As filed with the U.S. Securities and Exchange Commission on September 4, 2024.

Registration No. 333-

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

______________________________________

Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

______________________________________

Mach Natural Resources LP
(Exact name of registrant as specified in its charter)

______________________________________

Delaware	1311	93-1757616
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

14201 Wireless Way, Suite 300
Oklahoma City, Oklahoma 73134
(405) 252-8100
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

______________________________________

Tom L. Ward
Chief Executive Officer
14201 Wireless Way, Suite 300
Oklahoma City, Oklahoma 73134
(405) 252-8100
(Name, address, including zip code, and telephone number, including area code, of agent for service)

______________________________________

Copies to:

Julian J. Seiguer, P.C.
Michael W. Rigdon, P.C.
Kirkland & Ellis LLP
609 Main Street, Suite 4700
Houston, Texas 77002
(713) 836-3600 Joshua Davidson Douglas V. Getten Baker Botts L.L.P. 910 Louisiana Street Houston, Texas 77002 (713) 229-1234

______________________________________

Approximate date of commencement of proposed sale to the public:

As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b 2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒	Smaller reporting company	☐
		Emerging growth company	☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☐

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell the securities described herein until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell the securities described herein and it is not soliciting an offer to buy such securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED September4, 2024

PRELIMINARY PROSPECTUS

Mach Natural Resources LP

7,853,403Common Units

Representing Limited Partner Interests

______________________________________

Mach Natural Resources LP is a Delaware limited partnership 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. We are offering 7,853,403 common units representing limited partner interests (“common units”) to the underwriters in a firm commitment offering.

Our common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “MNR.” On September3, 2024, the last reported sale price of our common units on the NYSE was $19.10 per common unit. The public offering price will be determined between us and the underwriters at the time of pricing and may be at a discount to the current market price. Accordingly, the recent market price used throughout this prospectus may not be indicative of the public offering price.

The underwriters have an option to purchase up to 1,178,010 additional common units from us. The underwriters can exercise this option at any time within 30 days from the date of this prospectus.

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) and are therefore subject to reduced reporting requirements for this prospectus and future filings.

Investing in our common units involves risks. See the “Risk Factors” section beginning on page 15 of this prospectus.

Title of Each Class of Securities to be Registered	Per Common Unit	Total
Public offering price	$	$
Underwriting discounts and commissions(1)	$	$
Proceeds, before expenses, to us	$	$

____________

(1)See “Underwriting and Plan of Distribution” for a description of compensation to be paid to the underwriters.

Delivery of the common units will be made on or about, 2024 through the book entry facilities of The Depository Trust Company.

Neither the Securities and Exchange Commission (the “SEC”) nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Joint Book-Running Managers

Raymond James Stifel Truist Securities

Co-Managers

Johnson Rice & Company Stephens Inc.

The date of this prospectus is, 2024.

TABLE OF CONTENTS

	Page
PROSPECTUS SUMMARY	1
RISK FACTORS	15
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS	19
USE OF PROCEEDS	22
CAPITALIZATION	23
MANAGEMENT	24
PRINCIPAL UNITHOLDERS	26
CONFLICTS OF INTEREST AND DUTIES	28
DESCRIPTION OF COMMON UNITS	36
CASH DISTRIBUTION POLICY	38
DESCRIPTION OF THE PARTNERSHIP AGREEMENT	40
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES	52
UNDERWRITING AND PLAN OF DISTRIBUTION	71
LEGAL MATTERS	74
EXPERTS	74
WHERE YOU CAN FIND MORE INFORMATION	75
INCORPORATION OF CERTAIN INFORMATION BY REFERENCE	76
INDEX TO FINANCIAL STATEMENTS	F-1

We and the underwriters have not authorized anyone to provide any information other than that contained or incorporated by reference in this prospectus or in any free writing prospectus prepared by or on behalf of us or to which we have referred you. We and the underwriters take no responsibility for, and can provide no assurance and make no representation as to the reliability of, any other information that others may give you. We are offering to sell and are seeking offers to buy our securities only in jurisdictions where offers and sales are permitted. The information contained or incorporated by reference in this prospectus and any free writing prospectus is accurate only as of their respective dates, regardless of the time of delivery of this prospectus or of any sale of our securities.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

i

BASIS OF PRESENTATION

Mach Natural Resources LP (the “Company”) is a Delaware limited partnership that was formed for the purpose of effectuating an initial public offering (the “IPO”) that closed in October 2023. On October 25, 2023, the Company underwent a corporate reorganization (the “Corporate Reorganization”) in connection with the IPO whereby the existing owners who directly held membership interests in BCE-Mach LLC (“BCE-Mach”), BCE-Mach II LLC (“BCE-Mach II”) and BCE-Mach III LLC (“BCE-Mach III” and, together with BCE-Mach and BCE-Mach II, the “Mach Companies”) prior to the Offering contributed 100% of their membership interests in the Mach Companies for a pro rata allocation of 100% of the limited partner interests in the Company to effectuate a merger of such entities into the Company with BCE-Mach III determined as the accounting acquirer.

Our historical financial statements presented in or incorporated by reference in this prospectus reflect only the results of BCE-Mach III, or our accounting predecessor, for periods prior to the consummation of the IPO. For periods after our IPO, our historical financial statements also include the results of BCE-Mach and BCE-Mach II as acquired entities in the corporate reorganization. Furthermore, on December 28, 2023, we acquired certain oil and gas assets (the “Paloma Assets” and such acquisition, the “Paloma Acquisition”) from Paloma Partners IV, LLC (“Paloma”), and the results of such assets are reflected in our historical financial statements for periods after December 28, 2023.

This prospectus contains unaudited pro forma financial information, which presents certain financial information of our IPO predecessor, BCE-Mach, BCE-Mach II and Paloma, on a pro forma combined basis to give effect to such acquisitions as if they had occurred at the beginning of the periods presented.

ii

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 under “Risk Factors,” and “Forward-Looking Statements” included elsewhere in this prospectus and in the SEC filings we incorporate by reference before deciding to invest in our common units. 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.

Our Company

We are an independent upstream oil and gas company focused on the acquisition, development and production of oil, natural gas and natural gas liquid (“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 (as defined below) 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 nature of our low declining producing assets and large inventory of horizontal drilling locations with average royalty burdens of less than 20%, 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. 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, such as the Paloma Acquisition and the Pending Acquisitions (as defined below). 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 20%. Through a series of acquisitions since our inception, we have accumulated an acreage position consisting of 1,001,778 net acres, of which 99% is held by production, and approximately 2,000 identified horizontal drilling locations, of which more than 600 of these are located in the Woodford, Mississippian and Oswego formations, prolific reservoirs located throughout 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 production profile of our low declining 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.

1

Our Properties

Our assets are located throughout Western Oklahoma, Southern Kansas and the panhandle of Texas and consist of approximately 4,600 gross operated proved developed producing (“PDP”) wells. Our wells are located almost exclusively in the Anadarko Basin, which has a more predictable production profile compared to less mature basins. We view our assets in two groupings, our focus drilling area and our low declining producing assets. We define our “focus drilling area” assets as all of our horizontal properties that are located in Kingfisher, Logan, Canadian, Custer, Grady, Blaine and Caddo Counties, Oklahoma, and we define our “low declining producing assets” as all of our low declining producing properties which are not in the focus drilling area. Within our operating areas, our assets are prospective for multiple formations, most notably the Oswego, Woodford, Meramec/Osage, Mississippi Lime and Sycamore 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 1,210 miles of gas gathering pipelines, four processing plants with combined processing capacity of 353 MMcf/d, and water infrastructure consisting of 880 miles of gathering pipeline and 55 disposal wells. 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 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 declining producing assets with additional meaningful horizontal development inventory.    Our ability to generate significant cash flow is supported by the predictable production profile of our low declining producing assets, which have an average expected annual decline rate of approximately 11%. Based on our reserve report as of December31, 2023, 31% of our production is attributable to our low declining 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 approximately 2,000 horizontal drilling locations within our 1,001,778 net acre position.

•Maximize well economics by leveraging midstream infrastructure.    Our midstream infrastructure assets both reduce our overall upstream costs and generate incremental third-party revenue. Our complementary midstream assets reduce our average breakeven costs for our Oswego formation drilling locations tied to our owned midstream infrastructure. 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 six months ended June30, 2024, including the benefit of our midstream infrastructure assets, were $10.96 per barrel of oil equivalent, which is lower on average than other 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, such as the Paloma Acquisition and the Pending Acquisitions 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.

2

•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 a target long-term net debt to Adjusted EBITDA ratio of 1.0x or less. 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. 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 six months ended June30, 2024 was approximately 89.2 MBoe/d, with approximately 4,600 gross operated wells, and an average working interest of approximately 77%. We own extensive acreage in the Anadarko Basin, with 1,001,778 net acres, approximately 99% of which is held by production, and approximately 2,000 identified horizontal drilling locations, of which more than 600 are located in the Woodford, Mississippian and Oswego formations. We believe our large acreage position enables us to optimize our development plan and support significant cash flow generation. For the six months ended June30, 2024 and the year ended December31, 2023, we generated $81.2 million and $346.6 million of net income, respectively, $304.6 million and $450.1 million of Adjusted EBITDA, respectively, and $134.9 million and $135.1 million of cash available for distribution, respectively. See “— Non-GAAP Financial Measures.”

•Attractive portfolio of large and contiguous core acreage blocks supported by company owned midstream infrastructure.    Since our founding, we have accumulated a large acreage position which 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 reserves, 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 six months ended June30, 2024, we achieved a cash operating cost of approximately $10.96 per barrel of oil equivalent, inclusive of the benefit received from our midstream assets. Furthermore, in the early stages of the Oswego horizontal development, a mixture of standard completion fluids and proppant were utilized in the stimulation.

•Expansive Acreage Position.    We believe our land acquisition strategies have allowed us to efficiently target and assemble an expansive, contiguous acreage position in the Anadarko Basin with significant potential. Our acquisition strategies are predicated on assembling large contiguous acreage blocks with favorable geological and reservoir characteristics. On December28, 2023, we completed the Paloma Acquisition which further increased our footprint in the Anadarko Basin. Specifically, the Paloma Acquisition added approximately 62,000 net acres and expanded our asset portfolio to include the STACK and Merge plays. The STACK leasehold we purchased in the Paloma Acquisition is primarily located across Canadian and Kingfisher counties, and the majority of the Merge play leasehold we purchased in the Paloma Acquisition is also located in the Anadarko Basin and generally covers Caddo, Grady and McClain counties. Within our operating areas, our acreage is prospective for multiple formations, including the Woodford, Sycamore, Oswego, and Meramec/Osage. In total, our asset

3

portfolio consists of 1,001,778 net acres, providing us a contiguous land position with high operational control in both the STACK play, as well as the Merge play. We believe that our expansive acreage position uniquely positions us to implement and benefit from our focus of maximizing returns.

•Experienced management team with established track record of value creation.We believe our management team’s experience in the Anadarko Basin offers a distinctive 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. Furthermore, 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. Since January 2018, we have successfully executed 17 acquisitions for an aggregate purchase price of approximately $1.8 billion, increasing our net acreage to 1,001,778, and our average net daily production to approximately 89.2 MBoe/d for the six months ended June30, 2024. Additionally, since our initial public offering, we have distributed approximately $161.6 million in cash to our unitholders. 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 a target long-term net debt to Adjusted EBITDA ratio of 1.0x or less. Due to our significant existing low-decline production base, our business generates significant operating cash flow.

Recent Developments

Pending Acquisitions

On August26, 2024, we entered into a Consent Agreement with the purchaser under a Purchase and Sale Agreement (the “Ardmore Basin Purchase Agreement”) that assigns us the right to purchase certain oil and gas assets located in the Ardmore Basin of Oklahoma for consideration of $98.0million in cash, subject to customary purchase price adjustments (the “Ardmore Basin Acquisition”). We expect the Ardmore Basin Acquisition to close in the third quarter of 2024, subject to the satisfaction of specified closing conditions. If consummated, the effective date of the Ardmore Basin Acquisition will be May1, 2024. As of August9, 2024, the assets included in the Ardmore Basin Acquisition are comprised of 3,590 net acres, with 19 operated wells.

On August 9, 2024, we entered into a Purchase and Sale Agreement (the “Western Kansas Purchase Agreement” and, together with the Ardmore Basin Purchase Agreement, the “Purchase Agreements”) to purchase certain oil and gas assets located in the Anadarko Basin of Kansas and Oklahoma, for consideration of $38.0 million in cash, subject to customary purchase price adjustments (the “Western Kansas Acquisition” and, together with the Ardmore Basin Acquisition, the “Pending Acquisitions”). We expect the Western Kansas Acquisition to close in the third quarter of 2024, subject to the satisfaction of specified closing conditions. If consummated, the effective date of the Western Kansas Acquisition will be July 1, 2024. As of August 9, 2024, the assets included in the Western Kansas Acquisition are comprised of 128,788 net acres, with 270 operated wells.

As of July31, 2024, the total proved reserves of the combined assets to be purchased in the Pending Acquisitions (together, the “Ardmore and Anadarko Assets”) is 10.6 MMBoe with total PV-10 of $153.8 million. The total production from these reserves was 4,347 Boe/d, consisting of approximately 45% oil, 30% NGLs, and 25% gas, as of the six months ended February 29, 2024. We expect the December 2024 average daily production for the Ardmore and Anadarko Assets to increase to an estimated 5,220 Boe/d, consisting of approximately 47% oil, 25% NGLs, and 28% gas. We expect to hedge a portion of the underlying production to protect distributions and our balance sheet. The combined proved reserves of the Ardmore and Anadarko Assets are expected to have an average annual decline rate of approximately 20%.

As a result of the Pending Acquisitions, we expect to increase our total leasehold and mineral acreage from 1,001,778 net acres to 1,134,156 net acres, which positions us well to implement and benefit from our focus of maximizing returns.

4

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.

Estimates of proved reserves for the Ardmore and Anadarko Assets as of July 31, 2024 have been prepared by Cawley, Gillespie & Associates, Inc. using the information available at that time.

Our assessment and estimates of Ardmore and Anadarko Assets to date have been limited. Even upon closing of the Pending Acquisitions, our assessment of the Ardmore and Anadarko Assets may not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. Please read “Risk Factors.”

We intend to fund the purchase price for the Pending Acquisitions through a combination of the net proceeds from this offering. We have a target long-term net debt to Adjusted EBITDA ratio of 1.0x or less. This offering is not conditioned upon the consummation of either Pending Acquisition, and neither Pending Acquisition is conditioned upon the consummation of the other Pending Acquisition. We cannot assure you that we will consummate either Pending Acquisition on the terms described herein or at all. Please read “Risk Factors.”

Credit Agreements

On August26, 2024, we entered into (i) the first amendment (the “First Term Loan Amendment”) to the senior secured term loan credit agreement, dated as of December28, 2023 (the “Term Loan Credit Agreement”), among the Company, the guarantors party thereto, the lenders party thereto, Texas Capital Bank, as the administrative agent, and Chambers Energy Management, LP, as the loan commitment arranger, and (ii) the first amendment (the “First RCA Amendment”) to the senior secured revolving credit agreement, dated as of December28, 2023 (the “Revolving Credit Agreement”), among the Company, the guarantors party thereto, the lenders party thereto and MidFirst Bank, as the administrative agent.

The First Term Loan Amendment amends the Term Loan Credit Agreement to, among other things, provide for commitments from the lenders party to the First Term Loan Amendment to make up to an aggregate amount of $75million in Additional Loans (as defined in the First Term Loan Amendment).

The First RCA Amendment amends the Revolving Credit Agreement to, among other things, permit the Company to incur the Additional Loans and modify certain definitions relating to the Company’s hedging arrangements. The First RCA Amendment also reaffirms the Company’s borrowing base at $75million.

Our Sponsor

BCE was founded in 2015 by William McMullen and is a leading upstream-focused private equity firm with $2.2 billion in assets under management. Our Sponsor 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.

Corporate Information

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 machnr.com. We 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.

5

Implications of Being an Emerging Growth Company

We are an “emerging growth company” as defined in 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 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.

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

•December31, 2028.

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 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.

6

THE OFFERING

Common units offered by us	7,853,403 common units representing limited partner interests (or 9,031,413 common units if the underwriters exercise in full their option to purchase additional common units).
Underwriter’s option to purchase additional common units	We have granted the underwriter a 30-day option to purchase up to an additional 1,178,010 common units on the same terms and conditions as set forth above if the underwriter sells more than 7,853,403 common units in this offering.
Common units to be outstanding after this offering	102,893,092 common units (or 104,071,102 common units if the underwriters exercise in full their option to purchase additional common units).
Use of proceeds	We estimate that the net proceeds to us from this offering will be approximately $141.4million (or approximately $162.8million if the underwriters exercise in full their option to purchase additional common units), based on an assumed public offering price of $19.10 per common unit, which was the last reported sale price of our common units on the New York Stock Exchange (“NYSE”) on September3, 2024, and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us. We intend to use the net proceeds of this offering to fund the Pending Acquisitions and for general partnership purposes, which may include future acquisitions. See “Use of Proceeds.”
Cash distributions	Our partnership agreement requires that, within 90 days after the end of each quarter, we will pay distributions of our available cash to unitholders of record on the applicable record date. Our partnership agreement generally provides that we will distribute all available cash each quarter to the holders of common units, pro rata. We do not have a minimum quarterly distribution nor is there any guarantee that we will make any particular amount of distributions or any distributions to our unitholders in any quarter. The first quarter distribution of $0.75 per common unit for the three months ended March 31, 2024, was declared on May 13, 2024 and was paid on June 10, 2024 to unitholders of record as of May 28, 2024. Since our initial public offering, we have distributed approximately $161.6 million in cash to our unitholders. Our ability to pay such cash distributions is subject to various restrictions and other factors described in more detail in the section entitled “Cash Distribution Policy.”
Material tax consequences	For a discussion of material U.S. federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please see the section entitled “Material U.S. Federal Income Tax Consequences.”
Listing	Our common units are listed on the NYSE under the symbol “MNR.”

7

Risk Factors	You should carefully read and consider the information set forth under the heading “Risk Factors” beginning on page 15 of this prospectus and other risk factors incorporated by reference into this prospectus before deciding to invest in our common units.
Transfer Agent	Equiniti Trust Company, LLC.

Unless otherwise indicated, all information in this prospectus, including the number of common units that will be outstanding after this offering and other unit-related information, is based on 95,039,689 common units outstanding as of September3, 2024 and excludes 8,797,459 additional common units reserved for future issuance under the Mach Natural Resources LP 2023 Long-Term Incentive Plan (the “LTIP”).

8

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

We prepared the summary consolidated financial data using our consolidated financial statements for each of the periods presented. The summary consolidated financial data for each fiscal year in the two-year period ended December 31, 2023 was derived from our audited consolidated financial statements incorporated by reference in this prospectus. The summary consolidated financial data as of and for the six months ended June 30, 2024 and June 30, 2023 was derived from our unaudited interim condensed consolidated financial statements incorporated by reference in this prospectus. In the opinion of management, such unaudited interim condensed consolidated financial statements have been prepared on the same basis as the audited consolidated financial statements and reflect all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of our results of operations and financial position.

The summary unaudited pro forma financial data as of and for the year ended December 31, 2023 reflects the results of our predecessor, BCE-Mach, BCE-Mach II and Paloma on a pro forma basis to give effect to the initial public offering and related corporate reorganization and acquisition of BCE-Mach and BCE-Mach II and the Paloma Acquisition as if they had occurred on January 1, 2023. The summary unaudited pro forma financial data does not include the Pending Acquisitions. The unaudited pro forma historical financial data is 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 acquisitions had occurred on the dates indicated, nor are they necessarily indicative of the financial position or results of our operations in the future.

You should read this financial data in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our SEC filings and our consolidated historical and pro forma financial statements and related notes included herein and incorporated by reference in this prospectus.

