Mach Natural Resources (MNR) 10-Q2024 Q1 Quarterly report

The information in this Quarterly Report on Form 10-Q contains or incorporates by reference information that includes or is based upon “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, words such as “may,” “assume,” “forecast,” “could,” “should,” “will,” “plan,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events at the time such statement was made. When considering forward-looking statements, you should keep in mind the risk factors included in Part I, Item 1A. “Risk Factors” and Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2023 and elsewhere in this Quarterly Report. All forward-looking statements speak only as of the date of this Quarterly Report.

Forward-looking statements may include statements about:

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, our reserve and PV-10 estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties materialize, or should underlying assumptions prove to be incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.

Mach Natural Resources LP (the “Company”) is a Delaware limited partnership that was formed for the purpose of effectuating an initial public offering (the “Offering”) that closed in October 2023. The Company’s common units representing limited partnership interests (the “common units”) are listed on The New York Stock Exchange under the symbol “MNR.” The Company is an independent upstream oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Anadarko Basin region of Western Oklahoma, Southern Kansas and the panhandle of Texas.

Following the Offering and Corporate Reorganization, the Company became a holding partnership whose sole material asset consists of membership interests in Mach Natural Resources Intermediate LLC (“Intermediate”). Intermediate wholly owns Mach Natural Resources Holdco LLC (“Holdco”), and Holdco wholly owns each of the Company’s three operating subsidiaries, BCE-Mach LLC (“BCE-Mach”), BCE-Mach II LLC (“BCE-Mach II”) and BCE-Mach III LLC (collectively, the “Mach Companies”). BCE-Mach III LLC (the “Predecessor”) is the accounting predecessor to the Company for all periods prior to the Offering as discussed herein.

On October 27, 2023, the Company completed the Offering of 10,000,000 common units at a price of $19.00 per unit to the public. The sale of Company’s common units resulted in gross proceeds of $190.0 million to the Company and net proceeds of $168.5 million, after deducting underwriting fees and offering expenses. The material terms of the Offering are described in the Company’s final prospectus, filed with the U.S. Securities and Exchange Commission (“SEC”) on October 26, 2023, pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended (the “Securities Act”).

The Company used $102.2 million of the proceeds to pay down the existing credit facilities of its operating subsidiaries (the “Pre-IPO Credit Facilities”) and $66.3 million of the proceeds to purchase 3,750,000 common units from the existing common unit owners on a pro rata basis. After giving effect to the Offering and the transactions related thereto, the Company had 95,000,000 common units issued and outstanding.

statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2023, as included in the Company’s Annual Report on Form 10-K. Results for interim periods are not necessarily indicative of results to be expected for the full year ending December 31, 2024. 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.

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, if any, 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.

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.

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 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.

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 March 31, 2024 and December 31, 2023, the allowance for credit losses

related to joint interest receivables were $2.2 million and $1.7 million, respectively, and the credit losses related to sales of oil and natural gas were not material.

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. The cash and non-cash change in fair value on derivative instruments are included in the operating activities section in the statement of cash flows.

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. No impairments on proved oil and natural gas properties were recorded for the three months ended March 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. As of March 31, 2024, and December 31, 2023, the Company had no properties excluded from the full cost pool. 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.

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 natural gas liquids (“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 primarily consists of gathering systems, processing plants, and salt water disposal systems. Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed. Depreciation of

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 of other property and equipment was recorded for the three months ended March 31, 2024 or 2023.

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 March 31, 2024 and December 31, 2023. The Company’s production equipment is primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units, as well as pipe for midstream operations.

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 March 31, 2024 and December 31, 2023, the Company had unamortized debt issuance costs and discount of $16.9 million and $18.0 million, respectively, in relation to the term loan.

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.

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 has not recognized any potential interest or penalties in its financial statements for the three months ended March 31, 2024. The Company’s tax years 2023, 2022, and 2021 remain open for examination by state authorities.

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 salt water 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 for the three months ended March 31, 2024 and 2023 (in thousands):

Sales of oil, natural gas and NGL 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 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.

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 is 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.

