PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. Because this is a summary, it may not contain all of the information that may be important to you and to your investment decision. The following summary is qualified in its entirety by the more detailed information and financial statements and notes thereto included elsewhere in this prospectus. You should read the entire prospectus carefully and should consider, among other things, the matters set forth in “Risk Factors,” “Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical and unaudited pro forma consolidated financial statements and the related notes to each of those financial statements included elsewhere in this prospectus before deciding to invest in our common units. Unless otherwise indicated, the financial and operating information as well as the estimated proved and probable reserve information presented in this prospectus gives pro forma effect to the initial public offering and the use of proceeds therefrom and the Reorganization Transactions described herein and presents the data of the Mach Companies on a combined basis.

The information presented in this prospectus assumes (i) an initial public offering price of $            per common unit (the mid-point of the price range set forth on the cover of this prospectus) and (ii) that the underwriters do not exercise their option to purchase up to an additional             common units, unless otherwise indicated. As used in this prospectus, the term “our general partner” refers to Mach Natural Resources GP LLC, a Delaware limited liability company, and the terms “Mach Natural Resources,” “partnership,” the “Company,” “we,” “our,” “us” or similar terms refer to Mach Natural Resources LP, a Delaware limited partnership, and its subsidiaries. We include a glossary of some of the oil and natural gas terms and other terms used in this prospectus in Appendix B. Our estimated proved and probable reserve information included in this prospectus is based on reports prepared by Cawley, Gillespie & Associates, Inc., our independent reserve engineers.

Our Company

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. Our experienced management team, led by industry veteran Tom L. Ward, possesses deep operational and industry experience, particularly in Oklahoma and the Anadarko Basin. We leverage our extensive experience to identify the most attractive exploitation and development opportunities and optimize the production of current wells, efficiently drill our existing inventory of undeveloped locations and identify attractive low-risk acquisition opportunities.

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.” We believe the lower decline nature of our Legacy Producing Assets (as defined below) and large inventory of horizontal drilling locations with average royalty burdens of less than 25%, coupled with our lower cash operating costs and owned midstream infrastructure, will support our ability to make cash distributions to our unitholders. We expect to maintain a conservative capital structure with the long-term goal of remaining substantially debt free. Nevertheless, 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.

We seek to maximize cash distributions to unitholders through a combination of the development of our existing properties, primarily using our cash flow from operating activities, and the acquisition of producing properties. Our current acreage position in the Anadarko Basin is characterized as oil-rich with considerable natural gas content, notable historical production, low decline rates and average royalty burdens of less than 25%. Through a series of acquisitions since our inception, we have accumulated an acreage position consisting of approximately 936,000 net acres, of which 99% is held by production, and over 2,000 identified horizontal drilling locations, of which more than 750 of these are located in the Oswego formation, a prolific reservoir in north-central Oklahoma. We consider our large inventory of horizontal drilling locations to be low-risk based on information gained from the large number of existing wells in the area, industry activity surrounding our acreage, and the consistent and

predictable geology surrounding our positions. We believe the combination of our large inventory of low-risk drilling locations with the low decline production profile of our Legacy Producing Assets leads to a sustainable production profile.

We focus on controlling costs and maintaining financial discipline, which enables us to prudently develop our assets while generating significant cash available for distribution. Our strategy is to enhance existing production and reduce costs by right-sizing field operations to cost-effectively extract oil and natural gas from producing reservoirs. Our culture of cost control and production optimization has resulted in substantially lower cash operating costs than our peers.

We believe a key competitive advantage that we have over other operators is that we 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, which effectively reduces the cost of operating our midstream assets and reduces our average breakeven costs compared to other operators. We believe the Anadarko Basin is uniquely positioned with legacy takeaway pipeline infrastructure enabling our oil, natural gas and NGLs to be easily transported to premium markets, such as Cushing, Oklahoma.

Our Properties

Our assets are located throughout Western Oklahoma, Southern Kansas and the panhandle of Texas and consist of approximately 4,500 gross operated PDP wells. Our average net daily production for the twelve months ended June 30, 2023 was approximately 65 MBoe/d. We define our Focus Drilling Area assets as all of our horizontal properties that are located in Kingfisher and Logan Counties, Oklahoma, which we define as the Focus Drilling Area, and we define our “Legacy Producing Assets” as all of our legacy producing properties which are not in the Focus Drilling Area, as shown in the chart below. Based on our reserve report as of June 30, 2023, 57% of our production is attributable to our Legacy Producing Assets, which have an average expected annual decline rate of approximately 15%. Our wells are located almost exclusively in the Anadarko Basin, which has a more predictable production profile compared to less mature basins. Our production benefits from both the diversity of our well vintage and the lack of concentration in any specific sub-area. Within our large and diversified PDP base, no single well accounts for more than 1% of our PDP PV-10.

Within our operating areas, our assets are prospective for multiple formations, most notably the Oswego, 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.

In addition to our portfolio of producing wells, our properties include over 2,000 identified horizontal drilling locations that we believe will allow us to maintain our production and support future cash distributions to our unitholders.

Additionally, we own a portfolio of midstream assets which support our leases. As of June 30, 2023, approximately 75% of our operated PDP reserves (and approximately 66% of our total PDP reserves) are supported by Company-owned midstream infrastructure.

The following table presents our historical estimated oil, natural gas and NGL proved reserves as of June 30, 2023.

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(1)      Our estimated net proved and probable reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC regulations. For more information on the prices used, see “— Summary of Reserve, Production and Operating Data — Summary of Reserves.”