	Mach Natural Resources Historical										Mach Natural Resources Pro Forma
	Six Months Ended June 30,					Year Ended December 31,					Year Ended December 31, 2023
(in thousands, except per unit amounts)	2024			2023		2023		2022
Statement of Operations Data:
Operating Revenues:
Oil, natural gas, and NGL sales	$	486,779		$	312,613	$	647,352	$	860,388		$	1,128,533
Gain (loss) on oil and natural gas derivatives		(33,903	)		15,742		57,272		(67,453	)		65,423
Midstream revenue		12,660			13,318		26,328		44,373			26,681
Product sales		13,613			17,421		31,357		100,106			31,357
Total operating revenues		479,149			359,094		762,309		937,414			1,251,994
Operating Expenses:
Gathering and processing expense		55,773			17,510		39,449		47,484			100,882
Lease operating expense		87,257			60,615		127,602		95,941			189,790
Production taxes		24,054			15,526		31,882		47,825			54,983
Midstream operating expense		5,175			5,538		10,873		15,157			11,255
Cost of product sales		11,886			15,575		28,089		94,580			28,089
Depreciation, depletion, amortization and accretion expense – oil and natural gas		131,191			58,095		131,145		84,070			259,918
Depreciation and amortization expense – other		4,340			2,793		6,472		4,519			7,197
General and administrative expense		18,046			7,770		22,861		23,491			28,765
General and administrative expense – related party		3,700			2,135		4,792		1,963			4,792
Total operating expenses		341,422			185,557		403,165		415,030			685,671
Income from operations		137,727			173,537		359,144		522,384			566,323

9

	Mach Natural Resources Historical												Mach Natural Resources Pro Forma
	Six Months Ended June 30,						Year Ended December 31,						Year Ended December 31, 2023
(in thousands, except per unit amounts)	2024			2023			2023			2022
Other (expense) income:
Interest expense		(53,331	)		(3,789	)		(11,201	)		(4,852	)		(104,448	)
Gain (loss) on sale of assets														(1,385	)
Other (expense) income, net		(3,178	)		(245	)		(1,385	)		(691	)		(6,919	)
Total other expense		(56,509	)		(4,034	)		(12,586	)		(5,543	)		(112,752	)
Net income	$	81,218		$	169,503			346,558		$	516,841		$	453,571
Less: net income attributable to Predecessor		—			—			(278,040	)		—			—
Net income attributable to Mach Natural Resources LP		—			—		$	68,518			—		$	453,571
Net income per common unit attributable to Mach Natural Resources LP:
Basic	$	0.85			—		$	0.72			—		$	4.77
Diluted	$	0.85			—		$	0.72			—		$	4.77
Weighted average common units outstanding:
Basic		95,004			—			94,907			—			95,000
Diluted		95,129			—			94,907			—			95,000
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	260,784		$	275,145		$	491,742		$	553,542
Investing activities	$	(85,261	)	$	(187,812	)	$	(1,027,157	)	$	(372,660	)
Financing activities	$	(183,694	)	$	(67,904	)	$	658,790		$	(210,737	)
Balance Sheet Data (at period end):
Cash and cash equivalents	$	144,621					$	152,792		$	29,417
Oil and natural gas properties, net	$	1,785,361					$	1,831,645		$	610,420
Total assets	$	2,235,037					$	2,304,515		$	887,858
Total long-term liabilities	$	802,256					$	837,882		$	141,570
Members’ equity/Partners’ capital	$	1,113,110					$	1,191,724		$	593,230

Non-GAAP Financial Measures

Adjusted EBITDA

We include in this prospectus 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

10

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 performance and liquidity 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.

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

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.

	Mach Natural Resources Historical
	Six Months Ended June 30,						Year Ended December 31,
($ in thousands)	2024			2023			2023			2022
Net Income Reconciliation to Adjusted EBITDA:
Net income	$	81,218		$	169,503		$	346,558		$	516,841
Interest expense, net		50,952			3,294			9,546			4,852
Depreciation, depletion, amortization and accretion		135,531			60,888			137,617			88,589
Unrealized loss (gain) on derivative instruments		33,099			(8,212	)		(48,826	)		(23,335	)
Equity-based compensation expense		3,482			1,294			3,440			7,527
Credit losses		647			—			1,746			—
Gain on sale of assets		(309	)		(1	)		(1	)		(45	)
Adjusted EBITDA	$	304,620		$	226,766		$	450,080		$	594,429
Net Income Reconciliation to Cash Available for Distribution:
Net income	$	81,218		$	169,503		$	346,558		$	516,841
Interest expense, net		50,952			3,294			9,546			4,852
Depreciation, depletion, amortization and accretion		135,531			60,888			137,617			88,589
Unrealized loss (gain) on derivative instruments		33,099			(8,212	)		(48,826	)		(23,335	)
Equity-based compensation expense		3,482			1,294			3,440			7,527
Credit losses		647			—			1,746			—

11

	Mach Natural Resources Historical
	Six Months Ended June 30,						Year Ended December 31,
($ in thousands)	2024			2023			2023			2022
Gain on sale of assets		(309	)		(1	)		(1	)		(45	)
Settlement of asset retirement obligations		(418	)		(79	)		(537	)		(49	)
Cash interest expense, net		(47,458	)		(3,092	)		(7,596	)		(4,477	)
Development costs		(125,987	)		(192,892	)		(302,799	)		(271,999	)
Settlement of contingent consideration		—			—			—			(13,547	)
Change in accrued realized derivative settlements		4,188			(285	)		(4,029	)		(3,413	)
Cash available for distribution	$	134,945		$	30,418		$	135,119		$	300,944
Net Cash Provided by Operating Activities Reconciliation to Cash Available for Distribution:
Net cash provided by operating activities	$	260,784		$	275,145		$	491,742		$	553,542
Changes in operating assets and liabilities		148			(51,835	)		(53,824	)		19,401
Development costs		(125,987	)		(192,892	)		(302,799	)		(271,999	)
Cash available for distribution	$	134,945		$	30,418		$	135,119		$	300,944

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 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 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 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 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.

12

Summary of Reserve, Production and Operating Data

The following tables summarize our estimated proved oil, natural gas and NGL reserves as of December 31, 2023 and our production and historical operating data for the six months ended June 30, 2024 and the year ended December 31, 2023. The information included in these tables is based on a reserve report prepared by our independent consulting petroleum engineers, Cawley, Gillespie & Associates, Inc. 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.

Reserve Data based on SEC Pricing(1)	Year Ended December 31, 2023
Proved Developed:
Oil (MBbl)		49,629
Natural gas (MMcf)		909,372
Natural gas liquids (MBbl)		69,193
Total equivalent (MBoe)		270,384
PV-10 (in millions)(2)	$	2,090
Proved Undeveloped:
Oil (MBbl)		25,944
Natural gas (MMcf)		197,102
Natural gas liquids (MBbl)		16,472
Total equivalent (MBoe)		75,266
PV-10 (in millions)(2)	$	487
Total Proved:
Oil (MBbl)		75,573
Natural gas (MMcf)		1,106,474
Natural gas liquids (MBbl)		85,665
Total equivalent (MBoe)		345,650
PV-10 (in millions)(2)	$	2,577
Standardized Measure (in millions)(2)	$	2,577

____________

(1)Our estimated net proved 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 $78.22 per barrel for oil and $2.64 per MMBtu for natural gas at December 31, 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 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.”

13

Select Production and Operating Statistics

The following table summarizes our oil, natural gas and NGL production and historical operating data for the periods presented.

	Six Months Ended June 30, 2024			Year Ended December 31, 2023
Net Production Volumes:
Oil (MBbl)		3,776			5,445
Natural gas (MMcf)		52,232			59,378
NGLs (MBbl)		3,747			3,068
Total (MBoe)		16,228			18,409
Average daily production (MBoe/d)		89.17			50.44
Average Realized Prices (excluding effects of realized derivatives):
Oil (/Bbl)	$	78.23		$	77.57
Natural gas (/Mcf)	$	1.85		$	2.52
NGLs (/Bbl)	$	25.32		$	24.52
Average Realized Prices (including effects of realized derivatives):
Oil (/Bbl)	$	76.85		$	76.51
Natural gas (/Mcf)	$	1.93		$	2.76
NGLs (/Bbl)	$	25.32		$	24.52
Operating Costs and Expenses (per Boe):
Gathering and processing expense	$	3.44		$	2.14
Lease operating expense	$	5.38		$	6.93
Production taxes expense (% of oil, natural gas and NGL sales)		4.9	%		4.9	%
Depreciation, depletion, amortization and accretion expense – oil and natural gas	$	8.08		$	7.12
Depreciation and amortization expense – other	$	0.27		$	0.35
General and administrative expense	$	1.34		$	1.50

14

RISK FACTORS

You should carefully consider the following risk factors as well as those contained in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2023 and our other SEC filings incorporated by reference in this prospectus that may affect our business, future operating results and financial condition, as well as the other information set forth or incorporated by reference in this prospectus, before making a decision to invest in our common units. If any of the following risks actually occurs, our business, financial condition or results of operations would likely be materially and adversely affected. In such case, the trading price of our common units would likely decline, and you may lose all or part of your investment. The risks below and incorporated by reference are not the only ones we face. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us.

Risks Related to the Pending Acquisitions

We may not consummate the Pending Acquisitions, and this offering is not conditioned on the consummation of the Pending Acquisitions.

This offering is not conditioned upon the consummation of the Pending Acquisitions. In addition, the consummation of the Pending Acquisitions is not conditioned upon the successful completion of this offering and neither Pending Acquisition is conditioned upon the consummation of the other Pending Acquisition. Each of the Pending Acquisitions is subject to the satisfaction or waiver of customary closing conditions, and we cannot assure you that the Pending Acquisitions will be consummated in the anticipated time frame or at all.

We have performed only a limited investigation of the properties included in the Pending Acquisitions. The completion of the Pending Acquisitions is subject to specified closing conditions and to the right of any of the parties to terminate the transactions, including in the event that adjustments to the purchase price related to title defects are required in excess of agreed upon thresholds. If one or more of the closing conditions are not satisfied with respect to either of the Pending Acquisitions, then such acquisition may not be completed. Some of these conditions are beyond our control, and we may elect not to take actions necessary to satisfy these conditions or to ensure that the transaction is not otherwise terminated.

Because this offering is not conditioned upon the consummation of the Pending Acquisitions, upon the closing of this offering, you will become a holder of our common units regardless of whether either of the Pending Acquisitions is consummated, delayed or terminated. If one or both of the Pending Acquisitions is delayed, terminated or consummated on terms different than those described herein, the market price of our common units may decline to the extent that the price of our common units reflects a market assumption that the Pending Acquisitions will be consummated on the terms described herein or at all. Accordingly, your purchase of our common units may be an investment in us on a stand-alone basis without the anticipated benefits of the Pending Acquisitions. Further, a failed transaction may result in negative publicity or a negative impression of us in the investment community and may affect our relationships with our business partners. Please read “Summary — Recent Developments — Pending Anadarko Basin Acquisitions” for more information regarding the Pending Acquisitions.

In addition, prior to the consummation of the Pending Acquisitions, we may use the net proceeds from this offering for the repayment of outstanding borrowings under our debt agreements or for other purposes. Our general partner will have broad discretion with respect to the use of these funds, and may use such funds in ways that you or other unitholders may not support, which could adversely affect the market price of our common units.

We may not be able to achieve the expected benefits of the Pending Acquisitions and our assessment and estimates of the Ardmore and Anadarko Assets may prove to be incorrect.

Even if we consummate the Pending Acquisitions, we may not be able to achieve the expected benefits of the Pending Acquisitions. There can be no assurance that the Pending Acquisitions will be beneficial to us. We may not be able to integrate the Ardmore and Anadarko Assets without increases in costs or other difficulties. Any unexpected costs or delays incurred in connection with the integration of the Pending Acquisitions could have an adverse effect on our business, results of operations, financial condition and prospects, as well as the market price of our common units.

15

Our assessment and estimates of the properties to be acquired in the Pending Acquisitions to date has been limited and may prove to be incorrect. Even by the time of closing, our assessment of these properties may not reveal all existing or potential problems. In addition, any inspection that we do may not reveal all title issues or other problems. We may be required to assume the risk that the properties may not perform in accordance with our expectations. Our ability to make specified claims against the seller generally expires over time and we may be left with no recourse for liabilities and other problems associated with the Pending Acquisitions that we do not discover prior to the expiration date related to such matters under the Purchase Agreements.

The market price of our common units may decline as a result of the Pending Acquisitions if, among other things, the integration of the properties to be acquired in the Pending Acquisitions is unsuccessful or if the properties are not successfully developed by working interest owners or if the liabilities, expenses, title and other defects, or transaction costs related to the Pending Acquisitions are greater than expected. The market price of our common units may decline if we do not achieve the perceived benefits of the Pending Acquisitions as rapidly or to the extent anticipated by us or by securities market participants or if the effect of the Pending Acquisitions on our business, results of operations or financial condition or prospects is not consistent with our expectations or those of securities market participants.

Any acquisitions we complete, including the Pending Acquisitions, are subject to substantial risks that could reduce our ability to make distributions to our common unitholders.

Even if we do make acquisitions that we believe will increase the amount of cash available for distribution to our common unitholders, these acquisitions, including the Pending Acquisitions, may nevertheless result in a decrease in the amount of cash available for distribution. Any acquisition, including the Pending Acquisitions, involves potential risks, including, among other things:

•the validity of our assumptions about estimated proved reserves, future production, drilling locations, prices, revenues, capital expenditures and production costs;

•the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

•our inability to obtain satisfactory title to the assets we acquire; and

•the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

One or more of the Pending Acquisitions may have liabilities that are not known to us, and the indemnities in the applicable Purchase Agreement may not offer adequate protection.

In connection with the Pending Acquisitions, we have agreed to assume certain liabilities. In addition, there may be liabilities that we failed or were unable to discover in the course of performing due diligence investigations into the Pending Acquisitions, or we may not have correctly assessed the significance of certain liabilities identified in the course of our due diligence. Any such liabilities, individually or in the aggregate, could have a material adverse effect on our business, financial condition and results of operations. To the extent we consummate the Pending Acquisitions, we may learn additional information as we integrate the entities and their businesses into our operations, such as unknown or contingent liabilities or issues relating to compliance with applicable laws, that could potentially have an adverse effect on our business, financial condition and results of operations.

Risks Related to This Offering and Our Common Units

The market price of our common units may be volatile, which could cause the value of your investment to decline.

The trading price of our common units could be volatile. The public offering price will be determined between us and the underwriters at the time of pricing and may be at a discount to the current market price and may vary from the market price of our common units after this offering. Some of the factors that may cause the market price of our common units to fluctuate include:

•our operating and financial performance and drilling locations, including reserve estimates;

•actual or anticipated fluctuations in our quarterly results of operations, and financial indicators, such as net income, cash flow and revenues;

16

•our failure to meet revenue, reserves or earnings estimates by research analysts or other investors;

•sales of our common units by the Company or other unitholders, or the perception that such sales may occur;

•the public reaction to our press releases, other public announcements, and filings with the SEC;

•strategic actions by our competitors or competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel;

•publication of research reports about us or the oil and natural gas exploration and production industry generally;

•changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

•speculation in the press or investment community;

•the failure of research analysts to cover our common units;

•increases in market interest rates or funding rates, which may increase our cost of capital;

•changes in market valuations of similar companies;

•changes in accounting principles, policies, guidance, interpretations or standards;

•additions or departures of key management personnel;

•actions by our unitholders;

•commencement or involvement in litigation;

•general market conditions, including fluctuations in commodity prices;

•political conditions in oil and natural gas producing regions; and

•domestic and international economic, legal and regulatory factors unrelated to our performance.

If the market for stocks in our industry, or the stock market in general, experiences a loss of investor confidence, the trading price of our common units could decline for reasons unrelated to our business, financial condition or results of operations. These and other factors may cause the market price and demand for our common units to fluctuate substantially, which may limit or prevent investors from readily selling their common units and may otherwise negatively affect the liquidity of our common units. In the past, when the market price of a security has been volatile, holders of that security have instituted securities class action litigation against the company that issued the security. If any of our unitholders brought a lawsuit against us, we could incur substantial costs defending the lawsuit. Such a lawsuit could also divert the time and attention of our management from our business.

Future sales of our common units, or the perception that such sales may occur, could depress our common unit price.

We, the Sponsor and all of our directors and executive officers have signed lock-up agreements for a period of 60 days following the date of this prospectus, in which they agreed, subject to certain exceptions, not to offer, sell, contract to sell (including any short sale), pledge, hypothecate, establish an open “put equivalent position” within the meaning of Rule 16a-1(h) under the Exchange Act grant any option, right or warrant for the sale of, purchase any option or contract to sell, sell any option or contract to purchase, or otherwise encumber, dispose of or transfer, or grant any rights with respect to, directly or indirectly, any common units or securities convertible into or exchangeable or exercisable for any common units, enter into a transaction which would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of the common units, whether any such aforementioned transaction is to be settled by delivery of the common units or such other securities, in cash or otherwise, or publicly disclose the intention to make any such offer, sale, pledge or disposition, or to enter into any such transaction, swap, hedge or other arrangement.

17

The underwriters may, in their sole discretion and without notice, release all or any portion of the common units subject to such lock-up agreements. As restrictions on resale end, the market price of our common units drop significantly if the holders of these common units sell them or are perceived by the market as intending to sell them.

Moreover, certain unitholders have rights, subject to specified conditions, to require us to file registration statements covering their common units or to include their common units in registration statements that we may file for ourselves or other unitholders. Sales of these common units under any such registration statement would result in these units becoming freely tradable without restriction under the Securities Act. See “Description of the Partnership Agreement — Registration Rights.” We have also registered all common units that we may issue under our equity compensation plans, which can be freely sold in the public market upon issuance, subject to volume limitations applicable to affiliates and the lock-up agreements described in the “Underwriting and Plan of Distribution” section of this prospectus.

We will have broad discretion in the use of the net proceeds from this offering and may not use them effectively.

We currently intend to use the net proceeds from this offering in the manner described in “Use of Proceeds.” However, the Board and management will retain broad discretion in the application, and timing of the application, of the net proceeds from this offering and could spend the net proceeds in ways that do not improve our results of operations or enhance the value of our common units. As such, we may use net proceeds of this offering in ways that an investor may not consider desirable, if the Board and management believe such use would be in our best interest. As a result, investors will be relying on the judgment of the Board and management for the application of the net proceeds from this offering. There can be no assurance regarding the results and the effectiveness of our use of the net proceeds from this offering. Our failure to apply these funds effectively could result in financial losses that could harm our business, cause the market price of our common units to decline and delay the development of our operations. Pending their use, we may invest the net proceeds from this offering in a manner that does not produce income or that loses value.

18

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus 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, 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 prospectus 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 prospectus, 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 prospectus. All forward-looking statements speak only as of the date of this prospectus.

Forward-looking statements may include statements about:

•our business strategy;

•our estimated proved reserves;

•our ability to distribute cash available for distribution and achieve or maintain certain financial and operational metrics;

•our drilling prospects, inventories, projects and programs;

•general economic conditions;

•actions taken by the Organization of the Petroleum Exporting Countries and its allies as it pertains to the global supply and demand of, and prices for, oil, natural gas and NGLs;

•our ability to replace the reserves we produce through drilling and property acquisitions;

•our financial strategy, leverage, liquidity and capital required for our development program;

•our pending legal or environmental matters;

•our realized oil and natural gas prices;

•the timing and amount of our future production of natural gas;

•our hedging strategy and results;

•our competition and government regulations;

•our ability to obtain permits and governmental approvals;

•our marketing of natural gas;

•our leasehold or business acquisitions;

•our costs of developing our properties;

•credit markets;

•our decline rates of our oil and natural gas properties;

•uncertainty regarding our future operating results;

•our intention to use the proceeds from the offering in the manner as set forth herein; and

•our plans, objectives, expectations and intentions contained in this prospectus that are not historical.

19

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil, natural gas and NGLs. We disclose important factors that could cause our actual results to differ materially from our expectations as described under “Risk Factors” included in Part I, Item 1A in our Annual Report for the year ended December 31, 2023. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statement include:

•commodity price volatility;

•the impact of epidemics, outbreaks or other public health events, and the related effects on financial markets, worldwide economic activity and our operations;

•uncertainties about our estimated oil, natural gas and NGL reserves, including the impact of commodity price declines on the economic producibility of such reserves, and in projecting future rates of production;

•the concentration of our operations in the Anadarko Basin;

•difficult and adverse conditions in the domestic and global capital and credit markets;

•lack of transportation and storage capacity as a result of oversupply, government regulations or other factors;

•lack of availability of drilling and production equipment and services;

•potential financial losses or earnings reductions resulting from our commodity price risk management program or any inability to manage our commodity risks;

•failure to realize expected value creation from property acquisitions and trades;

•access to capital and the timing of development expenditures;

•environmental, weather, drilling and other operating risks;

•regulatory changes, including potential shut-ins or production curtailments mandated by the Railroad Commission of Texas, the Oklahoma Corporation Commission, and/or the Kansas Corporation Commission;

•competition in the oil and natural gas industry;

•loss of production and leasehold rights due to mechanical failure or depletion of wells and our inability to re-establish their production;

•our ability to service our indebtedness;

•any downgrades in our credit ratings that could negatively impact our cost of and ability to access capital;

•cost inflation;

•political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, the war in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage;

•evolving cybersecurity risks such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or other with authorized access, cyber or phishing-attacks, ransomware, social engineering, physical breaches or other actions; and

•risks related to our ability to expand our business, including through the recruitment and retention of qualified personnel.

20

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 prospectus 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 prospectus.

21

USE OF PROCEEDS

We estimate that the net proceeds to us from this offering will be approximately $141.4million (or approximately $162.8million if the underwriters exercise in full their option to purchase additional common units), based on an assumed public offering price of $19.10 per common unit, which was the last reported sale price of our common units on the NYSE on September3, 2024, and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us. We intend to use the net proceeds of this offering to fund the Pending Acquisitions and for general partnership purposes, which may include future acquisitions.

A $1.00 increase (decrease) in the assumed public offering price would increase (decrease) the net proceeds to us from this offering by approximately $7.5million, assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us. A 1,000,000 common unit increase (decrease) in the number of common units offered by us would increase (decrease) the net proceeds to us from this offering by approximately $18.1million, assuming the assumed public offering price remains the same and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us.

22

CAPITALIZATION

The following table shows:

•our historical capitalization as of June30, 2024 on an actual basis; and

•on an as adjusted basis to give effect to our sale of 7,853,403common units in this offering, after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us.

This table should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2024 and our consolidated financial statements and related notes incorporated by reference in this prospectus.