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 disposal. Fees are recognized as revenue based on measured volume at the specified delivery points

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.

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.

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

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

In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures,” which updates reportable segment disclosure requirements primarily through enhanced disclosures about significant segment expenses and information used to assess segment performance. The amendments are effective for annual periods beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The amendments should be applied retrospectively to all prior periods presented in the financial statements. 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.

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 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 BCE-Mach III 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. BCE-Mach III LLC has been 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.

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.

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

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 Revolving Credit Agreement are secured by a super-priority security interest on substantially all of our assets. The Revolving Credit Agreement has (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 includes customary covenants, mandatory repayments and events of default of financings of this type. The Company is 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. The Company used borrowings from the Term Loan Credit Agreement, together with cash on hand, to repay the November 2023 Credit Facility. As of March 31, 2024 and December 31, 2023, the Revolving Credit Agreement was undrawn, and there was $5.0 million in outstanding letters of credit.

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.

The Company uses derivative contracts to reduce exposure to fluctuations in commodity prices. These transactions are in the form of fixed price swaps. 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.

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.

The following table summarizes the open financial derivative positions as of March 31, 2024, related to oil production:

The following table summarizes the open financial derivative positions as of March 31, 2024, related to natural gas production:

table 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 table 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):

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.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2024 and December 31, 2023 (in thousands):

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.

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.

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.

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.

Total non-cash compensation cost related to the phantom units was $1.2 million for the period ended March 31, 2024. As of March 31, 2024, there was $11.3 million of unrecognized compensation cost related to phantom units that is expected to be recognized over a weighted average period of approximately 2.5 years.

As part of the Predecessor’s amended and restated LLC agreement as of March 25, 2021, incentive units (Class B 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 or 4 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.

Determination of the fair value of the awards requires judgements and estimates regarding, among other things, the appropriate methodologies to follow in valuing the award and the related inputs required by those valuation methodologies. For Predecessor awards granted during the year ended December 31, 2021, the fair value underlying the compensation expense was estimated using the Black-Scholes valuation model with the following primary assumptions:

A summary of the Predecessor’s incentive unit awards as of March 31, 2023 is as follows:

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.

The Company has operating leases on an office space, various vehicles, and compressors with remaining lease durations in excess of one year. These leases have various expiration dates throughout 2026. 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.

As most of the Company’s leases do not provide an implicit rate, the Company uses the U.S. 5 Year Treasury Rate in determining the present value of lease payments. Minor changes to the discount rate do not have a material impact to the calculation of the liability, therefore the Company will use this for all asset classes.

Future amounts due under operating lease liabilities as of March 31, 2024, 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 three months ended March 31, 2024 and 2023 (in thousands):

The weighted-average remaining lease term as of March 31, 2024 was 1.89 years. The weighted-average discount rate used to determine the operating lease liability as of March 31, 2024 was 5.0%.

Cash distributions to the Company’s unitholders were $90.3 million for the three months ended March 31, 2024.

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

Distributions to the Company’s predecessor members were $59.0 million for the three months ended March 31, 2023.

We are an independent upstream oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Anadarko Basin region of Western Oklahoma, Southern Kansas and the panhandle of Texas.

Within our operating areas, our assets are prospective for multiple formations, most notably the Oswego, Woodford, Meramec/Osage and Mississippi Lime formations. Our experience in the Anadarko Basin and these formations allows us to generate significant cash available for distribution from these low declining assets in a variety of commodity price environments. We also own an extensive portfolio of complementary midstream assets that are integrated with our upstream operations. These assets include gathering systems, processing plants and water infrastructure. Our midstream assets enhance the value of our properties by allowing us to optimize pricing, increase flow assurance and eliminate third-party costs and inefficiencies. In addition, our owned midstream systems generate third-party revenue.