(2)      All of our probable reserves are undeveloped. Estimates of probable reserves, and the future cash flows related to such estimates, are inherently imprecise and are more uncertain than estimates of proved reserves and the future cash flows related to such estimates but have not been adjusted for risk due to such uncertainty. Therefore, estimates of probable reserves and the future cash flows related to such estimates may not be comparable to estimates of proved reserves and the future cash flows related to such estimates and should not be summed arithmetically with estimates of proved reserves and the future cash flows related to such estimates. For more information regarding the presentation of probable reserves, see “Business and Properties — Our Operations — Preparation of Reserve Estimates.”

(3)      Presented on an oil-equivalent basis using a conversion of six thousand cubic feet of natural gas to one stock tank barrel of oil. This conversion is based on energy equivalence and not on price or value equivalence.

(4)      For more information on how we calculate PV-10 and a reconciliation of proved reserves PV-10 to its nearest GAAP measure, see “— Summary of Reserve, Production and Operating Data — Summary of Reserves” and “— Non-GAAP Financial Measures — Reconciliation of PV-10 to Standardized Measure.” With respect to PV-10 calculated as of an interim date, it is not practicable to calculate the taxes for the related interim period because GAAP does not provide for disclosure of Standardized Measure on an interim basis.

(5)      For more information on how we calculate Standardized Measure of proved reserves, see “— Non-GAAP Financial Measures — Reconciliation of PV-10 to Standardized Measure.”

Our near-term drilling program is focused on horizontal development in Kingfisher and Logan Counties, Oklahoma. The two primary, productive formations in this area are the Oswego and Meramec/Osage. The Oswego is the most oil rich and economic formation within our inventory. In the early stages of the Oswego horizontal development, a mixture of standard completion fluids and proppant were utilized in the stimulation. We have successfully further lowered our well costs to $3.0 million per well in the Oswego by using drilling efficiencies and utilizing acid in lieu of proppant within the stimulation. As observed in the chart below, the 154 acid-only stimulated wells that we drilled are performing comparably to the proppant-stimulated 75 Oswego wells producing in Kingfisher County, Oklahoma. The below illustrates the average oil production results from the Oswego as of August 2023:

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(1)      Based on Management’s estimates.

(2)      Data and analytics derived from Enverus Core. Includes all offset horizontal wells drilled in Oswego formation with reported proppant loading. Normalized to 5,121 feet.

In addition to the Oswego, there have been over 775 wells in the Meramec/Osage formations drilled and over 1,850 wells in the Mississippi Lime formation drilled on our acreage. Our assets have extensive production histories and high drilling success rates. Accordingly, we believe our acreage has been significantly delineated by our own drilling success and by the success of offset operators.

The below table summarizes our identified horizontal drilling locations as of June 30, 2023.

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(1)      “Business and Properties — Our Operations” contains a description of our methodology used to determine our drilling locations.

(2)      The above table includes 1,357 of our total drilling locations that have been evaluated by Cawley, Gillespie & Associates Inc., our independent reserve engineer, along with 665 drilling locations that have not been evaluated by Cawley, Gillespie & Associates Inc. that were based solely on the internal evaluations of the Company’s management. The 665 drilling locations not evaluated by Cawley, Gillespie & Associates Inc. includes 440 non-operated wells in our Focus Drilling Area Non-Operated and 225 non-operated wells in our Legacy Producing Assets. All 702 of the drilling locations listed under the Focus Drilling Area Operated have been evaluated by Cawley, Gillespie & Associates Inc. See “Risk Factors — Risks Related to Our Business — A portion of our estimated drilling locations are based on our management’s internal estimates and were not based on evaluations prepared by Cawley, Gillespie & Associates Inc.”

We have estimated our drilling locations based on well spacing assumptions for the areas in which we operate and upon the evaluation of our horizontal drilling results and those of other operators in our area, combined with our interpretation of available geologic and engineering data. The drilling locations on which we actually drill will depend on the availability of capital, drilling rigs and labor, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our ability to add proved reserves to our existing proved reserves. See “Risk Factors — Risks Related to Our Business — Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.”

STACK Area Gas Gathering & Processing (“G&P”) and Water Infrastructure

We own a significant complementary portfolio of midstream assets, including gas gathering and processing assets and water infrastructure assets, that supports the development of our properties in Kingfisher County in Oklahoma. For example, the recently constructed Lincoln gas processing plant that we acquired in 2020 has 260 MMcf/d of processing capacity, which is supported by approximately 460 miles of gas gathering lines with approximately 430 receipt point connections, and 27 compressors totaling 35,880 horsepower. Our processing complex has interconnects to both the Panhandle Eastern Pipeline (“PEPL”) and ONEOK Gas Transmission (“OGT”) system.

Our STACK water infrastructure consists of approximately 300 miles of owned gathering pipeline, and our water disposal assets consist of 20 disposal wells with approximately 377,000 BWPD permitted capacity.

Other Gas Gathering & Processing and Water Infrastructure

In addition to our STACK midstream assets, we own and/or operate other midstream assets, including gas gathering and processing, water infrastructure and compression assets that provide additional margin enhancement for our upstream business.