	As of June 30, 2024
	Actual		As Adjusted(1)
	(in thousands)
Cash and cash equivalents	$	144,621	$	286,029
Long-term debt:
Term loan(2)		804,400		804,400
Revolving credit agreement(3)		—		—
Partner’s capital:
Partner’s capital		1,113,110		1,254,518
Total capitalization	$	1,917,510	$	2,058,918

____________

(1)Does not reflect the intended use of proceeds for the Ardmore Basin Acquisition for approximately $98.0 million in cash or the Western Kansas Acquisition for approximately $38 million in cash.

(2)As of August 28, 2024, we had approximately $804.4 million of outstanding borrowings under our Term Loan Credit Agreement.

(3)As of August 28, 2024, we had no outstanding borrowings under our Revolving Credit Agreement.

23

MANAGEMENT

The following table sets forth certain information regarding the current executive officers and directors of our general partner upon consummation of this offering.

Name	Age	Position
Tom L. Ward	65	Chief Executive Officer and Director
Kevin R. White	67	Chief Financial Officer
Michael E. Reel	38	General Counsel and Secretary
William McMullen	39	Chairman of the Board
Edgar R. Giesinger	67	Director
Stephen Perich	44	Director
Francis A. Keating II	80	Director

Tom L. Ward — Chief Executive Officer and Director.Mr. Ward has served as our Chief Executive Officer since our founding in 2017 and as a Director since the IPO. Prior to joining the Company, he served as Chairman and Chief Executive Officer of Tapstone Energy from 2013 to 2017 and Sandridge Energy (NYSE: SD) from 2006 to 2013. Prior to joining SandRidge Energy, he served as President, Chief Operating Officer and a director of Chesapeake Energy Corporation (NYSE: CHK) from the time he co-founded the company in 1989 until February 2006. Mr. Ward graduated from the University of Oklahoma in 1981 with a Bachelor of Business Administration in Petroleum Land Management.

We believe that Mr. Ward’s extensive industry background, his previous experience as a director and executive of public companies, and deep knowledge of our business as founder make him well suited to serve as a member of the Board.

Kevin R. White — Chief Financial Officer.Mr. White has served as our Chief Financial Officer since March 2017. Prior to joining the Company, he served as Chief Financial Officer of Petroflow Energy Corporation from June 2016 to March 2017 and as SVP — Business Development and Investor Relations of SandRidge Energy from January 2008 to September 2013. Mr. White served as Executive Vice President of Corporate Development and Strategic Planning for Louis Dreyfus Natural Gas Corp. from 1993 until the company was sold in 2001. He attended Oklahoma State University, receiving his Bachelor of Science degree in Accounting in 1979 and a Master of Science degree in Accounting and his Certified Public Accountant qualification in 1980.

Michael E. Reel — General Counsel and Secretary.Mr. Reel joined the Company in July 2017 and currently serves as General Counsel and Secretary. Prior to joining the Company, he served as Senior Counsel for Accelerate Resources. Prior to his time at Accelerate Resources, Mr. Reel served as internal counsel for White Star Petroleum, LLC, American Energy Partners, LP and Chesapeake Energy Corporation. Mr. Reel graduated from Oklahoma State University in 2008 with a Bachelor of Science degree in Political Science and received his Juris Doctorate from Oklahoma City University School of Law in 2011.

William W. McMullen — Chairman of the Board.Mr. McMullen has served as Chairman of the Board since the IPO, and as Founder and Managing Partner of BCE since 2015, leading the firm’s investment strategy and capital allocation decisions. Prior to founding BCE in 2015, Mr. McMullen worked at White Deer Energy from 2012 to 2014. Previously, Mr. McMullen worked at Denham Capital Management from 2010 to 2012 and UBS Investment Bank’s Global Energy Group from 2008 to 2010. Mr. McMullen earned his AB in Economics, with Honors, from Harvard University.

We believe that Mr. McMullen’s industry experience, his previous leadership positions and finance-related roles, as well as his deep knowledge of our business, make him well suited to serve as a member of our board of directors.

Edgar R. Giesinger — Director.    Mr. Giesinger has served as a Director since the Offering. Mr. Giesinger retired as a managing partner from KPMG LLP in 2015. Since November 2015, Mr. Giesinger has served on the board of directors of Geospace Technologies Corporation (NASDAQ: GEOS), a publicly traded company primarily involved in the design and manufacture of instruments and equipment utilized in oil and gas industries. Mr. Giesinger has served on the board of directors of Solaris Oilfield Infrastructure, Inc. (NYSE: SOI), a public company involved in providing proppant management systems for oil and gas well sites, since May 2017.

24

Mr. Giesinger served on the board of directors of Newfield Exploration Company, a publicly traded crude oil and natural gas exploration and production company, from August 2017 until February 2019 when it was sold to Encana Corporation. He has 35 years of accounting and finance experience working mainly with publicly traded corporations. Over the years, he has advised a number of clients in accounting and financial matters, capital raising, international expansions and in dealings with the SEC. While working with companies in a variety of industries, his primary focus has been energy and manufacturing clients. Mr. Giesinger is a certified public accountant in the State of Texas and former chairman of the Texas TriCities Chapter of the National Association of Corporate Directors. He has lectured and led seminars on various topics dealing with financial risks, controls and financial reporting. Mr. Giesinger graduated from the University of Texas with a Bachelor of Business Administration in Accounting.

We believe that Mr. Giesinger’s extensive financial and accounting experience, including that related to the energy and manufacturing industries, qualifies him to effectively serve as a member of the Board.

Stephen Perich — Director.    Mr. Perich has served as a Director since the IPO. Mr. Perich served as the Head of Energy Investment Banking for the Americas at UBS Investment Bank from August 2018 to November 2023. As head of UBS’ energy investment banking practice, he has been a manager of a team of professionals focused on capital markets execution and mergers and acquisitions advisory services. He maintains regular strategic dialogue with management teams and boards of directors of energy companies, assisting them with capital raising and strategic growth initiatives. Since January 2024, he has served on the Board of Directors of Visuray PLC, a private technology company. He has lectured and led conferences on various topics including energy fundamentals and capital markets. Mr. Perich graduated from Georgetown University in 2001 with a Bachelor of Science degree in Finance and received a Master of Business Administration from the University of Texas at Austin in 2006.

We believe that Mr. Perich’s extensive experience in financial markets, oil and gas, capital markets and mergers and acquisitions, including that related to the energy and manufacturing industries, qualifies him to effectively serve as a member of the Board.

Francis A. Keating II — Director.    Governor Keating has served as a Director since the IPO. Governor Keating is the former Governor of the State of Oklahoma, a position in which he served from 1995 to 2003. More recently, he has served on The University of Oklahoma Board of Regents since 2017, elected to serve as Chairman in 2022. Mr. Keating has served on the board of directors of Citizens Inc. (NYSE: CIA) since 2017 and on the board of directors of BancFirst Corporation (Nasdaq: BANFP) since 2016. Previously, he was a partner at the law firm of Holland & Knight from February 2016 to December 2018. He served as President and Chief Executive Officer of the American Bankers Association from 2011 to 2016, and President and Chief Executive Officer of the American Council of Life Insurers, the trade association for the life insurance and retirement security industry, from 2003 to 2011.

Mr. Keating has held significant leadership positions in both the public and private sectors, which make him a valuable addition to our Board. In addition to serving as the Governor of Oklahoma, his impressive career included serving as assistant secretary of the Treasury and associate attorney general under President Ronald Reagan. He was later general counsel and acting deputy secretary for the Department of Housing and Urban Development (“HUD”) under President George H.W. Bush. During his tenure at the Treasury Department and HUD, he worked on significant issues affecting insurance, banking, and the financial services industries. In addition to his current public board, Gov. Keating formerly served on the board of Stewart Title Company, a wholly-owned subsidiary of Stewart Information Services Corp., a publicly held title insurance and real estate services company, from 2006 to January 2017, where he chaired the Nominations and Corporate Governance Committee. Mr. Keating graduated from Georgetown University with a Bachelor of Arts in History and received his Juris Doctorate from University of Oklahoma School of Law.

We believe that Mr. Keating’s impressive legal and public service career further strengthens our Board’s governance and oversight function and qualifies him to effectively serve as a member of the Board.

25

PRINCIPAL UNITHOLDERS

The following table sets forth information regarding beneficial ownership of our common units as of the date of this prospectus by:

•each person or group of affiliated persons known by us to beneficially own more than 5% of our common units;

•each of our general partner’s directors and named executive officers individually at any time since the beginning of the last fiscal year; and

•all of our general partner’s directors and executive officers as a group.

In computing the number of common units beneficially owned by an individual or entity and the percentage ownership of that person, common units subject to awards held by such person that are currently exercisable or will become exercisable within 60 days of the date of this prospectus are considered outstanding, although these common units are not considered outstanding for purposes of computing the percentage ownership of any other person. The ownership percentage before this offering is based on 95,039,689 common units outstanding as of the date of this prospectus. The ownership percentage after this offering assumes the sale and issuance of common units in this offering and assumes the underwriters’ do not exercise their option to purchase additional common units. Except as otherwise indicated in the footnotes below, each of the unitholders named in the table has sole voting and investment power with respect to the securities indicated as beneficially owned by such unitholder, subject to community property laws where applicable. Unless otherwise indicated in the footnotes below, the address for each of the beneficial owners is c/o Mach Natural Resources LP, 14201 Wireless Way, Suite 300, Oklahoma City, OK 73134.

Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned Before This Offering		Percentage of Common Units Beneficially Owned After This Offering
Greater than 5% Unitholders:
Investment funds managed by Bayou City Energy Management LLC(1)	68,226,633	71.8	%	66.3	%
Directors and Named Executive Officers:
Tom L. Ward(2)	13,676,353	14.4	%	13.3	%
Kevin R. White(3)	421,218	*		*
Daniel T. Reineke, Jr.(4)	—	—
Michael Reel(5)	74,228	*		*
William McMullen(1)	68,226,633	71.8	%	66.3	%
Edgar R. Giesinger(6)	7,895	*		*
Stephen Perich(6)	7,895	*		*
Frank A. Keating(6)	7,895	*		*
All directors and executive officers as a group (8 persons)	82,422,117	86.7	%	80.1	%

____________

*Represents beneficial ownership of less than 1%.

(1)Represents the common units held by BCE-Mach Aggregator LLC (“BCE-Mach Aggregator”). Investment funds managed by Bayou City Energy Management LLC controls the investment decisions of BCE-Mach Aggregator and William McMullen has management control over these investment funds and accordingly may be deemed to share beneficial ownership of the common units held by BCE-Mach Aggregator. William McMullen disclaims beneficial ownership of such common units. The principal address for each of the above referenced entities is c/o Bayou City Energy, L.P., 1201 Louisiana Street Suite 3308, Houston, TX 77002.

26

(2)Includes (i) 36,842 phantom units which will vest within 60 days of the date of this prospectus and (ii) 13,639,511 common units held through Mach Resources LLC (“Mach Resources”), over which Tom L. Ward has control, and common units held in trust through the Tom L Ward 1992 Revocable Trust, of which 4,800,000 common units are pledged as collateral to secure certain personal indebtedness of Tom L. Ward. Does not include common units owned by certain other trusts affiliated with Tom L. Ward, which are not controlled by Tom L. Ward, but for which an employee of Mach Resources serves as the trustee.

(3)Includes 22,919 phantom units which will vest within 60 days of the date of this prospectus.

(4)Mr. Reineke departed the Company effective April 19, 2024.

(5)Includes 6,103 phantom units which will vest within 60 days of the date of this prospectus.

(6)Represents phantom units which will vest within 60 days of the date of this prospectus.

27

CONFLICTS OF INTEREST AND DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (the Sponsor and Tom L. Ward) on the one hand, and us and our limited partners, on the other hand. In certain cases, directors and officers of our general partner have duties to manage our general partner at the direction of BCE-Mach Aggregator, which is controlled by the Sponsor and Tom L. Ward through his ownership of Mach Resources. At the same time, our general partner has a duty to manage us in a manner that is not adverse to the best interests of our partnership. The Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership. Pursuant to these provisions, 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 the methods of resolving conflicts of interest. Our partnership agreement also specifically limits the remedies available to limited partners for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the conflicts committee of the Board or from our unitholders. There is no requirement under our partnership agreement that our general partner seek the approval of the conflicts committee or our unitholders for the resolution of any conflict, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion; provided, however, the management services agreement (“MSA”) with Mach Resources requires our general partner to seek approval by the conflicts committee of the Board in connection with an amendment to the MSA that, in the reasonable discretion of our general partner, adversely affects our unitholders. Our general partner will make such decisions on a case-by-case basis. An independent third party is not required to evaluate the fairness of the resolution. In determining whether to refer a matter to the conflicts committee or to our unitholders for approval, our general partner will consider a variety of factors, including the nature of the conflict, the size and dollar amount involved, the identity of the parties involved and any other factors the Board deems relevant in determining whether it will seek approval from the conflicts committee or our unitholders. Whenever our general partner makes a determination to refer or not to refer any potential conflict of interest to the conflicts committee for approval or to seek or not to seek unitholder approval, our general partner is acting in its individual capacity, which means that it may act free of any duty or obligation whatsoever to us or our unitholders and will not be required to act in good faith or pursuant to any other standard or duty imposed by our partnership agreement or under applicable law, other than the implied contractual covenant of good faith and fair dealing. For a more detailed discussion of the duties applicable to our general partner, as well as the implied contractual covenant of good faith and fair dealing, please read “— Duties of Our General Partner.”

Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our limited partners if the resolution of the conflict is:

•approved by the conflicts committee, which our partnership agreement defines as “special approval”;

•approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

•determined by the Board to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•determined by the Board to be fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will

28

have the burden of overcoming such presumption. If our general partner does not seek approval from the conflicts committee or our unitholders and the Board determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement or the MSA, our general partner or the conflicts committee of the Board may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he or she is acting in a manner that is not adverse to the best interests of the partnership or that the determination to take or not to take action meets the specified standard; for example, the person may determine that a transaction is being entered into on terms no less favorable to us than those generally being provided to or available from unrelated third parties, or is “fair and reasonable” to us. In taking such action, such person may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. If that person has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement.

Conflicts of interest could arise in the situations described below, among others:

Agreements between us, on the one hand, and our general partner and its affiliates, on the other hand, are not and will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our partnership agreement generally provides that any affiliated transaction, such as an agreement, contract or arrangement between us and our general partner and its affiliates that does not receive unitholder or conflicts committee approval, must be determined by the Board to be:

•on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•“fair and reasonable” to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Our general partner’s affiliates may compete with us and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. However, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might directly compete with us. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner and its affiliates. As a result, neither our general partner nor any of its affiliates have any obligation to present business opportunities to us.

Our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest.

Our partnership agreement contains provisions that permissibly modify and reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, free of any duty or obligation whatsoever to us and our unitholders, including any duty to act in a manner not adverse to the best interests of us or our unitholders, other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners at the time our partnership agreement was entered into where the language in our partnership agreement

29

does not provide for a clear course of action. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples of decisions that our general partner may make in its individual capacity include the allocation of corporate opportunities among us and our affiliates, the exercise of its limited call right or its voting rights with respect to the units it owns, whether to exercise its registration rights, and whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to our partnership agreement.

We do not have any officers or employees and rely solely on officers and employees of our general partner and its affiliates.

Affiliates of our general partner conduct businesses and activities of their own in which we have no economic interest. There could be material competition for the time and effort of the officers and employees who provide services to our general partner.

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties and limits our general partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law.

Our partnership agreement:

•permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and our general partner has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

•provides that our general partner shall not have any liability to us or our limited partners for decisions made in its capacity so long as such decisions are made in good faith;

•generally provides that in a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our public common unitholders or the conflicts committee and the Board determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest is either on terms no less favorable to us than those generally being provided to or available from unrelated third parties or is “fair and reasonable” to us, considering the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us, then it will be presumed that in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

•provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers or directors, as the cases may be, acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

By purchasing a common unit, a common unitholder will be deemed to have agreed to become bound by the provisions in our partnership agreement, including the provisions discussed above.

30

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

•the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into or exchangeable for equity interests of the partnership, and the incurring of any other obligations;

•the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

•the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets or the merger or other combination of us with or into another person;

•the negotiation, execution and performance of any contracts, conveyances or other instruments;

•the distribution of cash held by the partnership;

•the selection and dismissal of employees and agents, attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

•the maintenance of insurance for our benefit and the benefit of our partners and indemnitees;

•the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other entities;

•the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

•the indemnification of any person against liabilities and contingencies to the extent permitted by law;

•the purchase, sale or other acquisition or disposition of our equity interests, or the issuance of additional options, rights, warrants and appreciation rights relating to our equity interests; and

•the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Please read “Description of the Partnership Agreement” for information regarding the voting rights of unitholders.

We will reimburse our general partner and its affiliates for expenses.

Pursuant to our partnership agreement, we will reimburse our general partner and its affiliates for costs and expenses they incur and payments they make on our behalf. Our partnership agreement provides that our general partner will determine such other expenses that are allocable to us, and our partnership agreement does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. Such reimbursements will be made prior to making any distributions on our common units. Please read “Description of the Partnership Agreement — Reimbursement of Expenses.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party to such agreements has recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement permits our general partner to limit its or our liability, even if we could have obtained terms that are more favorable without the limitation on liability.

31

Common units are subject to our general partner’s limited call right.

Our general partner may exercise its right to call and purchase common units as provided in our partnership agreement or assign this right to one of its affiliates or to us free of any liability or obligation to us or our partners. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “Description of the Partnership Agreement — Limited Call Right.”

Limited partners have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the limited partners, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Duties of our General Partner

The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership, provided that partnership agreements may not eliminate the implied contractual covenant of good faith and fair dealing. This implied contractual covenant is a judicial doctrine utilized by Delaware courts in connection with interpreting ambiguities in partnership agreements and other contracts and does not form the basis of any separate or independent fiduciary duty in addition to the express contractual duties set forth in our partnership agreement. Under the implied contractual covenant of good faith and fair dealing, a court will enforce the reasonable expectations of the partners at the time the partnership agreement was entered into where the language in our partnership agreement does not provide for a clear course of action.

As permitted by the Delaware Act, 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 the methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited or restricted by state-law fiduciary standards and to take into account the interests of other parties in addition to or in lieu of our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the Board has duties to manage our general partner at the direction of BCE-Mach Aggregator, which is controlled by the Sponsor and Tom L. Ward through his ownership of Mach Resources. Without these provisions, our general partner’s ability to make decisions involving conflicts of interest would be restricted. These provisions enable our general partner to take into consideration the interests of all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions disadvantage the limited partners because they restrict the remedies available to limited partners for actions that, without those provisions, might constitute breaches of fiduciary duty, as described below and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of:

•the fiduciary duties imposed on general partners of a limited partnership by Delaware law in the absence of partnership agreement provisions to the contrary;

•the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties referenced in the preceding bullet that would otherwise be imposed by Delaware law on our general partner; and

•certain rights and remedies of our limited partners contained in our partnership agreement and the Delaware Act.

32

Delaware law fiduciary duty standards	Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner of a Delaware limited partnership to use that amount of care that an ordinarily careful and prudent person would use in similar circumstances and to consider all material information reasonably available in making business decisions. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present unless such transaction were entirely fair to the partnership. Our partnership agreement modifies these standards as described below.
Partnership agreement modified standards	Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it subjectively believed that the decision was not adverse to our best interests, and our general partner will not be subject to any other standard under our partnership agreement or applicable law, other than the implied contractual covenant of good faith and fair dealing. If our general partner has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement. In taking such action, our general partner may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation whatsoever to us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. These standards reduce the obligations to which our general partner would otherwise be held under applicable Delaware law.
	Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the public common unitholders or the conflicts committee of the Board must be determined by the Board to be: •on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or •“fair and reasonable” to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

33

If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. If our general partner does not seek approval from the public common unitholders or the conflicts committee and the Board determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held. In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or, our limited partners for losses sustained or liabilities incurred as a result of any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such person acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

Rights and remedies of limited partners

The Delaware Act favors the principles of freedom of contract and enforceability of partnership agreements and allows our partnership agreement to contain terms governing the rights of our unitholders. The rights of our unitholders, including voting and approval rights and the ability of the partnership to issue additional units, are governed by the terms of our partnership agreement. Please read “The Partnership Agreement.” As to remedies of unitholders, the Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has wrongfully refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties, if any, or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

By purchasing our common units, each common unitholder will be deemed to have agreed to be bound by the provisions in our partnership agreement, including the provisions discussed above. Please read “Description of Common Units — Transfer Agent and Registrar — Transfer of Common Units.” This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign our partnership agreement does not render our partnership agreement unenforceable against that person.

34

Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or these persons acted in bad faith or engaged in intentional fraud or willful misconduct. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was criminal. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the U.S. federal securities laws, in the opinion of the SEC such indemnification is contrary to public policy and therefore unenforceable. Please read “Description of the Partnership Agreement — Indemnification.”

35

DESCRIPTION OF COMMON UNITS

The Units

The common units represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units in and to partnership distributions, please read this section and “Cash Distribution Policy.” For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read “Description of the Partnership Agreement.”

Transfer Agent and Registrar

Duties

Equiniti Trust Company, LLC, a New York limited liability trust company, serves as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by our unitholders:

•surety bond premiums to replace lost or stolen certificates or to cover taxes and other governmental charges;

•special charges for services requested by a common unitholder; and

•other similar fees or charges.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of their actions for their activities in that capacity, except for any liability due to any gross negligence or willful misconduct of the indemnitee.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

•represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

•automatically agrees to be bound by the terms and conditions of our partnership agreement; and

•gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status and/or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (ii) who fails to comply with the procedures established to obtain such proof.