Our financial results depend on many factors, particularly commodity prices and our ability to find, develop and market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand. The oil and natural gas industry is cyclical and commodity prices are highly volatile and we expect continued and increased pricing volatility in the crude oil and natural gas markets. Regional and worldwide economic activity, including any economic downturn or recession that has occurred or may occur in the future, extreme weather conditions and other substantially variable factors, influence market conditions for these products. Between January 1, 2023 and March 31, 2024, NYMEX WTI prices for crude oil ranged from $66.74 to $93.68 per Bbl, and the NYMEX Henry Hub price of natural gas ranged from $1.58 to $4.17 per MMBtu. The war in Ukraine, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession, and instability in the financial sector have contributed to recent economic and pricing volatility and may continue to impact pricing throughout 2024.

efforts may not succeed or may be insufficient. Further, if we are unable to recover higher costs through higher commodity prices, our current revenue stream, estimates of future reserves, borrowing base calculations, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions would all be significantly impacted.

We use a variety of financial and operational metrics to assess the performance of our operations, including the following sources of our revenue, principal components of our cost structure and other financial metrics:

Our future results of operations may not be comparable to our historical results of operations for the periods presented, primarily for the reasons described below.

We completed an acquisition on December 28, 2023 for approximately $815 million, subject to customary post-closing adjustments. This acquisition is reflected in our results of operations as of and after the date of completion of such acquisition. As a result, periods prior to such acquisition will not contain the results of such acquired assets which will affect the comparability of our results of operations for certain historical periods.

The historical consolidated financial statements included in this Quarterly Report are of our Predecessor for periods prior to the Corporate Reorganization, and of the Company for periods after the Corporate Reorganization. Our historical financial data presented herein does not present what our actual performance results would have been on a combined basis for the full fiscal period presented.

Upon the completion of our initial public offering, we incurred and expect to continue to incur incremental non-recurring costs related to our transition to a publicly traded partnership, including the costs of our initial public offering and the costs associated with the initial implementation of our internal control implementation and testing. We also expect to incur additional significant and recurring expenses as a publicly traded partnership, including costs associated with the employment of additional personnel, compliance under the Exchange Act, annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation.

The following table provides the components of our revenue, net of transportation and marketing costs for the periods indicated, as well as each period’s respective average realized prices and net production volumes. Some totals and changes throughout the below section may not sum or recalculate due to rounding.

For the three-month period ended March 31, 2024, we had realized gains on derivative instruments of $3.9 million and unrealized losses of $33.2 million for total losses of $29.3 million. For the three-month period ended March 31, 2023, we had realized gains on derivative instruments of $2.8 million and unrealized gains of $10.3 million for total gains of $13.1 million. The increase in realized gains is primarily from the decrease in natural gas prices in the three-month period ended March 31, 2024, as compared to the three-month period ended March 31, 2023.

Product sales decreased $3.2 million, or 31% for the three-month period ended March 31, 2024, as compared to the three-month period ended March 31, 2023. This decrease was primarily a result of decreases in non-operated production resulting in lower overall product sales and the decrease in the average selling price on natural gas and NGLs. These decreases corresponded with the decrease in our cost of product sales noted below.

The following table summarizes our expenses for the periods indicated and includes a presentation of certain expenses on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:

Our primary sources of liquidity and capital are cash flows generated by operating activities, borrowings under the Credit Agreements, and proceeds from the issuance of equity and debt. Outstanding borrowings under our Credit Agreements were $825.0 million at March 31, 2024, and the remaining availability under our Credit Agreements was $70.0 million at March 31, 2024.

We may need to utilize the public equity or debt markets and bank financings to fund future acquisitions or capital expenditures, but the price at which our common units will trade could be diminished as a result of the limited voting rights of unitholders. We expect to be able to issue additional equity and debt securities from time to time as market conditions allow to facilitate future acquisitions. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations or to refinance our indebtedness will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, particularly for oil and natural gas, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory, weather and other factors.

Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner, which we refer to as “available cash.” Our quarterly cash distributions may vary from quarter to quarter as a direct result of variations in the performance of our business, including those caused by fluctuations in commodity prices. Any such variations may be significant, and as a result, we may pay limited or even no cash distributions to our unitholders.