Within these other midstream assets, our 56% owned and operated Laredo gas gathering system, located in Roger Mills County, Oklahoma and Hemphill County, Texas, has approximately 166 MMcf/d of gathering capacity, which is supported by approximately 160 miles of pipeline. Our 50% owned and contract operated McLean processing facility, located in Gray County, Texas, has approximately 23 MMcf/d of processing capacity and is supported by our wholly owned McLean gathering assets consisting of approximately 510 miles of pipeline spanning seven counties in western Oklahoma and the Texas Panhandle. Our 50% owned and contract operated Madill processing facility, located in Marshall County, Oklahoma, has approximately 40 MMcf/d of processing capacity and is supported by our wholly owned Madill gathering assets consisting of approximately 180 miles of pipeline spanning Marshall and Bryan Counties, Oklahoma. Our wholly owned and operated Elmore City gas gathering and processing facility, located in Garvin County, Oklahoma has approximately 30 MMcf/d of processing capacity supported by approximately 60 miles of pipeline. Our 50% owned Mississippi Lime water infrastructure, located in Alfalfa, Woods and Grant Counties, Oklahoma, aids in the disposal of produced water generated by our operations

consisting of approximately 580 miles of pipeline and 35 disposal wells with approximately 300,000 BWPD permitted capacity. Our compression assets consist of a well site compression fleet of approximately 500 units with approximately 89,000 aggregate horsepower.

Development Plan and Capital Budget

Historically, our business plan has focused on acquiring and then exploiting the development and production of our assets. Funding sources for our acquisitions have included proceeds from borrowings under our revolving credit facilities, contributions from our equity partners and cash flow from operating activities. We spent approximately $290.6 million in 2022 on development costs and our budget for 2023 is approximately $316.2 million (of which $207.6 million has been incurred as of June 30, 2023). 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 2023 is focused on drilling Oswego wells given their high oil reserves and low breakeven costs.

During the year ended December 31, 2022, we spent approximately $270.2 million to drill 87.9 net wells and on related equipment, $9.1 million on remedial workovers and other capital projects, $11.3 million on midstream and other property and equipment capital projects, and $142.9 million on acquisitions. During the six months ended June 30, 2023, we spent approximately $182.0 million to drill 50.4 net wells and on related equipment, $18.4 million on remedial workovers and other capital projects, $7.2 million on midstream and other property and equipment capital projects, and $1.5 million on acquisitions.

Based on current commodity prices and our drilling success rate to date, we expect to be able to fund our 2023 capital development programs from cash flow from operations.

Our development plan and capital budget are based on management’s current expectations and assumptions about future events. While we consider these expectations and assumptions to be reasonable, they are subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. The amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated commodity prices, the availability of necessary equipment, infrastructure, drilling rigs, labor and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions and drilling and completion costs.

Our Business Strategies

Our primary business objective is to maximize cash distributions to our unitholders over time. To achieve our objective, we intend to execute the following business strategies:

•        Focus on low decline Legacy Producing Assets with additional meaningful horizontal development inventory.    Our ability to generate significant cash flow is supported by the predictable low decline production profile of our Legacy Producing Assets, which have an average expected annual decline rate of approximately 15%. Based on our reserve report as of June 30, 2023, 57% of our production is attributable to our low decline Legacy Producing Assets. In addition, we believe we have the ability to maintain or modestly grow our average annual production with the development of our horizontal Focus Drilling Area inventory. We have identified over 2,000 horizontal drilling locations within our 936,000 net acre position, of which at a 10% internal rate of return, over 770 are currently economic at $50 per barrel of oil, over 1,100 at $70 per barrel of oil and over 2,000 at $90 per barrel of oil, each assuming a flat natural gas price per Mcf of 1/20th of the assumed oil price.

•        Maximize well economics by leveraging midstream infrastructure.    Our midstream infrastructure assets both reduce our overall upstream costs and generate incremental third-party revenue. In our Oswego formation drilling locations, we estimate that, the oil price necessary to yield a 10% rate of return on invested capital would be approximately $45.47 per barrel of oil equivalent without our midstream assets. We estimate that our complementary midstream assets reduce our average breakeven costs for our Oswego formation drilling locations tied to our owned midstream infrastructure by approximately $4.18 per barrel of oil equivalent to approximately $41.29 per barrel. This reduction consists of the average net cost savings attributable to our working interest resulting from the utilization of our owned midstream infrastructure for gas processing and transportation and water disposal, and the

addition of the incremental third-party midstream revenue attributable to the non-operated portion of the working interest that we do not own. After adding the benefit of our midstream infrastructure, we believe these breakeven costs have comparable economics to the Midland and Delaware Basins.

•        Maintain low operating cost structure to support meaningful cash available for distribution.    Our average cash operating costs during the twelve months ended June 30, 2023, including the benefit of our midstream infrastructure assets, were $12.51 per barrel of oil equivalent, which is 16% lower on average than other unconventional focused operators, and 58% lower on average than other conventional focused operators during the same period. We believe that our low cost structure will help enable us to make unitholder cash distributions during a negative commodity cycle.

•        Leverage industry expertise to improve operations and pursue opportunistic acquisitions in Oklahoma.    Led by industry veteran Tom L. Ward, our senior management team has built lasting relationships with sellers and operators throughout the Anadarko Basin and has developed a track record of acquiring assets at consistently attractive valuations. We believe we can continue to execute opportunistic and accretive transactions that complement our operations in the Anadarko Basin, utilizing our technical expertise to identify acquisition opportunities where our production and cost optimization strategies will yield the greatest returns.