36

The redemption price in the case of such a redemption will be the average of the daily closing prices per common unit for the 20 consecutive trading days immediately prior to the date set for redemption.

In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units. Our general partner will cause any transfers to be recorded on our books and records from time to time (or shall cause the transfer agent to do so, as applicable).

The transferor of common units will have a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor will not have a duty to insure the execution of the transfer application and certification by the transferee and will have no liability or responsibility if the transferee neglects or chooses not to execute and forward the transfer application and certification to the transfer agent.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing transfers of securities.

37

CASH DISTRIBUTION POLICY

General

Our partnership agreement requires us to distribute all of our available cash each quarter. Our cash distribution policy reflects a basic judgment that our unitholders generally will be better served by us distributing our available cash, after costs, expenses and reserves, rather than retaining it. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions from our available cash in the aforementioned or any other amount, and our general partner has considerable discretion to determine the amount of cash available for distribution each quarter.

Because our policy will be to distribute all available cash we generate each quarter, without reserving cash for future distributions or borrowing to pay distributions during periods of low revenue, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. Our quarterly cash distributions from our available cash, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in the performance of our operators and revenue caused by fluctuations in the prices of oil and natural gas. Such variations may be significant.

Definition of Available Cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

less, the amount of cash reserves established by our general partner to:

•provide for the proper conduct of our business, which will include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;

•comply with applicable law, any of our debt instruments or other agreements; or

•provide funds for distributions to our unitholders for any one or more of the next four quarters;

plus, all cash and cash equivalents on hand on the date of determination resulting from dividends or distributions received after the end of the quarter from equity interests in any person other than a subsidiary in respect of operations conducted by such person during the quarter;

plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination resulting from working capital borrowings made after the end of the quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than additional working capital borrowings.

Methods of Distribution

We distribute available cash to our unitholders, pro rata. Our partnership agreement permits, but does not require, us to borrow funds to make distributions to our unitholders. Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter.

General Partner Interest

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future acquire common units or other equity interests in us and will be entitled to receive distributions on any such interests.

38

Distributions of Cash Upon Liquidation

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment (or establishing a reserve for payment) of our creditors. We will distribute any remaining proceeds to our unitholders, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

39

DESCRIPTION OF THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of the Amended and Restated Agreement of Limited Partnership of Mach Natural Resources LP, dated as of October 27, 2023 (the “partnership agreement”), as amended on June 13, 2024. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

•with regard to distributions of available cash, please read “Cash Distribution Policy”;

•with regard to the duties of our general partner, please read “Conflicts of Interest and Duties”;

•with regard to the transfer of common units, please read “Description of Common Units — Transfer Agent and Registrar — Transfer of Common Units”; and

•with regard to allocations of taxable income, taxable loss and other matters, please read “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

Our partnership was organized under Delaware law and will have a perpetual existence unless dissolved, wound up and terminated pursuant to the terms of our partnership agreement and the Delaware Act.

Purpose

Our purpose under our partnership agreement is to engage in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law. However, our general partner may not cause us to engage, directly or indirectly, in any business activity that it determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, except as otherwise provided below under “— Election to be Treated as a Corporation.”

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the ownership, acquisition, exploitation and development of oil and natural gas properties and the ownership, acquisition and operation of related assets, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described under “— Limited Liability.”

Limited Voting Rights

The following is a summary of the unitholder vote required for each of the matters specified below. Matters that call for the approval of a “unit majority” require the approval of a majority of the outstanding common units.

Affiliates of our general partner (the Sponsor and Tom L. Ward) have the ability to control the passage of, as well as the ability to control the defeat of, any amendment which requires a unit majority by virtue of their ownership.

In voting their common units, our general partner and its affiliates (the Sponsor and Tom L. Ward) will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. The holders of a majority of the common units (including common units deemed owned by our general partner and its

40

affiliates) entitled to vote at the meeting, represented in person or by proxy shall constitute a quorum at a meeting of common unitholders, unless any such action requires approval by holders of a greater percentage of such units in which case the quorum shall be such greater percentage.

Issuance of additional partnership interests	No approval right. Please read “— Issuance of Additional Partnership Interests.”
Amendment of the partnership agreement	Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement.”
Merger of our partnership or the sale of all or substantially all of our assets	Unit majority, in certain circumstances. Please read “— Merger, Consolidation, Sale or Other Disposition of Assets.”
Dissolution of our partnership	Unit majority. Please read “— Termination and Dissolution.”
Continuation of our business upon certain events of dissolution	Unit majority. Please read “— Termination and Dissolution.”
Withdrawal of our general partner	Under most circumstances, the approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates (the Sponsor and Tom L. Ward), is required for the withdrawal of our general partner in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of Our General Partner.”
Removal of our general partner	Requires the vote of not less than 66⅔% of the outstanding common units, including units held by our general partner and its affiliates (the Sponsor and Tom L. Ward), voting as a single class. Please read “— Withdrawal or Removal of Our General Partner.”
Transfer of our general partner interest	Our general partner may transfer any or all of its general partner interest in us without a vote of our unitholders. Please read “— Transfer of General Partner Interest.”
Transfer of ownership interests in our general partner	No unitholder approval required. Please read “— Transfer of Ownership Interests in Our General Partner.”
Election to be treated as a corporation	No approval right. Please read “— Election to be Treated as a Corporation.”

Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

•arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

•brought in a derivative manner on our behalf;

•asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

41

•asserting a claim arising pursuant to any provision of the Delaware Act; or

•asserting a claim governed by the internal affairs doctrine,

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. The foregoing provision will not apply to any claims as to which the Court of Chancery determines that there is an indispensable party not subject to the jurisdiction of such court, which is rested in the exclusive jurisdiction of a court or forum other than such court (including claims arising under the Exchange Act), or for which such court does not have subject matter jurisdiction, or to any claims arising under the Securities Act and, unless we consent in writing to the selection of an alternative forum, the United States federal district courts will be the sole and exclusive forum for resolving any action asserting a claim arising under the Securities Act. Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules or regulations thereunder. Accordingly, both state and federal courts have jurisdiction to entertain such Securities Act claims. To prevent having to litigate claims in multiple jurisdictions and the threat of inconsistent or contrary rulings by different courts, among other considerations, the partnership agreement provides that, unless we consent in writing to the selection of an alternative forum, United States federal district courts shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act. There is uncertainty as to whether a court would enforce the forum provision with respect to claims under the federal securities laws. If a court were to find these provisions of our amended and restated agreement of limited partnership inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Our partnership agreement also provides that each limited partner waives the right to trial by jury in any such claim, suit, action or proceeding, including any claim under the U.S. federal securities laws, to the fullest extent permitted by applicable law. If a lawsuit is brought against us under our partnership agreement, it may be heard only by a judge or justice of the applicable trial court, which would be conducted according to different civil procedures and may result in different outcomes than a trial by jury would have, including results that could be less favorable to the plaintiffs in any such action. No unitholder can waive compliance with respect to the U.S. federal securities laws and the rules and regulations promulgated thereunder. If the partnership or one of the partnership unitholders opposed a jury trial demand based on the waiver, the applicable court would determine whether the waiver was enforceable based on the facts and circumstances of that case in accordance with applicable state and federal laws. To our knowledge, the enforceability of a contractual pre-dispute jury trial waiver in connection with claims arising under the U.S. federal securities laws has not been finally adjudicated by the United States Supreme Court. However, we believe that a contractual pre-dispute jury trial waiver provision is generally enforceable, including under the laws of the State of Delaware, which govern our partnership agreement.

By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other courts in Delaware) in connection with any such claims, suits, actions or proceedings.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he or she otherwise acts in conformity with the provisions of our partnership agreement, his or her liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he or she is obligated to contribute to us for his or her common units plus his or her share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by our limited partners as a group:

•to remove or replace our general partner;

•to approve some amendments to the partnership agreement; or

•to take other action under the partnership agreement;

42

constituted “participation in the control” of our business for the purposes of the Delaware Act, then our limited partners could be held personally liable for our obligations under Delaware law, to the same extent as our general partner. This liability would extend to persons who transact business with us and reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our operating subsidiaries conduct business in Oklahoma, Kansas and Texas, and we may have operating subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as an owner of our operating subsidiary may require compliance with legal requirements in the jurisdictions in which our operating subsidiary conducts business, including qualifying our operating subsidiary to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership in our subsidiaries or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by our limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then our limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of our limited partners.

Issuance of Additional Partnership Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of our unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting or other rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to our common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain

43

the aggregate percentage interest in us of our general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership interests.

Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. To adopt a proposed amendment, other than the amendments discussed below under “— Opinion of Counsel and Unitholder Approval,” our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

•enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

•enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole and absolute discretion.

The provisions of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates (the Sponsor and Tom L. Ward)).

No Limited Partner Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

•a change in our name, the location of our principal place of business, our registered agent or our registered office;

•the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

•a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for U.S. federal income tax purposes, except as otherwise provided below under “— Election to be Treated as a Corporation”;

•a change in our fiscal year or taxable year and related changes;

•an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or the directors, officers, agents or trustees of our general partner from being subjected, in any manner, to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, whether or not substantially similar to plan asset regulations currently applied or proposed by the U.S. Department of Labor;

44

•an amendment that sets forth the designations, preferences, rights, powers and duties of any class or series of additional partnership securities or rights to acquire partnership securities, that our general partner determines to be necessary or appropriate or advisable for the authorization or issuance of additional partnership securities or rights to acquire partnership securities;

•any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

•an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our partnership agreement;

•any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership, limited liability company, joint venture or other entity, as otherwise permitted by our partnership agreement;

•any amendment necessary to require our limited partners to provide a statement, certification or other evidence to us regarding whether such limited partner is subject to U.S. federal income taxation on the income generated by us and to provide for the ability of our general partner to redeem the units of any limited partner who fails to provide such statement, certification or other evidence;

•an amendment that our general partner determines to be necessary or appropriate or advisable in connection with conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

•any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

•do not adversely affect our limited partners (or any particular class of limited partners) in any material respect;

•are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

•are necessary or appropriate to facilitate the trading of our units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which our units are or will be listed for trading;

•are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

•are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will not affect the limited liability of any limited partner under Delaware law. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding common units unless we first obtain such an opinion.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the holders of the type or class of units so affected, but no vote will be required by the holders of any class or classes or type or types of units that our general partner determines are not adversely affected in any material respect. Any amendment that reduces the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

45

Any amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased.

Merger, Consolidation, Sale or Other Disposition of Assets

A merger, consolidation, or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation, or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interest of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us, among other things, to sell, exchange or otherwise dispose of all or substantially all of our and our subsidiaries’ assets in a single transaction or a series of related transactions, including by way of merger, consolidation, conversion or other combination or sale of ownership interests of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger, consolidation or conversion without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction will not result in an amendment to our partnership agreement (other than an amendment that the general partner could adopt without the consent of the other partners), each of our units will be an identical unit of our partnership following the transaction, and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide our limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger, consolidation or conversion, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until dissolved and terminated under our partnership agreement. We will dissolve upon:

•the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner, other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or a withdrawal or removal followed by approval and admission of a successor;

•the election of our general partner to dissolve us, if approved by the holders of a unit majority;

•the entry of a decree of judicial dissolution of our partnership pursuant to the provisions of the Delaware Act; or

•there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law.

46

Upon a dissolution under the first bullet above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of a unit majority, subject to our receipt of an opinion of counsel to the effect that:

•the action would not result in the loss of limited liability under Delaware law of any limited partner; and

•neither our partnership nor our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Cash Distribution Policy.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2033 without obtaining the approval of the holders of at least a majority of our outstanding common units, excluding common units held by our general partner and its affiliates (the Sponsor and Tom L. Ward), and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2033, our general partner may withdraw as our general partner without first obtaining approval of any unitholder by giving at least 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw as our general partner without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates (the Sponsor and Tom L. Ward). In addition, our partnership agreement permits our general partner to sell or otherwise transfer all of its general partner interest in us without the approval of our unitholders. Please read “— Transfer of General Partner Interest.”

Upon voluntary withdrawal of our general partner by giving notice to the other partners, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated. Please read “— Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66⅔% of our outstanding units, voting together as a single class, including units held by our general partner and its affiliates (the Sponsor and Tom L. Ward), and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of our outstanding common units. The ownership of more than 33⅓% of our outstanding units by our general partner and its affiliates (the Sponsor and Tom L. Ward) would give them the practical ability to prevent our general partner’s removal.

In the event of removal of our general partner or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and its affiliate and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and its affiliate and the successor general partner will determine the fair market value. If the departing general partner and its affiliate and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

47

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Our general partner may transfer all or any of its general partner interest to an affiliate or a third party without the approval of our unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates (the Sponsor and Tom L. Ward) may at any time transfer common units to one or more persons without unitholder approval.

Transfer of Ownership Interests in Our General Partner

At any time, the members of our general partner may sell or transfer all or part of their membership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Election to be Treated as a Corporation

If at any time our general partner determines that (i) we should no longer be characterized as a partnership but instead as an entity taxed as a corporation for U.S. federal income tax purposes or (ii) common units held by some or all unitholders should be converted into or exchanged for interests in a newly formed entity taxed as a corporation for U.S. federal income tax purposes whose sole asset is interests in us (a “parent corporation”), then our general partner may, without unitholder approval, reorganize us and cause us to be treated as an entity taxable as a corporation for U.S. federal income tax purposes or cause us to engage in a merger or other transaction pursuant to which common units held by some or all unitholders will be converted into or exchanged for interests in the parent corporation. In addition, if our general partner causes partnership interests in us to be held by a parent corporation, our Existing Owners may choose to retain their partnership interests in us rather than convert or exchange their partnership interests into parent corporation shares. The general partner may take any of the foregoing actions if it in good faith determines (meaning it subjectively believes) that such action is not adverse to our best interests. Any such event may be taxable or nontaxable to our unitholders, depending on the form of the transaction. The tax liability, if any, of a unitholder as a result of such an event may vary depending on the unitholder’s particular situation and may vary from the tax liability of each of our Existing Owners. Our general partner will have no duty or obligation to make any such determination or take any such actions, however, and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in a manner not adverse to the best interests of us or our limited partners.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change the management of our general partner. If any person or group other than our general partner and its affiliates (the Sponsor and Tom L. Ward) acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the Board.

48

Limited Call Right

If at any time our general partner and its affiliates (the Sponsor and Tom L. Ward) own more than 95% of our then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:

•the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

•the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have its limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The federal income tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of its common units in the market. Please read “Material U.S. Federal Income Tax Consequences — Disposition of Common Units.”

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of common units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take such action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, entitled to vote at the meeting represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Partnership Interests.” However, if at any time any person or group, other than our general partner and its affiliates (the Sponsor and Tom L. Ward) or a direct or subsequently approved transferee of our general partner or its affiliates or a transferee of that person or group approved by our general partner or a person or group specifically approved by our general partner or the Board, as applicable, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held by a nominee or in a street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent or an exchange agent.

49

Status as Limited Partner

By transfer of any common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Unitholders; Redemption

We may acquire interests in oil and natural gas leases on United States federal lands in the future. To comply with certain U.S. laws relating to the ownership of interests in oil and natural gas leases on federal lands, our general partner, acting on our behalf, may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status and/or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (ii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption. Further, the units held by such unitholder will not be entitled to any voting rights and may not receive distributions in-kind upon our liquidation.

Furthermore, we have the right to redeem all of the common units of any holder that our general partner concludes is not an eligible holder pursuant to our partnership agreement or fails to furnish the information requested by our general partner. The redemption price in the event of such redemption for each unit held by such unitholder will be the current market price of such unit (the date of determination of which shall be the date fixed for redemption). The redemption price will be paid, as determined by our general partner, in cash or by delivery of a promissory note. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof.

Indemnification

Under our partnership agreement, unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such person acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

•our general partner;

•any departing general partner;

•any person who is or was an affiliate of our general partner or any departing general partner;

•any person who is or was a director, officer, manager, managing member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

•any person who is or was serving as a director, officer, manager, managing member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

•any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance covering liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

50

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation, and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us. The expenses for which we are required to reimburse our general partner are not subject to any caps or other limits.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For financial reporting and tax purposes, our fiscal year is the calendar year.

We will mail or make available to record holders of common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent registered public accounting firm. Except for our fourth quarter, we will also mail or make available a report containing unaudited financial statements within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on the cooperation of our unitholders in supplying us with specific information. Every unitholder will receive information to assist it in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether such unitholder supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, obtain:

•a current list of the name and last known address of each record holder;

•copies of our partnership agreement and our certificate of limited partnership and related amendments thereto; and

•certain information regarding the status of our business and financial condition.

Our general partner may, and intends to, keep confidential from the limited partners, trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the right to information that a limited partner would otherwise have under Delaware law.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner.

51

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

This section is a summary of certain material U.S. federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Kirkland & Ellis LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the U.S. Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed U.S. Treasury regulations promulgated under the Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Mach Natural Resources and our operating subsidiaries.

This discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to other categories of unitholders, such as corporations (or entities treated as corporations for U.S. federal income tax purposes), partnerships (or entities treated as partnerships for U.S. federal income tax purposes), trusts and estates. This discussion does not address all tax considerations that may be relevant to a particular unitholder in light of the unitholder’s circumstances. Moreover, this discussion does not address, or addresses only to a limited extent, the tax considerations that may be applicable to certain categories of unitholders that may be subject to special tax treatment under U.S. federal income tax laws, such as:

•U.S. expatriates and former citizens or long-term residents of the United States;

•banks, insurance companies and other financial institutions;

•tax-exempt institutions and IRAs;

•foreign persons (including controlled foreign corporations, passive foreign investment companies and foreign persons eligible for the benefits of an applicable income tax treaty with the United States);

•real estate investment trusts;

•mutual funds;

•dealers or traders in securities or currencies;

•U.S. persons whose “functional currency” is not the U.S. dollar;

•persons holding their units as part of a straddle, hedge, conversion, constructive sale or other integrated transaction; and

•persons subject to special tax accounting rules as a result of any item of gross income with respect to our common units being taken into account in an applicable financial statement.

In addition, this discussion does not comment on all U.S. federal income tax matters affecting us or our unitholders, such as the application of the alternative minimum tax, and only comments to a limited extent on state, local and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult his own tax advisor in analyzing the U.S. federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units and potential changes in applicable laws.

No ruling has been requested from the IRS regarding our characterization as a partnership for tax purposes. Instead, we will rely on opinions of Kirkland & Ellis LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our common units, including the prices at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

52

Unless otherwise noted, all statements as to matters of U.S. federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section are the opinion of Kirkland & Ellis LLP and are based on the accuracy of the representations made by us. Notwithstanding the foregoing, and for the reasons described below, Kirkland & Ellis LLP has not rendered an opinion with respect to the following specific U.S. federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (ii) whether all aspects of our method for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); (iii) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Uniformity of Units”); and (iv) whether percentage depletion will be available to a unitholder or the extent of the percentage depletion deduction (please read “— Tax Treatment of Operations — Depletion Deductions”).

Partnership Status

A partnership is not a taxable entity and generally incurs no U.S. federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his U.S. federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, refining, transportation and marketing of certain minerals and natural resources, including crude oil, natural gas and certain products thereof, certain related hedging activities, certain activities that are intrinsic to other qualifying activities, and our allocable share of our subsidiaries’ income from these sources. Other types of qualifying income include interest (other than from a financial business), dividends, real property rents, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 3% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, Kirkland & Ellis LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income.

The IRS has made no determination as to our status or the status of our operating subsidiaries for U.S. federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Code. Instead, we will rely on the opinion of Kirkland & Ellis LLP on such matters. It is the opinion of Kirkland & Ellis LLP that, based upon the Code, the Treasury Regulations, published revenue rulings and court decisions and the representations described below that:

•We will be classified as a partnership for U.S. federal income tax purposes; and

•Each of our operating subsidiaries will be treated as a partnership or will be disregarded as an entity separate from us for U.S. federal income tax purposes.

In rendering its opinion, Kirkland & Ellis LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Kirkland & Ellis LLP has relied include:

•Neither we nor any of our operating subsidiaries has elected or will elect to be treated as a corporation for U.S. federal income tax purposes;

•For each taxable year, more than 90% of our gross income has been and will be income of the type that Kirkland & Ellis LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Code; and

53

•Each commodity hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to the applicable Treasury Regulations, and has been and will be associated with oil, gas or products thereof that are held or to be held by us in activities of a type that Kirkland & Ellis LLP has opined or will opine result in qualifying income.

We believe that these representations have been true in the past, are true as of the date hereof and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for U.S. federal income tax purposes.

In addition, our general partner may, without unitholder approval, reorganize us and cause us to be treated as an entity taxable as a corporation for U.S. federal income tax purposes or cause us to enter into a transaction in which common units held by some or all unitholders will be converted into or exchanged for interests in a newly formed entity taxed as a corporation for U.S. federal income tax purposes whose sole asset is interests in us. Any such event may be taxable or nontaxable to our unitholders, depending on the form of the transaction. Please read “Description of the Partnership Agreement — Election to be Treated as a Corporation.”

If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder generally would be treated as (i) taxable dividend income, to the extent of our current and accumulated earnings and profits, (ii) then as a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, and (iii) then as taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the common units.

The discussion below is based on Kirkland & Ellis LLP’s opinion that we will be classified as a partnership for U.S. federal income tax purposes.

