was associated with revisions to reflect current lease operating expenses and production pricing differentials.

In 2025, the 372,979 MBoe of acquisitions represents the reserves acquired from several acquisitions that closed in 2025. See Note 3 for more information. The 32,234 MBoe of upward revisions in proved reserves were the result of higher commodity prices (25,847 MBoe), the addition of PUDs within proven areas of development (21,081 MBoe), the deletion of PUDs due to changes in the corporate development plan (-19,075 MBoe) and the addition of proved developed producing reserves associated with the drilling of wells within proved areas that were not booked as PUD at prior year-end (9,576 MBoe). The Company classifies these changes as revisions of previous estimates due to the Company’s drilling occurring in mature basins with well-established production histories and clearly defined development patterns, which we consider to be proven areas. The Company had no extensions or discoveries in 2025. The remainder was associated with revisions to reflect current lease operating expenses and production pricing differentials.

The following table sets forth the standardized measure of discounted future net cash flow from projected production of the Company’s oil and natural gas reserves:

(1)Production costs include production severance taxes, ad valorem taxes and operating expenses.

(2)Development costs include plugging expenses, net of salvage and net capital investment.

(3)Represents Texas franchise tax.

Price and cost revisions are primarily the net result of changes in prices, based on beginning of the year reserve estimates. Future development costs revisions are primarily the result of the extended economic life of proved reserves and proved undeveloped reserve additions attributable to increased development activity.

Average oil prices used in the estimation of proved reserves and calculation of the standardized measure were $65.34, $75.48 and $78.22 for the years ended December 31, 2025, 2024 and 2023, respectively. Average realized gas prices were $3.39, $2.13 and $2.64 for the years ended December 31, 2025, 2024 and 2023, respectively. We used 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period.