•        Ensure financial flexibility with conservative leverage and ample liquidity.    We intend to conduct our operations through cash flow generated from operations with a focus on maintaining a disciplined balance sheet with little to no outstanding debt. Due to our historically strong operating cash flows and liquidity, we have substantial flexibility to fund our capital budget and to potentially accelerate our drilling program as conditions warrant. Our focus is on the economic extraction of hydrocarbons while maintaining a strong liquidity profile and remaining substantially debt free. Further, to mitigate the risk associated with volatile commodity prices and to further enhance the stability of our cash flow available for distribution, from time to time we may opportunistically hedge a portion of our production volumes at prices we deem attractive.

Our Strengths

We have a number of differentiated strengths that we believe help us successfully execute our business strategy, including:

•        Strong production and cash flow across a large acreage position.    Our average net daily production for the twelve months ended June 30, 2023 was approximately 65 MBoe/d, with approximately 4,500 gross operated wells, and an average working interest of approximately 75%. We own extensive acreage in the Anadarko Basin, with approximately 936,000 net acres, approximately 99% of which is held by production. We believe our large acreage position enables us to optimize our development plan and support significant cash flow generation. For the six months ended June 30, 2023 and year ended December 31, 2022, on a pro forma basis, we generated $196 million and $639 million of net income, respectively, $256 million and $714 million of Adjusted EBITDA, respectively, and $43 million and $402 million of cash available for distribution, respectively. See “— Non-GAAP Financial Measures” and “Our Cash Distribution Policy and Restrictions on Distributions — Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2022 and the Twelve Months Ended June 30, 2023.”

•        Attractive portfolio of large and contiguous core acreage blocks supported by company owned midstream infrastructure.    Since our founding, we have accumulated an acreage position consisting of approximately 936,000 net acres, of which 99% is held by production, and over 2,000 identified horizontal drilling locations, of which more than 750 are located in the Oswego formation. This large acreage position provides flexibility to accelerate our drilling program or execute opportunistic developments as conditions warrant. In addition, we own substantial gathering and processing assets, which improves our cost structure and enhances the stability of our hydrocarbon flows. We believe our acreage footprint and midstream systems allows us to monetize our production at favorable realized prices and reduces our operating costs while providing us with additional incremental third party revenue streams.

•        Optimized operations designed to make cash distributions to unitholders.    Our entrepreneurial culture focuses on operational optimization, cost-minimization, and nimble development to ultimately deliver cash distributions to unitholders across commodity cycles. Our asset profile consists of a large, low cost, and low declining PDP asset, complemented by low-cost horizontal development inventory. Our significant operating experience in the Anadarko Basin and economic advantage conferred by our midstream infrastructure significantly reduces lifting costs relative to other operators. For example, for the twelve months ended June 30, 2023, we achieved a cash operating cost of approximately $12.51 per barrel of oil equivalent, inclusive of the benefit received from our midstream assets. Further, in the early stages of the Oswego horizontal development, a mixture of standard completion fluids and proppant were utilized in the stimulation. Since 2021, we have successfully further lowered our well costs to $3.0 million per well in the Oswego by using drilling efficiencies and utilizing acid in lieu of proppant within the stimulation. Due to our low completion costs, low operating costs, and our midstream advantage, we believe the average breakeven price for our Oswego drilling locations is $41.29 price per barrel of oil.

•        Experienced management team with established track record of value creation.    We believe our management team’s experience in the Anadarko Basin offers a distinguishing advantage. The members of management have an average of 32 years of experience in the oil and gas industry and have successfully executed on a strategy of acquiring and exploiting long-lived and low decline assets. Additionally, our Chief Executive Officer, Tom L. Ward, has over a 40-year history in the oil and gas industry. Further, through our team’s history of operating in Oklahoma, we have built lasting relationships with sellers and developed a track record of successfully acquiring and integrating assets at attractive valuations. From January 2018 to August 2023, we have successfully executed 16 acquisitions for an aggregate purchase price of approximately $960 million, increasing our net acreage to 936,000, and our average net daily production to approximately 65 MBoe/d for the twelve months ended June 30, 2023. Additionally, during the same period, we distributed approximately $630 million in cash to our members. We believe our management team has the experience, expertise and commitment to create significant value in the form of cash distributions to our unitholders.

•        Conservatively capitalized balance sheet and strong liquidity profile.    Since our founding, we have practiced financial conservatism and maintained a strong balance sheet with low leverage. Due to our significant existing low-decline production base, our business generates significant operating cash flow. Upon consummation of this offering, we expect to have little debt and substantial liquidity, which will provide us further financial flexibility to fund our capital expenditures and execute our strategic plan.

Risk Factor Summary

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units, among other things. You should carefully consider the risks described in “Risk Factors” and the other information in this prospectus before investing in our common units. Some of the most significant challenges and risks we face include the following:

Risks Related to Cash Distributions

•        We may not have sufficient available cash to pay any quarterly distribution on our common units following the payment of expenses, funding of development costs and establishment of cash reserves.

•        The amount of our quarterly cash distributions from our available cash, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution and could pay no distribution with respect to any particular quarter.

Risks Related to Our Business

•        Oil, natural gas and NGL prices are volatile. A sustained decline in prices could adversely affect our business, financial condition, results of operations, liquidity, ability to meet our financial commitments, ability to make our planned capital expenditures and our cash available for distribution.

•        Currently, our producing properties are concentrated in the Anadarko Basin, making us vulnerable to risks associated with operating in a limited number of geographic areas.

•        Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

•        Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

•        The development of our estimated proved and probable undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved and probable undeveloped reserves may not be ultimately developed or produced.