Limited Partner Status

Unitholders of Mach Natural Resources will be treated as partners of Mach Natural Resources for U.S. federal income tax purposes. In addition, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Mach Natural Resources for U.S. federal income tax purposes.

A beneficial owner of common units whose common units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those common units for U.S. federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.” Income, gains, losses or deductions would not appear to be reportable by a unitholder who is not a partner for U.S. federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for U.S. federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to the tax consequences to them of holding common units. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Mach Natural Resources for U.S. federal income tax purposes.

54

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

Subject to the discussion below under “— Entity-Level Collections,” we will not pay any U.S. federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions of cash by us to a unitholder generally will not be taxable to the unitholder for U.S. federal income tax purposes, except to the extent the amount of any such distribution exceeds his tax basis in his common units immediately before the distribution. Cash distributions in excess of a unitholder’s tax basis generally will be treated as gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our (i) “unrealized receivables,” including depreciation recapture, depletion recapture and intangible drilling costs recapture, or (ii) substantially appreciated “inventory items,” each as defined in the Code (collectively, “Section 751 Assets”). To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then as having exchanged those assets with us in return for the non-pro rata portion of the distribution (or deemed distribution) made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Basis of Common Units

A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income, by any increases in his share of our nonrecourse liabilities and, on the disposition of a common unit, by his share of certain items related to business interest not yet deductible by him due to applicable limitations. Please read “— Limitations on Interest Deductions.” That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the adjusted tax basis of the underlying properties, by any decreases in his share of our nonrecourse liabilities, by his share of our excess business interest (generally, the excess of our business interest over the amount that is deductible) and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his common units and, in the case of an individual unitholder, estate, trust or certain closely-held corporations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a

55

result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such unitholder’s tax basis in his common units. Upon the taxable disposition of a common unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his common units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his common units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the common units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The at-risk limitation applies on an activity-by-activity basis, and in the case of oil and natural gas properties, each property is treated as a separate activity. Thus, a taxpayer’s interest in each oil or natural gas property is generally required to be treated separately so that a loss from any one property would be limited to the at-risk amount for that property and not the at-risk amount for all the taxpayer’s oil and natural gas properties. It is uncertain how this rule is implemented in the case of multiple oil and natural gas properties owned by a single entity treated as a partnership for U.S. federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or natural gas properties we own in computing a unitholder’s at-risk limitation with respect to us. If a unitholder were required to compute his at-risk amount separately with respect to each oil or natural gas property we own, he might not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at-risk amount with respect to his common units as a whole.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and certain closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or the unitholder’s salary, active business or other income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation described above.

An additional loss limitation may apply to certain of our unitholders for taxable years beginning before January 1, 2029. A non-corporate unitholder will not be allowed to take a deduction for certain excess business losses in such taxable years. An excess business loss is the excess (if any) of a taxpayer’s aggregate deductions for the taxable year that are attributable to the trades or businesses of such taxpayer (determined without regard to the excess business loss limitation or any deduction allowable for net operating losses, qualified business income or capital losses) over the aggregate gross income or gain of such taxpayer for the taxable year that is attributable to such trades or businesses (subject to certain limitations in the case of capital gains) plus a threshold amount. The current threshold amount is equal to $305,000, or $610,000 for taxpayers filing a joint return. Any losses disallowed in a taxable year due to the excess business loss limitation may be used by the applicable unitholder in the following taxable year if certain conditions are met. Unitholders to which this excess business loss limitation applies will take their allocable share of our items of income, gain, loss and deduction into account in determining this limitation. This excess business loss limitation will be applied to a non-corporate unitholder after the passive loss limitations and may limit such unitholders’ ability to utilize any losses we generate allocable to such unitholder that are not otherwise limited by the basis, at-risk and passive loss limitations described above.

56

Limitations on Interest Deductions

Our ability to deduct interest paid or accrued on indebtedness properly allocable to a trade or business, “business interest”, may be limited in certain circumstances. Should our ability to deduct business interest be limited, the amount of taxable income allocated to our unitholders in the taxable year in which the limitation is in effect may increase. However, in certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years.

In addition, the deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense is interest expense on indebtedness that is properly allocable to property held for investment, which includes (i) property that produces portfolio income (for example, interest and dividends) and (ii) any interest held by the taxpayer in an activity that is not a passive activity and with respect to which the taxpayer does not materially participate. Net investment income is gross income from property held for investment, less deductible expenses (other than interest) directly connected with the production of such income. Net investment income, however, generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, a unitholder’s share of our portfolio income will be treated as investment income.

Prospective unitholders should consult their tax advisors regarding the impact of the foregoing interest deduction limitations on an investment in our common units.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of common units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the unitholders in accordance with their percentage interests in us. If we have a net loss, that loss will be allocated to the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts, as adjusted for certain items in accordance with applicable Treasury Regulations.

Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of this offering and (ii) any difference between the tax basis and fair market value of any property contributed to us that exists at the time of such contribution, together referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as “Section 704(c) Allocations,” to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. However, it may not be administratively feasible to make the relevant adjustments to “book” basis and the relevant reverse Section 704(c) Allocations each time we issue common units, particularly in the case of small or frequent common unit issuances. If that is the case, we may use simplifying conventions to make those adjustments and allocations, which may include the aggregation of certain issuances of common units. Kirkland & Ellis LLP is unable to opine as to the validity of such conventions. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving

57

rise to the recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts (subject to certain adjustments), if negative capital accounts (subject to certain adjustments) nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate such negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for U.S. federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

•his relative contributions to us;

•the interests of all the partners in profits and losses;

•the interest of all the partners in cash flow; and

•the rights of all the partners to distributions of capital upon liquidation.

Kirkland & Ellis LLP is of the opinion that, with the exception of the issues described in “— Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for U.S. federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

•any of our income, gain, loss or deduction with respect to those common units would not be reportable by the unitholder;

•any cash distributions received by the unitholder as to those common units would be fully taxable; and

•while not entirely free from doubt, all of these distributions would appear to be ordinary income.

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Kirkland & Ellis LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their common units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Tax Rates

Currently, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 20%. Such rates are subject to change by new legislation at any time.

In addition, a 3.8% Medicare tax, or NIIT, is imposed on certain net investment income earned by individuals, estates and trusts. For these purposes, net investment income generally includes both a unitholder’s allocable share of our income and a unitholder’s gain realized upon a sale of common units. In the case of an individual, the tax will

58

be imposed on the lesser of (i) the unitholder’s net investment income or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) the estate or trust’s “undistributed net investment income,” or (ii) the excess (if any) of the estate or trust’s adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins for such taxable year. Prospective unitholders are urged to consult with their tax advisors as to the impact of the NIIT on an investment in our common units.

For taxable years beginning on or before December 31, 2025, a non-corporate unitholder is entitled to a deduction equal to 20% of its “qualified business income” attributable to us, subject to certain limitations. For purposes of this deduction, a unitholder’s “qualified business income” attributable to us is equal to the sum of:

•the net amount of such unitholder’s allocable share of certain of our items of income, gain, deduction and loss (generally excluding certain items related to our investment activities, such as capital gains and dividends, which are subject to a U.S. federal income tax rate of 20%); and

•any gain recognized by such unitholder on the disposition of its common units, or the deemed disposition of its common units (as described above under “— Tax Consequences of Unit Ownership — Treatment of Distributions”), to the extent such gain is attributable to certain Section 751 assets, including depreciation recapture and “inventory items” we own.

Prospective unitholders should consult their tax advisors regarding the application of this deduction and its interaction with the overall deduction for qualified business income.

Section 754 Election

We have made the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS. The election generally permits us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets (“common basis”) and (ii) his Section 743(b) adjustment to that basis.

We have adopted or will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulations Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of common units even if that position is not consistent with these and any other Treasury Regulations. Please read “— Uniformity of Units.”

We will depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property that is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulations Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring common units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some

59

unitholders. Please read “— Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate such unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such common units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” Kirkland & Ellis LLP is unable to opine as to whether our method for taking into account Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the common units. If such a challenge were sustained, the gain from the sale of common units might be increased without the benefit of additional deductions.

Subject to certain limitations, a Section 743(b) adjustment may create additional depreciable basis that is eligible for bonus depreciation under Section 168(k) to the extent the adjustment is attributable to depreciable property and not to goodwill or real property. However, because we may not be able to determine whether transfers of our common units satisfy all of the eligibility requirements and due to other limitations regarding administrability, we may elect out of the bonus depreciation provisions of Section 168(k) with respect to basis adjustments under Section 743(b).

A Section 754 election is advantageous if the transferee’s tax basis in his common units is higher than the common units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his common units is lower than those common units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the common units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer. Generally, a built-in loss is substantial if (i) it exceeds $250,000 or (ii) the transferee would be allocated a net loss in excess of $250,000 on a hypothetical sale of our assets for their fair market value immediately after a transfer of the interests at issue. In addition, a basis adjustment is required regardless of whether a Section 754 election is made if we distribute property and have a substantial basis reduction. A substantial basis reduction exists if, on a liquidating distribution of property to a unitholder, there would be a negative basis adjustment to our assets in excess of $250,000 if a Section 754 election were in place.

The calculations involved in the Section 754 election are complex and will be made on the basis of certain assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of common units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and the accrual method of accounting for U.S. federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his common units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

60

Depletion Deductions

Subject to the limitations on deductibility of losses discussed above (please read “— Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses”), unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and natural gas interests. Although the Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for U.S. federal income tax purposes. Each unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the underlying property for depletion and other purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Code. To qualify as an “independent producer” eligible for percentage depletion (and that is not subject to the intangible drilling and development cost deduction limits, please read “— Deductions for Intangible Drilling and Development Costs”), a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of oil and natural gas products exceeding $5.0 million per year in the aggregate. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s average net daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, capital loss carrybacks, or any deduction allowable under Section 199A of the Code. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral common units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral common units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our oil and natural gas interests or the disposition by the unitholder of some or all of his common units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. Moreover, the availability of percentage depletion may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “— Recent Legislative Developments.” We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

61

Deductions for Intangible Drilling and Development Costs

We will elect to currently deduct intangible drilling and development costs (“IDCs”). IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, natural gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a non-corporate unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount in respect of those IDCs will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to oil and natural gas wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in oil or natural gas properties and also carries on substantial retailing or refining operations. An oil or natural gas producer is deemed to be a substantial retailer or refiner if it is does not qualify as an independent producer under the rules disqualifying retailers and refiners from taking percentage depletion. Please read “— Depletion Deductions.”

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

The election to currently deduct IDCs may be restricted or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “— Recent Legislative Developments.”

Lease Acquisition Costs

The cost of acquiring oil and natural gas leases or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read “— Depletion Deductions.”

Geophysical Costs

The cost of geophysical exploration incurred in connection with the exploration and development of oil and natural gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred. The amortization period for certain geological and geophysical expenditures may be extended if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “— Recent Legislative Developments.”

Operating and Administrative Costs

Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs, to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

62

Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation, depletion, amortization, accretion and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The U.S. federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by our unitholders holding interests in us prior to any such offering. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “— Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Code.

If we dispose of depreciable or depletable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation and depletion previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery, depletion or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs we incur in selling our common units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of our Properties

The U.S. federal income tax consequences of the ownership and disposition of common units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or determinations of basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of common units equal to the difference between the amount realized and the unitholder’s tax basis in the common units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of common units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in common units, on the sale or exchange of a common unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of common units held for more than twelve months will generally be taxed at the U.S. federal income tax rate applicable to long-term capital gains. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to (i) “unrealized receivables,” including potential recapture items such as depreciation, depletion,

63

amortization and accretion expenses or IDCs, or (ii) “inventory items” we own. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized upon the sale of a common unit and may be recognized even if there is a net taxable loss realized on the sale of a common unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of common units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations. Ordinary income recognized by a non-corporate unitholder on disposition of our common units may be reduced by such unitholder’s deduction for qualified business income. Both ordinary income and capital gain recognized on a sale of common units may be subject to the NIIT in certain circumstances. Please read “— Tax Consequences of Unit Ownership — Tax Rates.”

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of common units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. Unitholders considering the purchase of additional common units or a sale of common units purchased in separate transactions should consult their tax advisors as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest — that is, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value — if the taxpayer or related persons enter(s) into:

•a short sale;

•an offsetting notional principal contract; or

•a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position. Prospective unitholders should consult their tax advisors regarding the impact of these constructive sale rules in connection with an investment in our common units.

Allocations between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis in proportion to the number of days in each month and will be subsequently apportioned among our unitholders in proportion to the number of common units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among our unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring common units may be allocated income, gain, loss and deduction realized after the date of transfer.

64

The U.S. Department of Treasury and the IRS have issued Treasury Regulations that permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. Accordingly, Kirkland & Ellis LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year.

A unitholder who owns common units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter through the month of disposition but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his common units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of common units who purchases common units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Uniformity of Units

Because we cannot match transferors and transferees of common units, we must maintain uniformity of the economic and tax characteristics of the common units to a purchaser of these common units. In the absence of uniformity, we may be unable to completely comply with a number of U.S. federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulations Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the common units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

We will depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property that is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulations Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring common units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any common units that would not have a material adverse effect on the unitholders. In either case, and as stated above under “— Tax Consequences of Unit Ownership — Section 754 Election,” Kirkland & Ellis LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of common units might be affected, and the gain from the sale of common units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

65

Tax-Exempt Organizations and Other Investors

Ownership of common units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are such an investor, you should consult your own tax advisor before investing in our common units.

Employee benefit plans and most other organizations exempt from U.S. federal income tax, including IRAs and other retirement plans, are subject to U.S. federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it. Further, a tax-exempt organization with more than one unrelated trade or business (including by attribution from investments in a partnership, such as us, that is engaged in one or more unrelated trades or businesses) must compute its unrelated business taxable income separately for each such trade or business, including for purposes of determining any net operating loss deduction. As a result, it may not be possible for tax-exempt organizations to use losses from an investment in us to offset taxable income from another unrelated trade or business.

Non-resident aliens and foreign corporations, trusts or estates that own common units will be considered to be engaged in business in the United States because of the ownership of common units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay U.S. federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable marginal tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN, W-8BEN-E or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns common units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular U.S. federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that are effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that common unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Gain on the sale or disposition of a common unit will be treated as effectively connected with a U.S. trade or business to the extent that a foreign unitholder would recognize gain effectively connected with a U.S. trade or business upon the hypothetical sale of our assets at fair market value on the date of the sale or exchange of that common unit. Such gain shall be reduced by certain amounts treated as effectively connected with a U.S. trade or business attributable to certain real property interests, as set forth in the following paragraph.

Under the Foreign Investment in Real Property Tax Act, a foreign unitholder (other than certain “qualified foreign pension funds” (or an entity all of the interests of which are held by such a qualified foreign pension fund), which generally are entities or arrangements that are established and regulated by foreign law to provide retirement or other pension benefits to employees, do not have a single participant or beneficiary that is entitled to more than 5% of the assets or income of the entity or arrangement and are subject to certain preferential tax treatment under the laws of the applicable foreign country), generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future.

66

Therefore, foreign unitholders may be subject to U.S. federal income tax on gain from the sale or disposition of their common units.

Upon the sale, exchange or other disposition of a common unit by a foreign unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. The U.S. Department of the Treasury and the IRS have issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including transfers of our common units. Under these regulations, the “amount realized” on a transfer of our common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. Quarterly distributions made to our foreign unitholders may also be subject to withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. Prospective foreign unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

Additional withholding requirements may also affect certain foreign unitholders. Please read “— Administrative Matters — Additional Withholding Requirements.”

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Kirkland & Ellis LLP can assure prospective unitholders that the IRS will not successfully contend that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the common units.

A unitholder must file a statement with the IRS identifying the treatment of any item on his U.S. federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

The IRS may audit our U.S. federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners.

Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns (including any income tax returns filed by us or BCE-Mach LLC (“BCE-Mach”), BCE-Mach II LLC (“BCE-Mach II”) or BCE-Mach III (BCE-Mach III together with BCE-Mach and BCE-Mach II, the “Mach Companies”) in respect of periods beginning prior to the closing of our initial public offering in 2023), it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Similarly, if the IRS makes audit adjustments to income tax returns filed by an entity in which we are a member or a partner, it may assess and collect any taxes (including penalties and interest) resulting from such audit adjustment directly from such entity. Generally, we expect to elect to have our unitholders and former unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be made or be effective in all circumstances. If we are unable to have our unitholders and former unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability

67

resulting from such audit adjustment, even if such unitholders did not own our common units during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.

Additionally, pursuant to the Bipartisan Budget Act of 2015, we are required to designate a partner, or other person, with a substantial presence in the United States as the partnership representative (“Partnership Representative”). The Partnership Representative has the sole authority to act on our behalf for purposes of, among other situations, U.S. federal income tax audits and judicial review of administrative adjustments by the IRS. If we do not make such a designation, the IRS can select any person as the Partnership Representative. We have designated our general partner as our Partnership Representative. Further, any actions taken by us or by the Partnership Representative on our behalf with respect to, among other situations, U.S. federal income tax audits and judicial review of administrative adjustments by the IRS, will be binding on us and all of our unitholders.

Additional Withholding Requirements

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as specifically defined in the Code) and certain other foreign entities. Specifically, a 30% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States (“FDAP Income”), or, subject to the proposed Treasury Regulations discussed below, gross proceeds from the sale or other disposition of any property of a type that can produce interest or dividends from sources within the United States (“Gross Proceeds”) paid to a foreign financial institution or to a “non-financial foreign entity” (as specifically defined in the Code), unless (i) the foreign financial institution undertakes certain diligence and reporting, (ii) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (i) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other obligations, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to noncompliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these requirements may be subject to different rules.

These rules generally apply to payments of FDAP Income currently and, while these rules generally would have applied to payments of relevant Gross Proceeds made on or after January 1, 2019, proposed Treasury Regulations eliminate these withholding taxes on payments of Gross Proceeds entirely. Unitholders generally may rely on these proposed Treasury Regulations until final Treasury Regulations are issued. Thus, to the extent we have FDAP Income that is not treated as effectively connected with a U.S. trade or business (please read “— Tax-Exempt Organizations and Other Investors”), unitholders who are foreign financial institutions or certain other foreign entities, or persons that hold their common units through such foreign entities, may be subject to withholding on distributions they receive from us, or their distributive share of our income, pursuant to the rules described above.

Prospective unitholders should consult their own tax advisors regarding the potential application of these withholding provisions to their investment in our common units.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

1.the name, address and taxpayer identification number of the beneficial owner and the nominee;

2.whether the beneficial owner is:

a.a person that is not a U.S. person;

b.a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

c.a tax-exempt entity;

68

3.the amount and description of units held, acquired or transferred for the beneficial owner; and

4.specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition costs for purchases, as well as the amount of net proceeds from dispositions.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on common units they acquire, hold or transfer for their own account. A penalty of $310 per failure, up to a maximum of $3,783,500 per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the common units with the information furnished to us.

Accuracy-Related Penalties

Certain penalties may be imposed on taxpayers as a result of an underpayment of tax that is attributable to one or more specified causes, including: (i) negligence or disregard of rules or regulations, (ii) substantial understatements of income tax, (iii) substantial valuation misstatements and (iv) the disallowance of claimed tax benefits by reason of a transaction lacking economic substance or failing to meet the requirements of any similar rule of law. Except with respect to the disallowance of claimed tax benefits by reason of a transaction lacking economic substance or failing to meet the requirements of any similar rule of law, however, no penalty will be imposed for any portion of any such underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion.

With respect to substantial understatements of income tax, the amount of any understatement subject to penalty generally is reduced by that portion of the understatement which is attributable to a position adopted on the return: (A) for which there is or was “substantial authority”; or (B) as to which there is a reasonable basis and the relevant facts are adequately disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must adequately disclose the relevant facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty.

Recent Legislative Developments

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress and the President propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including the elimination of partnership tax treatment for publicly traded partnerships. For example, in recent years, the Biden administration has proposed repealing the exemption from the corporate income tax for “fossil fuel” publicly traded partnerships in its budget, which is published annually.

In recent years, legislation has been proposed that would reduce or eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. Changes in such proposals include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units.

69

Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. Please read “— Partnership Status.” We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

State, Local, Foreign and Other Tax Considerations

In addition to U.S. federal income taxes, you will likely be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We currently own property and do business in Oklahoma, Kansas and Texas. Oklahoma and Kansas each impose a personal income tax. Texas does not currently impose a personal income tax on individuals, but it does impose an entity level tax (to which we will be subject) on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of the United States, pertinent states, localities and foreign jurisdictions, of his investment in us. Accordingly, each prospective unitholder should consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Kirkland & Ellis LLP has not rendered an opinion on the state tax, local tax, alternative minimum tax or non-U.S. tax consequences of an investment in us.

70

UNDERWRITING AND PLAN OF DISTRIBUTION

Raymond James & Associates, Inc., Stifel, Nicolaus & Company, Incorporated and Truist Securities, Inc. are acting as representatives of each of the underwriters named below. Subject to the terms and conditions set forth in an underwriting agreement dated the date of this prospectus, we have agreed to sell to the underwriters, and each of the underwriters has agreed, severally and not jointly, to purchase from us, the number of our common units set forth opposite its name below.