Historically, our business plan has focused on acquiring and then exploiting the development and production of our assets. We spent approximately $80.4 million during the three-month period ended March 31, 2024 on development costs and our budget for 2024 is between $250.0 million and $275.0 million. For purposes of calculating our cash available for distribution, we define development costs as all of our capital expenditures, other than acquisitions. Our development efforts and capital for 2024 is anticipated to focus on drilling Oswego wells given their high oil reserves and low breakeven costs.

During the three-month period ended March 31, 2024, we spent approximately $64.0 million on drilling and completion activities and related equipment and spud 20.5 net wells while bringing online 20.4 net wells, $12.1 million on remedial workovers and other capital projects, and $4.3 million on midstream and other property and equipment capital projects.

Our 2024 capital expenditures program is largely discretionary and within our control. We could choose to defer a portion of these planned 2024 capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, including acid to be used for our acid stimulation completion, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows and reduce our cash available for distribution to unitholders.

Net cash provided by operating activities decreased $3.2 million for the three-month period ended March 31, 2024, as compared to the three-month period ended March 31, 2023. The decrease in net cash provided by operating activities is primarily a result of decreases in working capital of $38.1 million, offset with an increase in income from acquisitions and the Corporate Reorganization in 2023.

Net cash used in investing activities decreased $29.2 million for the three-month period ended March 31, 2024, as compared to the three-month period ended March 31, 2023. The decrease in net cash used in investing activities is primarily a result of decreases in capital expenditures on oil and gas properties of $30.0 million due to decreased drilling and completion activities in the three-month period ended March 31, 2024, as compared to the three-month period ended March 31, 2023.

Net cash used in financing activities increased $31.3 million for the three-month period ended March 31, 2024, as compared to the three-month period ended March 31, 2023. The increase in net cash used in investing activities is primarily due to a $31.3 million increase in distributions paid in the three-month period ended March 31, 2024, as compared to the three-month period ended March 31, 2023.

On December 28, 2023, the Company entered into (i) the Term Loan Credit Agreement with the lenders party thereto, Texas Capital Bank, as agent, and Chambers Energy Management, LP, as the arranger, and (ii) the Revolving Credit Agreement with the lenders party thereto and MidFirst Bank as the agent.

Loans advanced to the Company under the Term Loan Credit Agreement are secured by a first-priority security interest on substantially all of our assets. The Term Loan Credit Agreement has (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%. Mandatory repayments of principal of $61.9 million, $82.5 million, and $680.6 million are due in the year 2024, 2025, and 2026, respectively. The Term Loan Credit Agreement includes customary covenants, mandatory repayments and events of default of financings of this type.

Loans advanced to the Company under the Revolving Credit Agreement are secured by a super-priority security interest on substantially all of our assets. The Revolving Credit Agreement has (i) a maximum available principal amount of $75.0 million, (ii) a maturity date of December 28, 2026 and (iii) an interest rate equal to 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 includes customary covenants, mandatory repayments and events of default of financings of this type. The Company used borrowings from the Term Loan Credit Agreement, together with cash on hand, to repay the November 2023 Credit Facility. As of March 31, 2024, the Revolving Credit Agreement was undrawn, and there was $5.0 million in outstanding letters of credit.

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.

We include in this Quarterly Report the supplemental non-GAAP financial performance measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income, our most directly comparable financial measures calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income before (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized (gain) loss on derivative instruments, (4) equity-based compensation expense, (5) credit losses, and (6) (gain) loss on sale of assets.

Adjusted EBITDA is used as a supplemental financial performance measure by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to more effectively evaluate our operating performance and our results of operation from period to period and against our peers without regard to financing methods, capital structure or historical cost basis. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA is not a measurement of our financial performance under GAAP and should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as indicators of our operating performance. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDA. Our presentation of Adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual items. Our computations of Adjusted EBITDA may not be identical to other similarly titled measures of other companies.