•        The marketability of our production is dependent upon gathering, treating, processing and transportation facilities, some of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues could decrease.

•        Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

•        We depend on Mach Resources LLC (“Mach Resources”) to provide us services necessary to operate our business. If Mach Resources were unable or unwilling to provide these services, it would result in a disruption in our business that could have an adverse effect on our financial position, financial results and cash flow.

•        The unavailability or high cost of drilling rigs, frac crews, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.

•        Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

•        Events outside of our control, including widespread public health crises, epidemics and outbreaks of infectious diseases such as COVID-19, or the threat thereof, and any related threats of recession and other economic repercussions could have a material adverse effect on our business, liquidity, financial condition, results of operations, cash flows and ability to pay distributions on our common units.

•        Our business is subject to climate-related transition risks, including evolving climate change legislation, fuel conversation measures, technological advances and negative shift in market perception towards the oil and natural gas industry, which could result in increased operating expenses and capital costs, financial risks and reduction in demand for oil and natural gas.

•        Increased scrutiny of environmental, social, and governance (“ESG”) matters could have an adverse effect on our business, financial condition and results of operations and damage our reputation.

Risks Inherent in an Investment in Us

•        Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.

•        Our partnership agreement does not restrict the Sponsor (as defined below) from competing with us. Certain of our directors and officers may in the future spend significant time serving, and may have significant duties with, investment partnerships or other private entities that compete with us in seeking out acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

•        Our partnership agreement replaces our general partner’s fiduciary duties to us and our unitholders with contractual standards governing its duties, and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

•        Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors, which could reduce the price at which our common units will trade.

•        Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

•        Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent.

•        We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval.

Tax Risks to Common Unitholders

•        Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for U.S. federal income tax purposes or if we were otherwise subject to a material amount of entity-level taxation, then cash available for distribution to our unitholders could be reduced.

•        Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Reorganization Transactions, Partnership Structure and Expected Refinancing Transactions

Each of the following transactions (collectively, the “Reorganization Transactions”) have occurred or will occur immediately prior to the closing of this offering:

•        BCE through its affiliate holding companies will contribute 100% of its membership interests in BCE-Mach, BCE-Mach II, and BCE-Mach III (collectively, the “Mach Companies”) not already owned by BCE-Mach Aggregator LLC (“BCE-Mach Aggregator”) to BCE-Mach Aggregator in exchange for additional membership interests in BCE-Mach Aggregator;

•        Each of BCE-Mach Aggregator, the Management Members and Mach Resources will contribute 100% of their respective membership interests in the Mach Companies to the Company in exchange for a pro rata allocation of 100% of the limited partner interests in the Company;

•        The Company will contribute 100% of its membership interests in the Mach Companies to Mach Natural Resources Intermediate LLC (“Intermediate”) in exchange for 100% of the membership interests in Intermediate; and

•        Intermediate will contribute 100% of its membership interests in the Mach Companies to Mach Natural Resources Holdco LLC (“Holdco”) in exchange for 100% of the membership interests in Holdco.

Except where specified otherwise, the disclosure in this prospectus gives effect to the Reorganization Transactions.

Expected Refinancing Transaction

As of September 1, 2023, we had (i) $17.1 million of outstanding borrowings under the BCE-Mach II credit facility, (ii) $65.0 million of outstanding borrowings and $5 million in outstanding letters of credit under the BCE-Mach credit facility and (iii) $91.9 million of outstanding borrowings under the BCE-Mach III credit facility. We intend to use a portion of the net proceeds of this offering to repay in full and terminate the BCE-Mach II credit facility and repay in full and terminate the BCE-Mach credit facility, with any remaining net proceeds used to repay a portion of the BCE-Mach III credit facility and to purchase common units from the existing common unit owners as described herein. Please see “Use of Proceeds” for additional information.

We are currently negotiating a new credit facility (the “New Credit Facility”) with prospective lenders that we anticipate entering into after the completion of this offering. The amount, maturity, interest rates and other terms of the New Credit Facility are under negotiations with prospective lenders; however, we expect the aggregate commitments thereunder will be in the range of $150 million to $200 million, that the New Credit Facility will be secured by substantially all of our assets and the covenants in the New Credit Facility will be on substantially the same terms as the BCE-Mach III credit facility. For a description of the covenants under the BCE-Mach III credit facility, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 — Debt Agreements — Existing Credit Facilities.” Borrowings under the New Credit Facility may vary significantly from time to time depending on our cash needs at any given time. Once we have entered into the New Credit Facility, we expect to use borrowings under the New Credit Facility to repay in full and terminate the BCE-Mach III credit facility.

We have not yet obtained binding commitments for the New Credit Facility. If we are unable to obtain binding commitments for the New Credit Facility on acceptable terms or at all, the BCE-Mach III credit facility, and potentially the BCE-Mach credit facility depending on the net proceeds of this offering, will remain outstanding after this offering. We cannot assure you that after this offering we will obtain binding commitments for the New Credit Facility sufficient to refinance in full and terminate the BCE-Mach III credit facility. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt agreements”, “Risk Factors” and “Use of Proceeds.”

Ownership and Organizational Structure of Mach Natural Resources

The diagram below depicts our organization and ownership before giving effect to the offering and the Reorganization Transactions.

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(1)      Collectively refers to our current officers and employees who own direct and indirect equity interests in the Mach Companies.

(2)      Investment funds managed by Bayou City Energy Management, LLC own their interests in BCE-Mach LLC, BCE-Mach II LLC and BCE-Mach III LLC through certain holding companies in which investment funds managed by Bayou City Energy Management, LLC hold a majority interest.