Underwriters	Number of Common Units
Raymond James & Associates, Inc.
Stifel, Nicolaus & Company, Incorporated
Truist Securities, Inc.
Johnson Rice & Company L.L.C.
Stephens Inc.
Total	7,853,403

Subject to the terms and conditions set forth in the underwriting agreement, the underwriters have agreed, severally and not jointly, to purchase all of our common units (other than those covered by the underwriters’ option to purchase additional common units described below) sold under the underwriting agreement. If an underwriter defaults, the underwriting agreement provides that the purchase commitments of the non-defaulting underwriters may be increased or the underwriting agreement may be terminated.

We have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make in respect of those liabilities.

The underwriters are offering our common units, subject to prior sale, when, as and if issued to and accepted by them, subject to approval of legal matters by their counsel, including the validity of the common units, and other conditions contained in the underwriting agreement, such as the receipt by the underwriters of officers’ certificates and legal opinions. The underwriters reserve the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part.

Underwriting Discounts and Expenses

The representatives have advised us that the underwriters propose initially to offer our common units to the public at the public offering price set forth on the cover page of this prospectus and to dealers at that price less a concession not in excess of $per common unit. After this offering, the public offering price, concession or any other term of this offering may be changed.

The following table shows the public offering price, underwriting discount and proceeds before expenses to us. The information assumes either no exercise or full exercise by the underwriters of their option to purchase additional common units.

	Per Common Unit	Without Option	With Option
Public offering price	$	$	$
Underwriting discount	$	$	$
Proceeds, before expenses, to us	$	$	$

The estimated expenses of this offering payable by us, exclusive of the underwriting discount, are approximately $1,092,186. We will reimburse the underwriters for certain reasonable out-of-pocket expenses related to blue-sky laws and for certain reasonable out-of-pocket expenses (up to $35,000) related to the review by the Financial Industry Regulatory Authority (“FINRA”) of the terms of sale of the common units offered hereby.

71

Option

We have granted an option to the underwriters to purchase up to an aggregate of 1,178,010 additional common units at the public offering price, less the underwriting discount. The underwriters may exercise this option at any time or from time to time for 30 days from the date of this prospectus. If the underwriters exercise this option, each will be obligated, subject to conditions contained in the underwriting agreement, to purchase a number of additional common units proportionate to that underwriter’s initial amount as reflected in the above table.

No Sales of Similar Securities

The Sponsor, the directors and executive officers of our general partner have agreed with the underwriters not to offer, sell, transfer or otherwise dispose of any common units or any securities convertible into or exercisable or, exchangeable for, exercisable for, or repayable with common units, for a period of 60 days after the date of this prospectus without first obtaining the written consent of the representatives. Specifically, we and these other persons have agreed, with certain limited exceptions, not to directly or indirectly:

•offer, pledge, sell or contract to sell any common units;

•sell any option or contract to purchase any common units;

•purchase any option or contract to sell any common units;

•grant any option, right or warrant for the sale of any common units;

•lend or otherwise dispose of or transfer any common units;

•file or cause to be filed any registration statement related to the common units; or

•enter into any swap hedging, collar or other agreement that can be reasonably expected to transfer, in whole or in part, the economic consequence of ownership of any common units whether any such swap hedging, collar or other agreement is to be settled by delivery of common units or other securities, in cash or otherwise.

This lock-up provision applies to common units and to securities convertible into or exchangeable or exercisable for or repayable with common units. It also applies to common units owned now or acquired later by the person executing the agreement or for which the person executing the agreement later acquires the power of disposition.

Raymond James & Associates, Inc., Stifel, Nicolaus & Company, Incorporated and Truist Securities, Inc. may release any of the common units and other securities subject to the lock-up agreements described above in whole or in part subject to the below considerations. When determining whether or not to release common units from lock-up agreements, Raymond James & Associates, Inc., Stifel, Nicolaus & Company, Incorporated and Truist Securities, Inc. will consider, among other factors, the unitholders’ reasons for requesting the release, the number of common units for which the release is being requested and market conditions at the time. However, Raymond James & Associates, Inc., Stifel, Nicolaus & Company, Incorporated and Truist Securities, Inc. have informed us that, as of the date of this prospectus, there are no agreements between them and any party that would allow such party to transfer any common units, nor do they have any intention at this time of releasing any of the common units subject to the lock-up agreements, prior to the expiration of the lock-up period.

Price Stabilization, Short Positions and Penalty Bids

In connection with this offering, the underwriters may purchase and sell our common units in the open market. These transactions may include short sales, purchases on the open market to cover positions created by short sales and stabilizing transactions. Short sales involve the sale by the underwriters of a greater number of our common units than they are required to purchase in this offering. “Covered” short sales are sales made in an amount not greater than the underwriters’ over-allotment option to purchase additional common units described above. The underwriters may close out any covered short position by either exercising their option or purchasing common units in the open market. In determining the source of our common units to close out the covered short position, the underwriters will consider, among other things, the price of our common units available for purchase in the open market as compared to the price at which they may purchase our common units through the option. “Naked” short

72

sales are sales in excess of the over-allotment option. The underwriters must close out any naked short position by purchasing our common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of our common units in the open market after pricing that could adversely affect investors who purchase in this offering. Stabilizing transactions consist of various bids for or purchases of our common units made by the underwriters in the open market prior to the completion of this offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the underwriters have repurchased common units sold by or for the account of such underwriter in stabilizing or short covering transactions.

Similar to other purchase transactions, the underwriters’ purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of our common units. As a result, the price of our common units may be higher than the price that might otherwise exist in the open market. The underwriters may conduct these transactions on the NYSE, in the over-the-counter market or otherwise.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common units. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

Electronic Distribution

In connection with this offering, certain of the underwriters or securities dealers may distribute prospectuses by electronic means, such as e-mail. In addition, the underwriters may facilitate Internet distribution for this offering to certain of their Internet subscription customers. The underwriters may allocate a limited number of our common units for sale to their online brokerage customers. An electronic prospectus may be available on the websites maintained by the underwriters. Other than the prospectus set forth in electronic format, the information on the underwriters’ websites is not part of this prospectus.

Other Relationships

In addition, in the ordinary course of their business activities, the underwriters and their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Direct Participation Program Requirements

Because FINRA views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with FINRA Rule 2310. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

73

LEGAL MATTERS

The validity of the common units and certain tax matters will be passed upon for us by Kirkland & Ellis LLP, Houston, Texas. Certain legal matters in connection with the common units offered by us will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The audited consolidated financial statements of Mach Natural Resources LP incorporated by reference in this prospectus and elsewhere in the registration statement have been so incorporated by reference in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The audited condensed financial statements of Paloma Partners IV Holdings, LLC as of and for the year ended December 31, 2022 and 2021, have been incorporated by reference herein in reliance upon the report of EEPB Company, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The audited financial statements of BCE-Mach LLC incorporated by reference in this prospectus and elsewhere in the registration statement have been so incorporated by reference in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The audited financial statements of BCE-Mach II LLC incorporated by reference in this prospectus and elsewhere in the registration statement have been so incorporated by reference in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

Estimated quantities of proved oil and natural gas reserves of the Mach Natural Resources LP and the net present value of such reserves as of December 31, 2023 set forth in this prospectus are based upon reserve reports prepared by our internal reservoir engineers and evaluated by Cawley, Gillespie & Associates.

Estimated quantities of proved oil and natural gas reserves of the Ardmore and Anadarko Assets and the net present value of such reserves as of July31, 2024 set forth in this prospectus are based upon reserve reports prepared by Cawley, Gillespie & Associates.

74

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-l (including the exhibits, schedules and amendments thereto) regarding our common units. This prospectus, which constitutes part of the registration statement, does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information regarding us and our common units offered in this prospectus, we refer you to the full registration statement, including its exhibits and schedules, filed under the Securities Act. Statements contained or incorporated by reference in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved.

The SEC maintains a website that contains reports, proxy and information statements and other information that we have filed electronically with the SEC. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s website. The address of the SEC’s website is www.sec.gov. We are subject to the informational requirements of the Exchange Act. We fulfill our obligations with respect to such requirements by filing reports and proxy and other information statements with the SEC.

Our website is machnr.com. The information contained on, or that can be accessed through, our website is not a part of this prospectus and is not incorporated by reference in this prospectus.

75

INCORPORATION OF CERTAIN INFORMATION BY REFERENCE

This prospectus “incorporates by reference” information that we have filed with the SEC under the Exchange Act, which means that we are disclosing important information to you by referring you to those documents. We incorporate by reference the documents listed below:

•our Annual Report on Form 10-K for the year ended December31, 2023;

•our Quarterly Reports on Form 10-Q for the quarters ended March31, 2024 and June30, 2024;

•our Current Reports on Form 8-K or Form 8-K/A filed with the SEC on March12, 2024, April11, 2024, May9, 2024, June13, 2024 and August30, 2024;

•the audited financial statements as of and for the years ended December31, 2022 and 2021 of BCE-Mach contained in our Registration Statement on Form S-1/A filed with the SEC on October16, 2023;

•the audited financial statements as of and for the years ended December31, 2022 and 2021 of BCE-Mach II contained in our Registration Statement on Form S-1/A filed with the SEC on October16, 2023; and

•the description of our common units included in our registration statement on Form 8-A, filed with the SEC on October24, 2023, including any amendments thereto.

Any statement contained in this prospectus or in any document incorporated or deemed to be incorporated by reference into this prospectus will be deemed modified or superseded for the purposes of this prospectus to the extent that a statement contained in this prospectus or any subsequently filed document which also is, or is deemed to be, incorporated by reference into this prospectus modifies or supersedes that statement. Any statement so modified or superseded will not be deemed, except as so modified or superseded, to constitute a part of this prospectus.

You can obtain any of the filings incorporated by reference in this prospectus through us or from the SEC through the SEC’s website at www.sec.gov. Our filings with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and exhibits incorporated in and amendments to those reports, are also available free of charge on our website (machnr.com) as soon as reasonably practicable after they are filed with, or furnished to, the SEC. The information contained on, or that can be accessed through, our website is not a part of this prospectus and is not incorporated by reference herein. You can obtain any of the documents incorporated by reference into this prospectus from us without charge, excluding any exhibits to those documents unless the exhibit is specifically incorporated by reference into those documents. You can obtain documents incorporated by reference into this prospectus by requesting them in writing or by telephone from us at the following address:

Investor Relations
Mach Natural Resources LP
14201 Wireless Way, Suite 300
Oklahoma City, Oklahoma
(405) 252-8100

76

INDEX TO FINANCIAL STATEMENTS

	Page
PRO FORMA FINANCIAL STATEMENTS
Mach Natural Resources LP
Unaudited Pro Forma Condensed Consolidated Financial Statements
Introduction	F-2
Unaudited Pro Forma Condensed Consolidated Financial Statements for the year ended December 31, 2023	F-4
Notes to Pro Forma Condensed Consolidated Financial Statements	F-5
HISTORICAL FINANCIAL STATEMENTS
BCE-Mach LLC
Interim Financial Statements (Unaudited)
Unaudited Financial Statements as of September 30, 2023 and for the Nine Months ended September 30, 2023	F-13
Notes to Financial Statements	F-18
BCE-Mach II LLC
Interim Financial Statements (Unaudited)
Unaudited Financial Statements as of September 30, 2023 and for the Nine Months ended September 30, 2023	F-31
Notes to Financial Statements	F-36

F-1

MACH NATURAL RESOURCES LP

Unaudited Pro Forma Condensed Combined Statement of Operations

Introduction

Mach Natural Resources LP (the “Company”) is a limited partnership 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.

The unaudited pro forma condensed combined statement of operations (the “pro forma statement of operations”) has been prepared in accordance with Article 11 of Regulation S-X, Pro Forma Financial Information, using assumptions set forth in the notes to the unaudited pro forma statement of operations. The following pro forma statement of operations reflects the historical results of (i) the Company, including the historical results of BCE-Mach III LLC (“BCE-Mach III” or the “Predecessor”), (ii) BCE-Mach LLC (“BCE-Mach”), (iii) BCE-Mach II LLC (“BCE-Mach II”) and (iv) Paloma Partners IV Holdings, LLC (“Paloma Partners”) 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 January 1, 2023:

1.The completion of the reorganization transactions (the “Corporate Reorganization”) described in “Note 1 — Basis of Pro Forma Presentation.”

2.The initial public offering of 10,000,000 common units (the “Offering”) at a price of $19.00 per unit and the use of net proceeds of $168.5 million, after deducting underwriting fees and offering expenses, as follows: (i) to repay the credit facilities of BCE-Mach and BCE-Mach II in full, (ii) to repay a portion of the BCE-Mach III credit facility and (iii) to purchase 3,750,000 common units from the existing owners prior to the Offering (the “Exchanging Members”) for $66.3 million.

3.The entry into certain new credit agreements and the termination of certain outstanding credit agreements (the “Refinancings”) described in “Note 1 — Basis of Pro Forma Presentation.”

4.The consummation of the transactions contemplated by the purchase and sale agreement (the “Paloma PSA”), dated as of November 10, 2023, 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”) for aggregate purchase consideration of $727.7 million, including purchase price adjustments and capitalized transaction costs (the “Paloma Acquisition,” and together with the Corporate Reorganization, the Offering and the Refinancings, the “Transactions”).

The pro forma statement of operations is based on the historical statements of operations of the Company, BCE-Mach, BCE-Mach II and Paloma Partners for the year ended December 31, 2023 and is adjusted to give effect to the Transactions as if they occurred on January 1, 2023. All entities contributed in the Corporate Reorganization had a high degree of common ownership, though no individual controlled any of the entities and therefore the transactions are not accounted for as common control transactions, and the acquisitions of BCE-Mach and BCE-Mach II by BCE-Mach III, the accounting acquirer and the Predecessor to the Company, were accounted for in accordance with the business combination guidance in ASC 805. The pro forma information presented reflects events directly attributable to the Transactions and certain assumptions the Company believes are reasonable.

The pro forma information is not necessarily indicative of financial results that would have been attained had the Transactions occurred on the date indicated or which could be achieved in the future because they necessarily exclude various operating expenses, such as incremental general and administrative expenses associated with being a public company. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the Transactions, and the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma statement of operations. The Company has not included any adjustments depicting synergies or dis-synergies of the Corporate Reorganization or the Paloma Acquisition.

F-2

The pro forma statement of operations and related notes are presented for illustrative purposes only. If the Transactions had occurred in the past, the Company’s operating results might have been materially different from those presented in the pro forma statement of operations. The pro forma statement of operations should not be relied upon as an indication of operating results that the Company would have achieved if the Transactions had taken place on the date specified in the pro forma statement of operations and related notes. In addition, future results may vary significantly from the results reflected in the pro forma statement of operations and should not be relied upon as an indication of the future results the Company.

F-3

MACH NATURAL RESOURCES LP

Unaudited Pro Forma Condensed Combined Statement of Operations
For the Year Ended December 31, 2023
(in thousands, except per unit data)

	Mach Natural Resources LP (Historical)			BCE-Mach (Historical)(1)			BCE-Mach (Historical)(2)			BCE- Mach II (Historical)(1)			BCE- Mach II (Historical)(2)			Paloma Assets As Adjusted (See Note 3)		Transaction Adjustments (Pro Forma)				Mach Natural Resources LP Pro Forma Combined
Revenue
Oil, natural gas, and NGL sales	$	647,352		$	104,896		$	11,642		$	23,772		$	2,281		$	338,590	$	—			$	1,128,533
Gain (loss) on oil and natural gas derivatives		57,272			5,713			1,404			835			199			—		—				65,423
Midstream revenue		26,328			—			—			319			34			—		—				26,681
Product sales		31,357			—			—			—			—			—		—				31,357
Total revenues		762,309			110,609			13,046			24,926			2,514			338,590		—				1,251,994
Operating expenses
Gathering and processing		39,449			21,377			2,246			2,808			267			34,735		—				100,882
Lease operating expense		127,602			30,080			3,038			9,926			1,080			18,064		—				189,790
Production taxes		31,882			5,252			610			1,142			98			15,999		—				54,983
Midstream operating expense		10,873			—			—			350			32			—		—				11,255
Cost of product sales		28,089			—			—			—			—			—		—				28,089
Depreciation, depletion, and accretion – oil and natural gas		131,145			18,159			1,670			3,320			287			—		105,337		(a)		259,918
Depreciation and amortization – other		6,472			6,701			802			519			57			—		(7,354	)	(b)		7,197
General and administrative		22,861			7,447			810			(2,174	)		(179	)		—		—				28,765
General and administrative – related party		4,792			—			—			—			—			—		—				4,792
Total operating expenses		403,165			89,016			9,176			15,891			1,642			68,798		97,983				685,671
Income from operations		359,144			21,593			3,870			9,035			872			269,792		(97,983	)			566,323
Other (expense) income
Interest expense		(11,201	)		(4,284	)		(500	)		(1,148	)		(135	)		—		16,409		(c)		(104,448	)
																			(103,589	)	(d)
Gain (loss) on sale of assets		(1,385	)		—			—			—			—			—		—				(1,385	)
Other (expense) income, net		—			(4,825	)		(173	)		(1,937	)		16			—		—				(6,919	)
Total other expense		(12,586	)		(9,109	)		(673	)		(3,085	)		(119	)		—		(87,180	)			(112,752	)
Net income	$	346,558		$	12,484		$	3,197		$	5,950		$	753		$	269,792	$	(185,163	)		$	453,571
Less: net income attributable to Predecessor		(278,040	)																278,040		(e)		—
Net income attributable to Mach Natural Resources LP		68,518																$	92,877			$	453,571
Net income per common unit attributable to Mach Natural Resources LP
Basic	$	0.72																$	4.05		(f)	$	4.77
Diluted	$	0.72																$	4.05		(f)	$	4.77
Weighted average common units outstanding:
Basic		94,907																	93		(g)		95,000
Diluted		94,907																	93		(g)		95,000

____________

(1)Reflects the historical operations of BCE-Mach and BCE-Mach II for the nine months ended September 30, 2023.

(2)Reflects the historical operations of BCE-Mach and BCE-Mach II for the period from October 1, 2023 through October 25, 2023, the date of the Corporate Reorganization.

The accompanying notes are an integral part of this
unaudited pro forma condensed combined statement of operations.

F-4

MACH NATURAL RESOURCES LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

Note 1 — Basis of Pro Forma Presentation

The historical financial information included herein is derived from the statements of operations of the Company, BCE-Mach, BCE-Mach II, and Paloma Partners. For purposes of the pro forma statement of operations, it is assumed that each of the Transactions took place on January 1, 2023:

Corporate Reorganization

i)Investment funds managed by Bayou City Energy Management LLC contributed 100% of their membership interests in the Predecessor, BCE-Mach and BCE-Mach II to BCE Mach Aggregator LLC (“BCE-Mach Aggregator”) in exchange for 100% of the membership interests in BCE-Mach Aggregator;

ii)Each of BCE-Mach Aggregator, the current officers and employees who own indirect equity interests in the Predecessor, BCE-Mach and BCE-Mach II and Mach Resources, LLC contributed 100% of their respective membership interests in the Predecessor, BCE-Mach and BCE-Mach II to the Company in exchange for a pro rata allocation of 100% of the limited partner interests in the Company;

iii)The Company contributed 100% of its membership interests in the Predecessor, BCE-Mach and BCE-Mach II to Mach Natural Resources Intermediate LLC (“Intermediate”) in exchange for 100% of the membership interests in Intermediate; and

iv)Intermediate contributed 100% of its membership interests in the Predecessor, BCE-Mach and BCE-Mach II to Mach Natural Resources Holdco LLC (“Holdco”) in exchange for 100% of the membership interests in Holdco.

The Offering

i)10,000,000 common units of the Company were issued and sold to the public at an initial public offering price of $19.00 per common unit. The gross proceeds from the sale of the common units were $190.0 million, and net proceeds were $168.5 million after deducting underwriters’ fees and offering expenses; and

ii)Net proceeds from the Offering were used as follows: (i) to repay the credit facilities of BCE-Mach and BCE-Mach II in full, (ii) to repay a portion of the BCE-Mach III credit facility and (iii) to purchase 3,750,000 common units from the Exchanging Members for $66.3 million.

The Refinancings

i)The Company entered into an amended and restated credit agreement (the “November 2023 Credit Facility”) with a syndicate of banks, including MidFirst Bank who served as sole book runner and lead arranger. In connection with entering into the November 2023 Credit Facility on November 10, 2023, the Company repaid all amounts outstanding under the BCE-Mach III credit facility and terminated the credit facilities of BCE-Mach III, BCE-Mach and BCE-Mach II (collectively, the “Pre-IPO Credit Facilities”); and

ii)The Company entered into (i) the Term Loan Credit Agreement, 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. The Company used borrowings from the Term Loan Credit Agreement, together with cash on hand, to repay and terminate the November 2023 Credit Facility on December 28, 2023.

Paloma Acquisition

i)The Paloma Acquisition was consummated pursuant to the terms of the Paloma PSA.

Subsequent to the closing of the Offering, the Company has incurred direct, incremental general and administrative expenses as a result of being publicly traded, including, but not limited to, costs associated with annual and quarterly reports to unitholders, tax return preparation, independent auditor fees, incremental legal fees,

F-5

MACH NATURAL RESOURCES LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

Note 1 — Basis of Pro Forma Presentation (cont.)

investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental general and administrative expenditures are not fully reflected in the historical financial statements or in the pro forma statement of operations.