Cash available for distribution is not a measure of net income or net cash flow provided by or used in operating activities as determined by GAAP. Cash available for distribution is a supplemental non-GAAP financial performance measure used by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as net income less (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized (gain) loss on derivative instruments, (4) equity-based compensation expense, (5) credit losses, (6) (gain) loss on sale of assets, (7) settlement of asset retirement obligations, (8) cash interest expense, net (9) development costs, and (10) change in accrued realized derivative settlements. Development costs include all of our capital expenditures, other than acquisitions. Cash available for distribution will not reflect changes in working capital balances. Cash available for distribution is not a measurement of our financial performance or liquidity under GAAP and should not be considered as an alternative to, or more meaningful than, net income or net cash provided by or used in operating activities as determined in accordance with GAAP or as indicators of our financial performance and liquidity. The GAAP measures most directly comparable to cash available for distribution are net income and net cash provided by operating activities. Cash available for distribution should not be considered as an alternative to, or more meaningful than, net income or net cash provided by operating activities.

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses.

Our revenue and cash flow from operations are subject to many variables, the most significant of which is the volatility of commodity prices. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by global economic factors, pipeline capacity constraints, inventory levels, basis differentials, weather conditions and other factors. Commodity prices have long been volatile and unpredictable, and we expect this volatility to continue in the future.

There can be no assurance that commodity prices will not be subject to continued wide fluctuations in the future. A substantial or extended decline in such prices could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil and gas reserves that may be economically produced, which could result in impairments of our oil and natural gas properties.

To reduce the impact of fluctuations of commodity prices on our total revenue and other operating income, we have historically used, and we expect to continue to use, commodity derivative instruments, primarily swaps, to hedge price risk associated with a portion of our anticipated production. Our hedging instruments allow us to reduce, but not eliminate the potential effects of the variability in cash flow from operations due to fluctuations in commodity prices and provide increased certainty of cash flows for funding our drilling program and debt service requirements. These instruments provide only partial price protection against declines in prices and may partially limit our potential gains from future increases in prices. We do not enter derivative contracts for speculative trading purposes. The Pre-IPO Credit Facilities contain or contained, and the Credit Agreements contain, various covenants and restrictive provisions which, among other things, limit our ability to enter into commodity price hedges exceeding a certain percentage of production.

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of a contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. As of March 31, 2024, we had derivative instruments in place with three different counterparties. We believe our counterparties currently represent acceptable credit risks. We are not required to provide credit support or collateral to our counterparties under current contracts, nor are they required to provide credit support or collateral to us.

Substantially all of our revenue and receivables result from oil and gas sales to third parties operating in the oil and gas industry. Our receivables also include amounts owed by joint interest owners in the properties we operate. Both our purchasers and joint interest partners have recently experienced the impact of significant commodity price volatility as discussed above under “— Commodity Price Risk — Oil and Gas Revenue.” This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in commodity prices and economic and other conditions. In the case of joint interest owners, we often have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings.

At March 31, 2024, we had $825.0 million of debt outstanding under the Term Loan Credit Agreement. Borrowings outstanding under the Term Loan Credit Agreement bore an effective interest rate of 13.0% as of March 31, 2024.

Assuming no change in the amount outstanding, the impact on interest expense of a 1% (or 100 basis points) increase or decrease in the assumed weighted average interest rate on our variable interest debt would be approximately $8.3 million per year based on our borrowings outstanding at March 31, 2024.

As of March 31, 2024, we did not have any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness, but we may enter into such derivative arrangements in the future. To the extent we enter into any such interest rate derivative arrangement, we would be subject to risk for financial loss.

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2024. Based on such evaluation, such officers have concluded that, as of March 31, 2024, the Company’s disclosure controls and procedures are designed and effective to ensure that information required to be included in the Company’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that information required to be disclosed in the Company’s reports filed or submitted under the Exchange Act is accumulated and communicated to the Company’s management including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

The Company may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business. The Company is not currently a party to any material legal proceedings. In addition, the Company is not aware of any material legal proceedings contemplated to be brought against the Company.

The Company, as an owner and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.

The Company is not aware of any environmental claims existing as of March 31, 2024. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.

There have been no material changes to the Company’s “Risk Factors” previously disclosed in Part I, Item 1A of our Annual Report for the year ended December 31, 2023. For a detailed discussion of the risks that affect our business, please refer to Part I, Item 1A “Risk Factors” in our Annual Report for the year ended December 31, 2023.

None.