(3)      Mach Resources is owned 50.5% by Tom L. Ward through the Tom L Ward 1992 Revocable Trust and 49.5% by WCT Resources LLC which is owned by certain trusts owned by certain of Tom L. Ward’s family members. We will contract with Mach Resources for our employees and other services. See “Certain Relationships and Related Party Transactions.”

The diagram below depicts our organization and ownership after giving effect to the offering and the Reorganization Transactions and assumes that the underwriters do not exercise their option to purchase additional common units.

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(1)      Mach Resources is owned 50.5% by Tom L. Ward through the Tom L Ward 1992 Revocable Trust and 49.5% by WCT Resources LLC which is owned by certain trusts owned by certain of Tom L. Ward’s family members. We will contract with Mach Resources for our employees and other services. See “Certain Relationships and Related Party Transactions” and “Risk Factors — Risks Related to Our Business — We depend on Mach Resources to provide us services necessary to operate our business. If Mach Resources were unable or unwilling to provide these services, it would result in a disruption in our business that could have an adverse effect on our financial position, financial results and cash flow.”

(2)      Collectively refers to our current officers and employees who own direct and indirect equity interests in the Mach Companies.

(3)      Investment funds managed by BCE will own their interests in Mach Natural Resources LP through BCE-Mach Aggregator LLC, a holding company in which investment funds managed by Bayou City Energy Management, LLC hold a majority interest.

(4)      BCE-Mach Aggregator LLC and Mach Resources collectively wholly own Mach Natural Resources GP LLC, our general partner.

Management of Mach Natural Resources

We are managed and operated by the board of directors (the “Board”) and executive officers of our general partner, Mach Natural Resources GP LLC. Our unitholders will not be entitled to elect our general partner or its directors or otherwise participate in our management or operations. For information about the executive officers and directors of our general partner, please read “Management.”

The members of our general partner are (i) BCE-Mach Aggregator, the majority of the membership interests of which are owned by investment funds managed by Bayou City Energy Management, LLC and its affiliates, which we refer to collectively as the Sponsor, and (ii) Mach Resources, which is controlled by Tom L. Ward, with such membership interests and Board appointment rights of such members held in proportion to their respective limited partnership interest ownership in us. As a result, the Sponsor will control our general partner and will be entitled to appoint four members of the Board initially and Mach Resources shall be entitled to appoint one member of the Board initially, who shall be Tom L. Ward.

Our operations are conducted through, and our assets are currently owned by, various subsidiaries. Although all of the employees that conduct our business are either employed by Mach Resources or its subsidiaries, we sometimes refer to these individuals in this prospectus as our employees.

Our Sponsor

Our Sponsor was founded in 2015 by Will McMullen and is a leading upstream-focused private equity firm with $2.2 billion in assets under management. BCE targets control-oriented investments in free-cash-flow focused assets in partnership with best-in-class management teams. BCE has invested approximately $1.0 billion in the Mid-Continent region, and has an investment team with diverse experience across the sector. We believe our relationship with our sponsor gives us access to a highly accomplished and aligned investment partner.

Implications of Being an Emerging Growth Company

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (the “JOBS Act”). For as long as we are an emerging growth company, unlike other public companies that are not emerging growth companies under the JOBS Act, we are not required to:

•        provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002;

•        provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations nor more than two years of selected financial data in a registration statement on Form S-1;

•        comply with any new requirements adopted by the Public Company Accounting Oversight Board (the “PCAOB”) requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; or

•        provide certain disclosure regarding executive compensation required of larger public companies required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”).

We will cease to be an emerging growth company upon the earliest of:

•        the last day of the fiscal year in which we have $1.235 billion or more in annual revenues (as such amount may be adjusted by the SEC for inflation);

•        the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30 of such year);

•        the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or

•        the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards. We have elected to avail ourselves of the provision of the JOBS Act that permits emerging growth companies to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies. As a result, we will not be subject to new or revised accounting standards at the same time as other public companies that are not emerging growth companies. We intend to take advantage of the other exemptions discussed above, both in this prospectus and in future filings with the U.S. Securities and Exchange Commission (the “SEC”). Accordingly, the information contained herein and that we provide to our unitholders from time to time may be different than the information you receive from other public companies. For additional information, see the section titled “Risk Factors — Risks Inherent in an Investment in Us — For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies, including those relating to auditing standards and disclosure about our executive compensation. Taking advantage of the longer phase-in periods for the adoption of new or revised financial accounting standards applicable to emerging growth companies may make our common units less attractive to investors.”

Principal Executive Offices and Internet Address

Our principal executive offices are located at 14201 Wireless Way, Suite 300, Oklahoma City, Oklahoma 73134 and our telephone number at that address is (405) 252-8100. Our website address is www.machresources.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on, or otherwise accessible through, our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

Summary of Conflicts of Interest and Duties

Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is not adverse to our best interests. However, because our general partner is owned by BCE-Mach Aggregator and Tom L. Ward through his ownership of Mach Resources, the officers and directors of our general partner also have a duty to manage the business of our general partner at the direction of BCE-Mach Aggregator and Tom L. Ward through his ownership of Mach Resources. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including the Sponsor and Tom L. Ward in his capacity as a member of our general partner through his ownership of Mach Resources, on the other hand; provided, however, that upon our adoption of our code of business conduct, we would expect that any such member of our management, so long as they are an executive officer, will be required to avoid personal conflicts of interest and not compete against us, in each case unless approved by the Board. For example, our general partner is entitled to make determinations that affect our ability to generate the cash flow necessary to make cash distributions to our unitholders, including determinations related to:

•        purchases and sales of oil and natural gas properties and other acquisitions and dispositions, including whether to pursue acquisitions that may also be suitable for the Sponsor or any affiliate of the Sponsor;

•        the manner in which our business is operated;

•        the level of our borrowings;

•        the amount, nature and timing of our capital expenditures; and

•        the amount of cash reserves necessary or appropriate to satisfy our general, administrative and other expenses and debt service requirements and to otherwise provide for the proper conduct of our business.

For a more detailed description of the conflicts of interest and duties of our general partner, please read “Risk Factors — Risks Inherent in an Investment in Us” and “Conflicts of Interest and Duties.”

Our partnership agreement can generally be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including any common units held by our general partner and its affiliates). Upon consummation of this offering and the application of the use of proceeds as described under “Use of Proceeds,” our general partner will continue to be controlled by the Sponsor and Tom L. Ward through his ownership of Mach Resources, who will own and control the voting of an aggregate of approximately             % and             %, respectively, of our outstanding common units (or             % and             %, respectively, of our outstanding common units if the underwriters exercise in full their option to purchase additional common units). Assuming that we do not issue any additional common units and the Sponsor and Tom L. Ward through his ownership of Mach Resources do not transfer their respective common units, the Sponsor and Tom L. Ward will have the ability to control any amendment to our partnership agreement, including our policy to distribute all of our available cash to our unitholders. Please see “Risk Factors — Risks Inherent in an Investment in Us” and “The Partnership Agreement — Amendment of the Partnership Agreement.”

Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the duties owed and remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of its fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including the Sponsor and

its affiliates, are not restricted from competing with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement, each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Duties — Duties of Our General Partner” for a description of the duties imposed on our general partner by Delaware law, the replacement of those duties with contractual standards under our partnership agreement and certain legal rights and remedies available to holders of our common units.

In connection with this offering, the Company will enter into a management services agreement (“MSA”) with Mach Resources. Under the MSA, Mach Resources will manage and perform all aspects of oil and gas operations and other general and administrative functions for the Company. On a monthly basis, the Company will reimburse Mach Resources for certain costs and expenses related to its performance under the MSA. For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

The Offering

Summary Historical and Pro Forma Financial and Operating Data

Unless otherwise indicated, the historical financial information presented in this prospectus is that of our predecessor. The historical financial information of BCE-Mach LLC and BCE-Mach II LLC is also included herein as indicated.

The summary historical financial data set forth below as of and for each of the years ended December 31, 2022 and 2021 have been derived from our audited consolidated financial statements included elsewhere in this prospectus. The summary historical financial data set forth below as of June 30, 2023 and for the six months ended June 30, 2023 and 2022 have been derived from our unaudited financial statements and related notes included elsewhere in this prospectus.

The summary unaudited pro forma financial data as of June 30, 2023 and for the six months ended June 30, 2023 and year ended December 31, 2022 are derived from the unaudited pro forma condensed combined financial statements of Mach Natural Resources included elsewhere in this prospectus, which reflect the historical results of our predecessor, BCE-Mach LLC and BCE-Mach II LLC on a pro forma basis to give effect to the following transactions, which are described in further detail below, as if they had occurred on June 30, 2023, for pro forma balance sheet purposes, and on January 1, 2022, for pro forma statements of operations purposes:

•        the Reorganization Transactions as described in “— Reorganization Transactions, Partnership Structure and Expected Refinancing Transactions” elsewhere in this prospectus summary; and

•        the issuance and sale by us to the public of common units in this offering and the application of the net proceeds as described in “Use of Proceeds.”

We have not given pro forma effect to the incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership.

The unaudited pro forma historical financial data are presented for illustrative purposes only and are not necessarily indicative of the financial position that would have existed or the financial results that would have occurred if this offering and the Reorganization Transactions had occurred on the dates indicated, nor are they necessarily indicative of the financial position or results of our operations in the future. The pro forma adjustments, as described in the notes to the unaudited pro forma condensed combined financial statements, are preliminary and based upon currently available information and certain assumptions that our management believes are reasonable. The summary historical financial data are qualified in their entirety by, and should be read in conjunction with, the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section included in this prospectus and the consolidated financial statements and related notes and other financial information included in this prospectus. Among other things, those historical financial statements and unaudited pro forma condensed combined financial statements include more detailed information regarding the basis of presentation for the following information. Historical results are not necessarily indicative of results that may be expected for any future period.

The following table presents non-GAAP financial measures, Adjusted EBITDA and cash available for distribution, which we use in evaluating the financial performance of our business. These measures are not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain these measures below and reconcile them to the most directly comparable financial measures calculated and presented in accordance with GAAP.

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(1)      Adjusted EBITDA is a non-GAAP financial measure, please see “— Non-GAAP Financial Measures” below.

(2)      Cash available for distribution is a non-GAAP financial measure, please see “— Non-GAAP Financial Measures” below.

Non-GAAP Financial Measures

Adjusted EBITDA

We include in this prospectus the non-GAAP financial 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, (2) depreciation, depletion and amortization, (3) unrealized (gain) loss on derivative settlements, (4) equity-based compensation expense, (5) loss on contingent consideration and (6) (gain) loss on sale of assets.

Adjusted EBITDA is used as a supplemental financial 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

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 measure used by our management and by external users of our financial statements, such as investors, lenders and others (including industry analysts and rating agencies who will be using such measure), 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, (2) depreciation, depletion and amortization, (3) unrealized (gain) loss on derivative settlements, (4) equity-based compensation expense, (5) loss on contingent consideration, (6) (gain) loss on sale of assets, (7) settlement of asset retirement obligations, (8) net cash interest expense, (9) development costs, (10) settlement of contingent consideration and (11) 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.

Reconciliations of GAAP Financial Measures to Adjusted EBITDA and Cash Available for Distribution

The following table presents our reconciliation of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measures Adjusted EBITDA and cash available for distribution, as applicable, for each of the periods indicated.

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(1)      Development costs includes all of our capital expenditures, other than acquisitions.

Reconciliation of PV-10 to Standardized Measure

Certain of our oil and natural gas reserve disclosures included in this prospectus are presented on a PV-10 basis. PV-10 is a non-GAAP financial measure and represents the estimated present value of the future cash flows less future development and production costs from our proved and probable reserves before income taxes discounted using a 10% discount rate. PV-10 of proved reserves generally differs from the standardized measure of discounted future net cash flows from production of proved oil and natural gas reserves (the “Standardized Measure”), the most directly comparable GAAP financial measure, because it does not include the effects of future income taxes, as is required under GAAP in computing the Standardized Measure. However, our PV-10 for proved and probable reserves using SEC pricing and the Standardized Measure of proved reserves are equivalent because we were not subject to entity level taxation. Accordingly, no provision for federal or state income taxes has been provided in the Standardized Measure because taxable income is passed through to our unitholders.

We believe that the presentation of a pre-tax PV-10 value provides relevant and useful information because it is widely used by investors and analysts as a basis for comparing the relative size and value of our proved and probable reserves to other oil and natural gas companies. Because many factors that are unique to each individual company may impact the amount and timing of future income taxes, the use of PV-10 value provides greater comparability when evaluating oil and natural gas companies. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of proved oil and gas reserves. However, the definition of PV-10 value as defined above may differ significantly from the definitions used by other companies to compute similar measures. As a result, the PV-10 value as defined may not be comparable to similar measures provided by other companies.

Investors should be cautioned that neither PV-10 nor Standardized Measure of proved reserves represents an estimate of the fair market value of our proved and probable reserves. We and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities.

Summary of Reserve, Production and Operating Data

The following tables summarize our estimated proved and probable oil, natural gas and NGL reserves as of June 30, 2023 and our estimated proved oil, natural gas and NGL reserves as of December 31, 2022 and our production and historical operating data for the six months ended June 30, 2023 and year ended December 31, 2022 on a pro forma combined basis. The information included in these tables consolidates information about the Mach Companies and is based on reserve reports prepared by our independent consulting petroleum engineers, Cawley, Gillespie & Associates, Inc. For more information regarding our reserve volumes and values, see “Business and Properties — Operating Data” and our summary reserve report filed as an exhibit to the registration statement of which this prospectus forms a part. Historical reserve volumes and values are not necessarily indicative of results that may be expected for any future period.

Summary of Reserves

Our historical SEC reserves, PV-10 and Standardized Measure of proved reserves were calculated using oil and gas price parameters established by current SEC guidelines, including the use of an average effective price, calculated as prices equal to the 12-month unweighted arithmetic average of the first day of the month prices for each of the preceding 12 months as adjusted for location and quality differentials, unless prices are defined by contractual arrangements, excluding escalations based on future conditions (“SEC Pricing”). These prices were adjusted for differentials on a per-property basis, which may include local basis differential, fuel costs and shrinkage. All prices are held constant throughout the lives of the properties.

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(1)      Our estimated net proved and probable reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC regulations. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $93.67 per barrel for oil and $6.358 per Mcf for natural gas at January 1, 2023 and $82.82 per barrel for oil and $4.763 per MMBtu for natural gas at June 30, 2023. These base prices were adjusted for differentials on a per-property basis, which may include local basis differentials, fuel costs and shrinkage.

(2)      PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved and probable oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows. For more information on how we calculate PV-10 and a reconciliation of proved reserves PV-10 to its nearest GAAP measure, see “— Non-GAAP Financial Measures — Reconciliation of PV-10 to Standardized Measure.” With respect to PV-10 calculated as of an interim date, it is not practicable to calculate the taxes for the related interim period because GAAP does not provide for disclosure of Standardized Measure on an interim basis.

(3)      All of our probable reserves are undeveloped. Estimates of probable reserves, and the future cash flows related to such estimates, are inherently imprecise and are more uncertain than estimates of proved reserves and the future cash flows related to such estimates but have not been adjusted for risk due to such uncertainty. Therefore, estimates of probable reserves and the future cash flows related to such estimates may not be comparable to estimates of proved reserves and the future cash flows related to such estimates and should not be summed arithmetically with estimates of proved reserves and the future cash flows related to such estimates. For more information regarding the presentation of probable reserves, see “Business and Properties — Our Operations — Preparation of Reserve Estimates.”

Select Production and Operating Statistics

The following table summarizes the Mach Companies’ oil, natural gas and NGL production and historical operating data for the periods presented on a combined unaudited pro forma basis.

The unaudited pro forma combined net production volumes and realized prices for the six months ended June 30, 2023 and year ended December 31, 2022 treat the Reorganization Transactions as if they had occurred on January 1, 2022.