The pro forma statement of operations reflects pro forma adjustments that are based on available information and certain assumptions that management believes are reasonable. However, actual results may differ from those reflected in these statements. In management’s opinion, all adjustments known to date that are necessary to fairly present the pro forma information have been made. The pro forma statement of operations does not purport to represent what the combined entity’s results of operations would have been if the Transactions had actually occurred on January 1, 2023, nor are they indicative of the Company’s future results of operations.

This pro forma statement of operations should be read in conjunction with the Company’s historical financial statements for the year ended December 31, 2023 included in the Company’s Annual Report on Form 10-K, as well as the historical financial statements of BCE-Mach, BCE-Mach II, and Paloma Partners for the nine months ended September 30, 2023 included elsewhere in this registration statement.

Note 2 — Purchase Price Allocations

The acquisitions of BCE-Mach and BCE-Mach II, in connection with the Corporate Reorganization, were accounted for using the acquisition method of accounting for business combinations with BCE-Mach III, the Predecessor of the Company, determined to be the accounting acquirer. The Paloma Acquisition was accounted for as an asset acquisition. The allocation of the purchase price for the acquisitions of BCE-Mach, BCE-Mach II and the Paloma Acquisition were based upon management’s estimates of and assumptions related to the fair value of assets acquired and liabilities assumed using available information. The Company has completed the purchase price allocations for BCE-Mach, BCE-Mach II and the Paloma Acquisition.

The determination of consideration transferred and the allocation of the purchase price to assets acquired and liabilities assumed were as follows (in thousands, except unit data):

	BCE-Mach		BCE-Mach II		Paloma Acquisition
Common units issued for acquisition		7,765,625		4,215,625		—
Offering price of common units	$	19.00	$	19.00	$	—
Equity consideration	$	147,547	$	80,097	$	—
Cash consideration		—		—		724,913
Capitalized transaction costs		—		—		2,980
Less: purchase price adjustment receivable		—		—		(188	)
Total acquisition consideration	$	147,547	$	80,097	$	727,705
Assets acquired:
Cash and cash equivalents	$	30,350	$	8,803	$	—
Accounts receivable		32,042		11,541		4,239
Other current assets		18,303		2,331		166
Proved oil and natural gas properties		184,840		98,800		751,631
Other long-term assets		11,176		7,811		—
Total assets acquired		276,711		129,286		756,036
Liabilities assumed:
Accounts payable and accrued liabilities		17,312		3,659		—
Revenue payable		29,390		15,317		26,867
Other current liabilities		1,361		446		—
Long-term debt		65,000		17,100		—
Asset retirement obligations		14,369		11,589		1,464
Other long-term liabilities		1,732		1,078		—
Total liabilities assumed		129,164		49,189		28,331
Net assets acquired	$	147,547	$	80,097	$	727,705

F-6

MACH NATURAL RESOURCES LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

Note 3 — Adjustments to Historical Statement of Operations of Paloma Partners

The following table presents pro forma adjustments to the historical statement of operations of Paloma Partners. In addition to carve-out adjustments for certain oil and natural gas properties and activities that were not acquired from Paloma Partners as part of the Paloma Acquisition, certain reclassification adjustments were made to the financial statement presentation of Paloma Partners in order to conform with the Company’s financial statement presentation.

	Paloma Partners (Historical)(1)			Paloma Partners Reclassification Adjustments (Pro Forma)			Paloma Partners Carve-out Adjustments (Pro Forma)				Paloma Assets (Historical)(2)		Paloma Assets As Adjusted (Pro Forma)
Revenue
Crude oil	$	149,708		$	(149,708	)	$	—			$	—	$	—
Natural gas		51,377			(51,377	)		—				—		—
Natural gas liquids		61,885			(61,885	)		—				—		—
Oil, natural gas, and NGL sales		—			262,970			(19,959	)	(a)		95,579		338,590
Realized gain (loss) on derivatives		8,655			—			(8,655	)	(b)		—		—
Total revenues		271,625			—			(28,614	)			95,579		338,590
Operating expenses
Processing and other fees		30,371			(30,371	)		—				—		—
Gathering and processing		—			30,371			(7,489	)	(a)		11,853		34,735
Lease operating expense		16,803			—			(3,480	)	(a)		4,741		18,064
Production taxes		13,875			—			(2,808	)	(a)		4,932		15,999
Depletion and accretion		56,791			—			(56,791	)	(c)		—		—
Overhead reimbursement		7,703			—			(7,703	)	(b)		—		—
General and administrative		1,392			—			(1,392	)	(b)		—		—
Total operating expenses		126,935			—			(79,663	)			21,526		68,798
Income from operations		144,690			—			51,049				74,053		269,792
Other (expense) income
Unrealized gain (loss) on derivatives		6,912			—			(6,912	)	(b)		—		—
Interest expense		(12,392	)		—			12,392		(b)		—		—
Gain (loss) on sale of assets		(141,439	)		—			141,439		(b)		—		—
Other income (expense)		791			—			(791	)	(b)		—		—
Total other expense		(146,128	)		—			146,128				—		—
Net income		(1,438	)		—			197,177				74,053		269,792

____________

(1)Reflects the historical operations of Paloma Partners for the nine months ended September 30, 2023.

(2)Reflects the revenues and direct operating expenses of the acquired Paloma Assets for the period from October 1, 2023 through December 28, 2023, the date the Paloma Acquisition was closed. Historical information for Paloma Partners is not available for this stub period.

F-7

MACH NATURAL RESOURCES LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

Note 3 — Adjustments to Historical Statement of Operations of Paloma Partners (cont.)

The Company made the following pro forma carve-out adjustments to the historical statement of operations of Paloma Partners:

a)Adjustments reflect the carve-out of revenues and operating expenses for certain oil and natural gas properties that were not acquired from Paloma Partners as part of the Paloma Acquisition.

b)Adjustments reflect the elimination of historical amounts for Paloma Partners related to activities that were not acquired as part of the Paloma Acquisition.

c)Adjustment reflects the elimination of depletion and accretion for the nine months ended September 30, 2023 for Paloma Partners on a pro forma basis. A separate depletion adjustment has been recorded on a pro forma basis for the entirety of the Company’s full cost pool within the pro forma statement of operations for the year ended December 31, 2023.

Note 4 — Pro Forma Adjustments and Assumptions

The pro forma statement of operations has been prepared to illustrate the effect of the Transactions and has been prepared for informational purposes only.

The preceding pro forma statement of operations has been prepared in accordance with Article 11 of Regulation S-X which requires the presentation of adjustments to account for the pro forma transactions (“Transaction Accounting Adjustments”) and allows for supplemental disclosure of the reasonably estimable synergies and other transaction effects that have occurred or are reasonably expected to occur (“Management Adjustments”). Management has elected not to disclose Management Adjustments.

The Company made the following adjustments and assumptions in its preparation of the pro forma statement of operations:

a)Adjustment reflects changes to depreciation, depletion and amortization expense that would have been incurred based on the fair value of acquired oil and natural gas properties.

b)Adjustment reflects changes to depreciation and amortization of other assets that would have been incurred based on the fair value of acquired other property and equipment.

c)Adjustment reflects the elimination of interest expense for the Pre-IPO Credit Facilities and the November 2023 Credit Facility resulting from the use of proceeds from the Offering and the Term Loan Credit Agreement to pay down all debt outstanding under the Pre-IPO Credit Facilities and the November 2023 Credit Facility.

d)Adjustment reflects interest expense for the Credit Agreements on a pro forma basis assuming the amounts drawn on December 28, 2023 were outstanding from January 1, 2023.

e)Adjustment reflects the elimination of net income attributable to Predecessor on a pro forma basis.

f)Adjustments reflect the computation of net income per common unit on a pro forma basis.

g)Adjustments reflect the pro forma impact of the Company’s net issuance of common units assuming the Corporate Reorganization and the Offering had occurred on January 1, 2023.

Note 5 — Supplementary Disclosure for Oil and Natural Gas Producing Activities

Oil and natural gas reserves

The following tables present the estimated pro forma combined net proved developed and undeveloped oil, natural gas and NGL reserves information as of December 31, 2023 for the Company’s proved reserves. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and

F-8

MACH NATURAL RESOURCES LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

Note 5 — Supplementary Disclosure for Oil and Natural Gas Producing Activities (cont.)

frequent revisions. The estimates below are in certain instances presented on a “barrels of oil equivalent” or “Boe” basis. To determine Boe in the following tables, natural gas is converted to a crude oil equivalent at the ratio of six Mcf of natural gas to one barrel of crude oil equivalent.

The pro forma oil and natural gas reserves information is not necessarily indicative of the results that might have occurred had the Corporate Reorganization and Paloma Acquisition been completed on January 1, 2023 and is not intended to be a projection of the Company’s future results. Future results may vary significantly from the results reflected because of various factors, including those discussed in “Risk Factors” included in the Company’s Annual Report filed on Form 10-K.

	Mach Natural Resources LP (Historical)		BCE-Mach Transaction Adjustments (Pro Forma)		BCE-Mach II Transaction Adjustments (Pro Forma)		Paloma Acquisition Transaction Adjustments (Pro Forma)		Mach Natural Resources LP Pro Forma Combined
	Oil (MBbl)
Proved Developed and Undeveloped Reserves as of:
December 31, 2022	48,580		16,472		1,694		21,087		87,833
Revisions of previous estimates	(724	)	(6,296	)	(335	)	3,589		(3,766	)
Purchases in place	33,198		(9,309	)	(1,243	)	(22,159	)	487
Extensions, discoveries and other additions	—		—		—		—		—
Sales in place	(36	)	—		—		—		(36	)
Production	(5,445	)	(867	)	(116	)	(2,517	)	(8,945	)
December 31, 2023	75,573		—		—		—		75,573
Proved Developed Reserves as of:
December 31, 2022	29,984		11,629		1,694		11,548		54,855
December 31, 2023	49,629		—		—		—		49,629
Proved Undeveloped Reserves as of:
December 31, 2022	18,596		4,843		—		9,539		32,978
December 31, 2023	25,944		—		—		—		25,944
	Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves as of:
December 31, 2022	629,620		254,150		98,908		384,593		1,367,271
Revisions of previous estimates	(95,816	)	(68,906	)	(26,553	)	35,724		(155,551	)
Purchases in place	632,049		(172,060	)	(66,614	)	(391,763	)	1,612
Extensions, discoveries and other additions	—		—		—		—		—
Sales in place	—		—		—		—		—
Production	(59,378	)	(13,184	)	(5,741	)	(28,554	)	(106,857	)
December 31, 2023	1,106,475		—		—		—		1,106,475
Proved Developed Reserves as of:
December 31, 2022	527,369		212,020		98,908		179,116		1,017,413
December 31, 2023	909,372		—		—		—		909,372
Proved Undeveloped Reserves as of:
December 31, 2022	102,251		42,130		—		205,477		349,858
December 31, 2023	197,103		—		—		—		197,103

F-9

MACH NATURAL RESOURCES LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

Note 5 — Supplementary Disclosure for Oil and Natural Gas Producing Activities (cont.)

	Mach Natural Resources LP (Historical)		BCE-Mach Transaction Adjustments (Pro Forma)		BCE-Mach II Transaction Adjustments (Pro Forma)		Paloma Acquisition Transaction Adjustments (Pro Forma)		Mach Natural Resources LP Pro Forma Combined
	NGL (MBbl)
Proved Developed and Undeveloped Reserves as of:
December 31, 2022	46,833		16,210		6,695		44,865		114,603
Revisions of previous estimates	(13,768	)	(5,017	)	(2,135	)	(219	)	(21,139	)
Purchases in place	55,668		(10,415	)	(4,219	)	(41,034	)	—
Extensions, discoveries and other additions	—		—		—		—		—
Sales in place	—		—		—		—		—
Production	(3,068	)	(778	)	(341	)	(3,612	)	(7,799	)
December 31, 2023	85,665		—		—		—		85,665
Proved Developed Reserves as of:
December 31, 2022	39,239		13,827		6,695		20,739		80,500
December 31, 2023	69,193		—		—		—		69,193
Proved Undeveloped Reserves as of:
December 31, 2022	7,594		2,383		—		24,126		34,103
December 31, 2023	16,472		—		—		—		16,472
	Oil Equivalents (MBoe)
Proved Developed and Undeveloped Reserves as of:
December 31, 2022	200,349		75,040		24,874		130,050		430,313
Revisions of previous estimates	(30,461	)	(22,797	)	(6,896	)	9,325		(50,829	)
Purchases in place	194,208		(48,401	)	(16,564	)	(128,487	)	756
Extensions, discoveries and other additions	—		—		—		—		—
Sales in place	(36	)	—		—		—		(36	)
Production	(18,409	)	(3,842	)	(1,414	)	(10,888	)	(34,553	)
December 31, 2023	345,650		—		—		—		345,650
Proved Developed Reserves as of:
December 31, 2022	157,117		60,792		24,874		62,139		304,922
December 31, 2023	270,384		—		—		—		270,384
Proved Undeveloped Reserves as of:
December 31, 2022	43,232		14,248		—		67,911		125,391
December 31, 2023	75,266		—		—		—		75,266

Standardized measure of discounted future net cash flows

The following tables present the pro forma standardized measure of discounted future net cash flows (the “pro forma standardized measure”) as of December 31, 2023 for the Company’s proved reserves. The future cash flows are discounted at 10% per year and assume continuation of existing economic conditions.

F-10

MACH NATURAL RESOURCES LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

Note 5 — Supplementary Disclosure for Oil and Natural Gas Producing Activities (cont.)

The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of the Company’s proved oil and natural gas properties.

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the prices and costs utilized in the computation of reported amounts.

The pro forma standardized measure is not necessarily indicative of the results that might have occurred had the Corporate Reorganization and Paloma Acquisition been completed on January 1, 2023 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected because of various factors, including those discussed in “Risk Factors” included in the Company’s Annual Report on Form 10-K.

The pro forma standardized measure of discounted future net cash flows from projected production of the Company’s proved oil and natural gas reserves as of December 31, 2023 is as follows:

	(in thousands)
	Mach Natural Resources LP (Historical)			Transaction Adjustments (Pro Forma)		Mach Natural Resources LP Pro Forma Combined
Future cash inflows	$	9,729,149		$	—	$	9,729,149
Future costs:
Production(1)		(3,831,083	)		—		(3,831,083	)
Development(2)		(1,097,667	)		—		(1,097,667	)
Income taxes		—			—		—
Future net cash flows		4,800,399			—		4,800,399
10% annual discount		(2,223,540	)		—		(2,223,540	)
Standardized measure	$	2,576,859		$	—	$	2,576,859

____________

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

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

F-11

MACH NATURAL RESOURCES LP

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

Note 5 — Supplementary Disclosure for Oil and Natural Gas Producing Activities (cont.)

Changes in standardized measure

The changes in the pro forma standardized measure of discounted future net cash flows relating to the Company’s proved oil and natural gas reserves for the year ended December 31, 2023 are as follows:

	(in thousands)
	Mach Natural Resources LP (Historical)			BCE-Mach Transaction Adjustments (Pro Forma)			BCE-Mach II Transaction Adjustments (Pro Forma)			Paloma Acquisition Transaction Adjustments (Pro Forma)			Mach Natural Resources LP Pro Forma Combined
Standardized measure, beginning of period	$	2,953,505		$	849,970		$	254,830		$	2,069,928		$	6,128,233
Revisions of previous quantity estimates		(509,130	)		(291,352	)		(73,741	)		84,907			(789,316	)
Changes in estimated future development costs		4,361			(33	)		(49	)		10,099			14,378
Purchases of reserves in place		1,374,144			(278,044	)		(67,158	)		(1,020,382	)		8,560
Net changes in prices and production costs		(1,248,485	)		(412,803	)		(133,908	)		(1,211,830	)		(3,007,026	)
Divestiture of reserves		(1,207	)		—			—			—			(1,207	)
Net change due to extensions and discoveries, net of estimated future development and production costs		—			—			—			—			—
Accretion of discount		295,351			70,831			21,236			205,291			592,709
Sales of oil and gas produced, net of production costs		(448,419	)		(53,935	)		(10,732	)		(269,792	)		(782,878	)
Development costs incurred during the period		56,064			7,503			356			189,389			253,312
Change in timing of estimated future production and other		100,675			107,863			9,166			(57,610	)		160,094
Standardized measure, end of period	$	2,576,859		$	—		$	—		$	—		$	2,576,859

F-12

BCE-Mach LLC
Unaudited Financial Statements
As of September 30, 2023 and December 31, 2022 and for the nine months ended September 30, 2023 and 2022

F-13

BCE-MACH LLC
BALANCE SHEETS (UNAUDITED)
(in thousands)

	September 30, 2023			December 31, 2022
ASSETS
Current assets:
Cash and cash equivalents	$	25,370		$	30,266
Accounts receivable – joint interest and other, net		10,419			10,941
Accounts receivable – oil, gas, and NGL sales		22,154			31,457
Inventories		14,330			12,518
Other current assets		2,097			403
Total current assets		74,370			85,585
Oil and natural gas properties, using the full cost method:
Proved oil and natural gas properties		530,123			515,790
Less: accumulated depreciation, depletion, amortization and impairment		(297,541	)		(280,472	)
Oil and natural gas properties, net		232,582			235,318
Other property, plant and equipment		99,697			96,292
Less: accumulated depreciation		(42,149	)		(35,499	)
Other property, plant and equipment, net		57,548			60,793
Other assets		5,334			8,326
Operating lease assets		2,897			2,496
Goodwill		2,674			2,674
Total assets	$	375,405		$	395,192
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	7,272		$	12,818
Accrued liabilities		11,770			15,055
Revenue payable		28,808			34,860
Short-term derivative liabilities		361			9,339
Current portion of operating lease liabilities		1,393			1,117
Total current liabilities		49,604			73,189
Long-term debt		65,000			65,000
Asset retirement obligations		34,776			33,693
Long-term portion of operating leases		1,513			1,379
Other long-term liabilities		322			225
Total long-term liabilities		101,611			100,297
Commitments and contingencies (Note 9)
Members’ equity:
Members’ equity		224,190			221,706
Total liabilities and members’ equity	$	375,405		$	395,192

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

F-14

BCE-MACH LLC
STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands)

	Nine Months Ended September 30,
	2023			2022
Revenue
Oil, natural gas, and NGL sales	$	104,896		$	186,729
Gain (loss) on oil and natural gas derivatives		5,713			(46,781	)
Total revenues		110,609			139,948
Operating expenses
Gathering and processing		21,377			26,413
Lease operating expense		30,080			26,104
Production taxes		5,252			10,594
Depreciation, depletion, amortization and accretion – oil and natural gas		18,159			19,986
Depreciation and amortization – other		6,701			6,191
General and administrative		7,447			3,272
Total operating expenses		89,016			92,560
Income from operations		21,593			47,388
Other (expense) income
Interest expense		(4,284	)		(4,303	)
Gain (loss) on debt extinguishment		—			(898	)
Other income (expense), net		(4,825	)		1,702
Total other expense		(9,109	)		(3,499	)
Net income	$	12,484		$	43,889

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

F-15

BCE-MACH LLC
STATEMENTS OF MEMBERS’ EQUITY (UNAUDITED)
(in thousands)

	Total Members’ Equity
Balance at December 31, 2022	$	221,706
Net income		12,484
Distributions		(10,000	)
Balance at September 30, 2023	$	224,190
Balance at December 31, 2021	$	180,065
Net income		43,889
Balance at September 30, 2022	$	223,954

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

F-16

BCE-MACH LLC
STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)

	Nine Months Ended September 30,
	2023			2022
Cash flows from operating activities
Net income	$	12,484		$	43,889
Adjustments to reconcile net income to cash provided by operating activities
Depreciation, depletion, amortization and accretion		24,860			26,177
(Loss) gain on derivative instruments		(5,713	)		46,781
Cash (payments) on settlement of derivative contracts, net		(5,259	)		(56,714	)
Debt issuance costs amortization		131			1,950
(Gain) loss on sale of assets		(33	)		29
Settlement of asset retirement obligations		(52	)		(118	)
Changes in operating assets and liabilities (decreasing) increasing cash:
Accounts receivable		8,614			(2,534	)
Revenue payable		(6,052	)		8,503
Accounts payable and accrued liabilities		135			8,216
Other		(928	)		(12,211	)
Net cash provided by operating activities		28,187			63,968
Cash flows from investing activities
Capital expenditures for oil and natural gas properties		(19,661	)		(3,466	)
Capital expenditures for other property and equipment		(3,455	)		(1,987	)
Proceeds from sales of other property and equipment		33			285
Net cash used in investing activities		(23,083	)		(5,168	)
Cash flows from financing activities
Distributions to members		(10,000	)		—
Payment of other financing fees		—			(700	)
Proceeds from long-term debt		—			70,000
Repayments of borrowings		—			(113,500	)
Net cash used in financing activities		(10,000	)		(44,200	)
Net (decrease) increase in cash and cash equivalents		(4,896	)		14,600
Cash and cash equivalents, beginning of period		30,266			36,550
Cash and cash equivalents, end of period	$	25,370		$	51,150

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

F-17

BCE-MACH LLC
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

1. Organization and Nature of Business

BCE-Mach LLC (“the Company”) was formed on January 23, 2018 as a limited liability company under the laws of the State of Delaware. On March 29, 2018, the Company entered into an amended and restated LLC agreement with two entities (the “Members”, see Note 11 — Members’ Equity), capitalizing the Company concurrent with its initial acquisitions of oil and natural gas properties and commencement of operations. Revenues and expenses are allocated to the Members based upon the provisions of the Company’s operating agreement. The Company owns producing wells and undeveloped acreage primarily in Oklahoma and Kansas.

2. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The unaudited financial statements included herein were prepared from records of the Company in accordance with generally accepted accounting principles in the United States (“US GAAP”). These financial statements should be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2022. Results for interim periods are not necessarily indicative of results to be expected for the full year ending December 31, 2023. 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.

Use of Estimates

The preparation of the financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, 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.

Cash and Cash Equivalents

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

Accounts Receivable

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

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

F-18

BCE-MACH LLC
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

2. Basis of Presentation and Summary of Significant Accounting Policies (cont.)

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 September 30, 2023 and December 31, 2022, the allowance for credit losses related to joint interest receivables and the credit losses related to sales of oil and natural gas was not material.

Derivative Instruments

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

Oil and Natural Gas Operations

The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, costs of both successful and unsuccessful exploration and development activities are capitalized as proved oil and natural gas properties. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities, which are expensed as incurred. Capitalized costs are depreciated using the unit of production method. Under this method, depletion is computed at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by a net equivalent proved reserves at the beginning of the period. The average depletion rate per barrel equivalent unit of production was $4.93 and $5.33 for the nine months ended September 30, 2023 and 2022, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $17.1 million and $18.9 million for the nine months ended September 30, 2023 and 2022, respectively.

Under the full cost method, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization, may not exceed the full cost “ceiling” at the end of each reporting period. The ceiling is calculated based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10%. The estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and natural gas properties. Estimated future net cash flows are calculated using the preceding 12-months’ average price based on closing prices on the first day of each month. The net book value is compared to the ceiling limitation on a quarterly basis. The excess, if any, of the net book value above the ceiling limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. The ceiling limitation computation is determined without regard to income taxes due to the Internal Revenue Service (“IRS”) recognition of the Company as a flow-through entity. No impairments on proved oil and natural gas properties were recorded for the nine months ended September 30, 2023 and 2022.

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

F-19

BCE-MACH LLC
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

2. Basis of Presentation and Summary of Significant Accounting Policies (cont.)

and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. As of September 30, 2023, and December 31, 2022, 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, Net

Other property and equipment primarily consists of compression assets. Additionally, other property and equipment includes computer equipment and software, vehicles, office furniture, and an office building for field operations. Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed as incurred. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from two to 39 years. Depreciation expense for other property and equipment was $6.7 million and $6.2 million for the nine months ended September 30, 2023 and 2022, respectively.

Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. No impairment of other property and equipment was recorded for the nine months ended September 30, 2023 or 2022.

Inventories

Inventories are stated at the lower of cost or net realizable value and consist of production equipment not placed in service as of September 30, 2023 and December 31, 2022. The Company’s equipment is primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations.

Debt Issuance Costs

Other assets include capitalized costs related to the credit facility of $0.7 million, net of accumulated amortization of $0.2 million as of September 30, 2023. As of December 31, 2022, other assets include capitalized costs related to the credit facility of $0.7 million, net of accumulated amortization of $0.1 million. These costs are being amortized over the terms of the related credit agreements and are reported as interest expense on the Company’s statement of operations.

Income Taxes

The Company is an LLC taxed as a partnership, and any associated tax liability is the responsibility of the individual members of the LLC. Accordingly, no provision for income taxes has been made in these financial statements.

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 nine months ended September 30, 2023. The Company’s tax years 2022, 2021, and 2020 remain open for examination by state authorities.

F-20

BCE-MACH LLC
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

2. Basis of Presentation and Summary of Significant Accounting Policies (cont.)

Goodwill

Goodwill represents the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment at least annually. Such test includes an assessment of the qualitative factors that could indicate impairment, and if necessary, the quantitative analysis to determine the goodwill.

Asset Retirement Obligations

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

The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future downhole plugging, dismantlement and removal of production equipment and facilities, and the restoration and reclamation of a field’s surface to a condition similar to that existing before oil and natural gas extraction or 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 nine months ended September 30, 2023 and 2022 (in thousands):

	September 30, 2023			September 30, 2022
Asset retirement obligation at beginning of period	$	33,693		$	33,617
Liabilities incurred		32			77
Liabilities settled		(94	)		(1,687	)
Liabilities revised		54			293
Accretion expense		1,091			1,105
Asset retirement obligation at end of period	$	34,776		$	33,405

Revenue Recognition

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.

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and the Company expects this volatility to continue in the future. The prices the Company receives for production depend on many factors outside of our control. See Note 6 for a discussion of the Company’s management of price volatility.

F-21

BCE-MACH LLC
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

2. Basis of Presentation and Summary of Significant Accounting Policies (cont.)

Oil Sales

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

Natural Gas and NGL Sales

Under the Company’s natural gas and NGL sales contracts, it first delivers wet natural gas to a midstream processing entity. After processing, the residue gas is transported to the purchaser at the inlet to certain natural gas pipelines, where the purchaser takes control, title and risk of loss of the product. 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.

Transaction Price Allocated to Remaining Performance Obligations

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

Prior-Period Performance Obligations

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

Concentrations

The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. The following purchasers each accounted for more than 10% of the Company’s revenues for the nine months ended September 30, 2023 and 2022:

	Nine Months Ended September 30,
	2023		2022
Coffeyville Resources, LLC	43.9	%	*
Southwest Energy L.P.	*		32.1	%
NextEra Energy Marketing, LLC	27.2	%	32.0	%
One-Ok Hydrocarbon, L.P.	10.6	%	11.3	%
Sandridge Energy, Inc.	10.2	%	12.1	%

____________

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

F-22

BCE-MACH LLC
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

2. Basis of Presentation and Summary of Significant Accounting Policies (cont.)

The Company’s receivables as of September 30, 2023 and 2022 from oil and gas sales are concentrated with the same counterparties noted above. The Company does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

As of September 30, 2023 and December 31, 2022, the Company had one customer that represented approximately 69.8% and 70.7% of our total joint interest receivables.

Revenue Disaggregation

The following table displays the revenue disaggregated and reconciles disaggregated revenue to the revenue reported for the nine months ended September 30, 2023 and 2022 (in thousands):

	Nine Months Ended September 30,
	2023			2022
Revenues:
Oil	$	58,573		$	76,353
Natural gas		30,374			78,819
NGL		17,360			31,572
Gross oil, natural gas, and NGL sales		106,307			186,744
Transportation, gathering and marketing		(1,411	)		(15	)
Net oil, natural gas, and NGL sales	$	104,896		$	186,729

Supplemental Cash Flow Information

Supplemental disclosures to the statements of cash flows are presented below for the nine months ended September 30, 2023 and 2022 (in thousands):

	Nine Months Ended September 30,
	2023			2022
Supplemental disclosure of cash flow information:
Cash paid for interest	$	3,682		$	3,250
Supplemental disclosure of non-cash transactions:
Change in accrued capital expenditures	$	(5,373	)	$	(13	)
Asset retirement cost capitalized	$	32		$	77
Right-of-use assets obtained in exchange for lease liabilities	$	1,322		$	2,881

Recent Accounting Pronouncements Adopted

In June 2016, the FASB issued Accounting Standards Update 2016-13, “Financial Instrument-Credit Losses: Measurement of Credit Losses on Financial Instruments,” which amends reporting guidance on credit loses for certain financial instruments. The Company’s primary risk for credit losses related to its receivables from joint interest owners in our operated oil and natural gas wells. This guidance is effective for periods after December 15, 2022, and the Company implemented it effective January 1, 2023, with no material impacts to the financial statements.

F-23

BCE-MACH LLC
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

3. Property and Equipment

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

	September 30, 2023			December 31, 2022
Oil and natural gas properties
Proved properties	$	530,123		$	515,790
Accumulated depreciation and depletion		(297,541	)		(280,472	)
Oil and natural gas properties, net		232,582			235,318
Other property and equipment
Compressors	$	92,050		$	88,802
Buildings		4,032			4,032
Vehicles		1,002			912
Office equipment		1,105			1,038
Land		904			904
Other assets		604			604
Total other property and equipment		99,697			96,292
Accumulated depreciation, depletion and amortization		(42,149	)		(35,499	)
Total other property and equipment, net	$	57,548		$	60,793

4. Accrued Liabilities

Accrued liabilities consist of the following (in thousands):

	September 30, 2023		December 31, 2022
Operating expenses	$	4,874	$	5,356
Capital expenditures		1,317		4,968
Payroll costs		1,569		2,033
Severance and other tax		1,311		935
General, administrative, and other		2,699		54
Derivative settlements		—		1,709
Total accrued liabilities	$	11,770	$	15,055

5. Long-Term Debt

The Company entered into a revolving credit facility (“the Credit Facility”) on September 2, 2022 with a syndicate of banks, including MidFirst Bank who serves as sole book runner and lead arranger, maturing in September 2026. Outstanding obligations under the Credit Facility are secured by substantially all of the Company’s assets. The previous revolving Credit Facility was retired in September 2022 and the Company wrote off all unamortized loan origination costs, recognizing $0.9 million as loss on debt extinguishment in the third quarter of 2022.

The credit agreement provides for a revolving Credit Facility in the maximum of $200.0 million, subject to commitments of $100.0 million as of September 30, 2023. As of September 30, 2023, $65.0 million was outstanding under the Credit Facility and $5.0 million in outstanding letters of credit, which reduces the availability under the Credit Facility on a dollar-for-dollar basis. The amount available to be borrowed under the Credit Facility is subject to a borrowing base that is redetermined semiannually each May and November in an amount determined by the lenders.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements

F-24

BCE-MACH LLC
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

5. Long-Term Debt (cont.)

and require the maintenance of the financial ratios. Financial ratios the Company is required to maintain on a quarterly basis include the ratio of total net debt to EBITDAX not greater than 3.25 and the ratio of current assets to current liabilities of no less than 1.0. As of September 30, 2023 and December 31, 2022, the Company was in compliance with all applicable covenants under the Credit Facility.

Outstanding borrowings under the credit agreement bear interest at a per annum rate that is equal to the SOFR rate (which is equal to the Term SOFR rate as published by the Chicago Mercantile Exchange, Inc., CME Group Inc. and their Affiliates or their successor as the administrator for Term SOFR two Business Days before commencement of such Interest Period, subject to SOFR adjustment periods one month: 0.10% three months: 0.15%, and six months: 0.25%), plus the applicable margin. The applicable margin ranges from 3% to 4% depending on the amount of loans and letters of credit outstanding. The Company is obligated to pay a quarterly commitment fee of 0.50% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding. The effective interest rate as of September 30, 2023 and December 31, 2022 was 8.7% and 7.4%, respectively.

6. Derivative Contracts

The Company uses derivative contracts to reduce exposure to fluctuations in commodity prices. These transactions are in the form of fixed price swaps. 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 Company reports the fair value of derivatives on the balance sheet in derivative contracts assets and derivative contracts liabilities as either current or noncurrent based on the timing of expected future cash flows of individual trades. See Note 7 for additional information regarding fair value measurements.

The following table summarizes the open financial derivative positions as of September 30, 2023, related to oil production:

Period	Volume (Mbbl)	Weighted Average Fixed Price
October 2023 – December 2023	149	$	83.56
January 2024 – June 2024	126	$	83.98

As of September 30, 2023 the Company has no natural gas volumes hedged due to offsetting swap positions of equal volumes.

Balance Sheet Presentation.The Company has master netting agreements with all of its derivative counterparties and presents its derivative assets and liabilities with the same counterparty on a net basis on the balance sheet. The following 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):

	September 30, 2023			December 31, 2022
Derivative contracts – current, gross	$	(729	)	$	(9,339	)
Netting arrangements		368			—
Derivative contracts – current, net	$	(361	)	$	(9,339	)

F-25

BCE-MACH LLC
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

6. Derivative Contracts (cont.)

Gains and Losses.The following table presents the settlement and mark-to-market (“MTM”) gains and losses presented as a loss or gain on derivatives in the statement of operations for the nine months ended September 30, 2023 and 2022 (in thousands):

	Nine Months Ended September 30,
	2023			2022
Settlements of oil derivatives	$	(2,967	)	$	(28,471	)
Settlements of natural gas derivatives		(298	)		(28,249	)
MTM gains (losses) on oil derivatives, net		4,860			13,743
MTM gains (losses) on natural gas derivatives, net		4,118			(3,804	)
Total gains (losses) on derivative contracts	$	5,713		$	(46,781	)

7. Fair Value Measurements

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

Level 1 —	Quoted prices are available in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2 —	Quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets.
Level 3 —	Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Fair Value on a Recurring Basis

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

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2023 and December 31, 2022 (in thousands):

	Level 1		Level 2			Level 3		Fair Value
As of September 30, 2023
Liabilities:
Commodity derivative instruments	$	—	$	(361	)	$	—	$	(361	)
As of December 31, 2022
Liabilities:
Commodity derivative instruments	$	—	$	(9,339	)	$	—	$	(9,339	)

F-26

BCE-MACH LLC
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

7. Fair Value Measurements (cont.)

Fair Value on a Non-Recurring Basis

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

Fair Value of Other Financial Instruments

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

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

8. Equity Compensation and Deferred Compensation Plan

As part of the Company’s LLC Agreement, incentive units (Class B Units) were issued to certain employees as compensation for services to be rendered to the Company. In determining the appropriate accounting treatment, the Company considered the characteristics of the awards in terms of treatment as stock-based compensation. US GAAP generally requires that all equity awards granted to employees be accounted for at fair value and recognized as compensation cost over the vesting period.

The incentive units are subject to graded vesting over a period of 3 or 4 years (subject to accelerated vesting, as defined by the incentive unit agreement) and a holder of incentive units forfeits unvested incentive units upon ceasing to be an employee of the Company, excluding limited exceptions. The Company recognizes forfeitures as they occur. Holders of incentive units will begin to participate in distributions upon the Company meeting a certain requisite financial internal rate of return threshold as defined in the LLC agreement.

As of September 30, 2023, 19,300 of the 20,000 authorized incentive units had been granted. As of September 30, 2023 there were no unvested units or unrecognized compensation costs. The Company did not recognize non-cash compensation for Class B Units for the nine months ended September 30, 2023 or 2022. As of September 30, 2023, there is no material unrecognized compensation cost related to incentive units.

9. Commitments and Contingencies

Legal Matters.In the ordinary course of business, the Company may at times be subject to claims and legal actions including, but not limited to, title disputes, royalty disputes, contract claims, personal injury claims and employment claims. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters. Nevertheless, actual outcomes may differ significantly from the Company’s assessment. As of September 30, 2023, the Company has accrued approximately $2.1million in accrued liabilities pertaining to these matters. Management does not expect that the impact of such matters will have a materially adverse effect on the Company’s financial position, results of operations or cash flows.

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

F-27

BCE-MACH LLC
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

9. Commitments and Contingencies (cont.)

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

NGL Sales and Gas Transportation Commitments.The Company is party to a NGL sales contract, which includes certain NGL volume commitments in the event the Company elects not to reduce its committed quantity, at its option. To the extent the Company does not deliver NGL volumes in sufficient quantities to meet the commitment and does not elect to reduce its committed quantity, it would be required to pay a deficiency fee. The Company is currently delivering at least the minimum volumes. Additionally, the Company has natural gas firm transportation agreements terminating in 2024. For the nine months ended September 30, 2023 and 2022, the Company incurred approximately $2.4 million and $2.3 million, respectively, of transportation charges under these agreements.

Contributions to 401(k) Plan.The Company sponsors a 401(k) plan under which eligible employees may contribute a portion of their total compensation up to the maximum pre-tax threshold through salary deferrals. The plan provides a company match on 100% of salary deferrals that do not exceed 10% of compensation. The Company contributed $0.9 million and $0.7 million for the nine months ended September 30, 2023 and 2022, respectively.

10. Leases

Nature of Leases

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 2027. The vehicles are used for field operations and leased from third parties. The Company recognizes right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year. Short-term leases that have an initial term of one year or less are not capitalized.

Discount Rate

As most of the Company’s leases do not provide an implicit rate, the Company uses 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 September 30, 2023, were as follows (in thousands):

Remaining 2023	$	427
2024		1,371
2025		975
2026		246
2027		7
Total lease payments	$	3,026
Less: imputed interest		(120	)
Total	$	2,906

F-28

BCE-MACH LLC
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

10. Leases (cont.)

The following table summarizes our total lease costs before amounts are recovered from our joint interest partners, where applicable, for the nine months ended September 30, 2023 and 2022 (in thousands):

	Nine Months Ended September 30,
	2023		2022
Operating lease cost	$	1,284	$	590
Short-term lease cost		4,702		3,835
Total lease cost	$	5,986	$	4,425

The weighted-average remaining lease term as of September 30, 2023 was 2.22 years. The weighted-average discount rate used to determine the operating lease liability as of September 30, 2023 was 3.7%.

	Nine Months Ended September 30,
	2023		2022
Operating cash flows from operating leases	$	1,266	$	507

11. Members’ Equity

Upon formation, the Company issued 124,000 Class A-1 Units to BCE-Mach Holdings LLC and 8,000 Class A-2 Units to Mach Resources LLC. The Company issued 26,437 Class A-3 Units to BCE-Mach Holdings LLC and 313 Class A-3 Units to Mach Resources LLC for additional capital contributed throughout 2020. As part of the amended and restated LLC agreement holders of class A-3 Units are entitled to 100% of all distributions until a 1.0x return on invested capital has been met. On March 25, 2021, per the Amended and Restated LLC Agreement, the Company issued 2,351 Class A-2 Units to an employee of MR for services performed for the Company. Additionally, Class A-2 Units were granted to the employee on a quarterly basis throughout 2021. During 2021 there were 3,135 total Class A-2 Units issued to the employee, which have substantially all the same rights as the equity holders. In 2022, the Class A-2 Issuance Agreement was updated and there are no additional units being granted to the employee. As of September 30, 2023 there were 11,438 Class A-2 Units issued and outstanding.

As part of a long-term incentive plan for certain employees, 19,300 Class B Units were outstanding as of September 30, 2023 and 2022. The Class B Units represent a non-voting interest in the Company that allows the holder to participate in distributions once the Company’s Class A shares have met a certain requisite financial internal rate of return in accordance with the LLC agreement.

Distributions to the Company’s members were $10.0 million for the nine months ended September 30, 2023 and there were no distributions made for the nine months ended September 30, 2022.

12. Related Party Transactions

Management Services Agreement.Upon formation of the Company, the Company entered into a management services agreement (“MSA”) with one of its Members, Mach Resources LLC (“MR”). Under the MSA, MR manages and performs all aspects of oil and gas operations and other general and administrative functions for the Company. On a monthly basis, the Company distributes funding to MR for performance under the MSA. During the nine months ended September 30, 2023 and 2022, the Company paid Mach Resources $29.2 million (inclusive of $2.0 million in management fees) and $17.8 million (inclusive of $0.9 million as management fees), respectively. As of September 30, 2023 the Company had $1.2 million in prepaid assets with MR. As of December 31, 2022 the Company owed $0.3 million to MR.

F-29

BCE-MACH LLC
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

12. Related Party Transactions (cont.)

BCE-Mach II LLC and BCE-Mach III LLC.    BCE-Mach II LLC and BCE-Mach III LLC are two related parties that also entered into a MSA with Mach Resources. These entities have shared ownership with the Company and operate primarily in different geographical locations than the Company. As of September 30, 2023 the Company has receivables from these related parties for approximately $0.2 million included in accounts receivable-joint interest and other. As of December 31, 2022 the Company had payables to these related parties for approximately $1.3 million included in accounts payable.

13. Subsequent Events

The Company has evaluated its financial statements for subsequent events through August13, 2024 the date the financial statements were available to be issued to ensure that any subsequent events that met the criteria for recognition and disclosure in this report have been properly included.

Corporate Reorganization

On October 25, 2023, the Company was reorganized as a subsidiary of Mach Natural Resources LP, who underwent an initial public offering. In the reorganization, the existing equity holders of BCE-Mach II LLC exchanged their equity units in exchange for limited partnership interests in the newly formed public company, Mach Natural Resources LP.

New Credit Facility

Subsequent to September 30, 2023, the Company’s credit facility was paid in full, terminated, and replaced with a credit facility entered into by Mach Natural Resources LP and MidFirst Bank.

Legal Matters

Subsequent to September30, 2023, the Company was party to a settlement agreement for certain litigation matters. The effects of this settlement have been recorded in the financial statements as of and for the period ended September30, 2023, and further information can be found in Note 9.

F-30

BCE-Mach II LLC
Unaudited Financial Statements
As of September 30, 2023 and December 31, 2022 and for the nine months ended September 30, 2023 and 2022

F-31

BCE-MACH II LLC
BALANCE SHEETS (UNAUDITED)
(in thousands)

	September 30, 2023			December 31, 2022
ASSETS
Current assets:
Cash and cash equivalents	$	9,127		$	19,303
Accounts receivable – joint interest and other, net		7,430			9,586
Accounts receivable – oil, gas, and NGL sales		3,882			10,326
Short-term derivative assets		82			737
Inventories		1,051			1,154
Other current assets		1,103			1,449
Total current assets		22,675			42,555
Oil and natural gas properties, using the full cost method:
Proved oil and natural gas properties		81,020			82,989
Less: accumulated depreciation, depletion, amortization, and impairment		(40,532	)		(38,024	)
Oil and natural gas properties, net		40,488			44,965
Other property, plant and equipment		11,474			11,418
Less: accumulated depreciation		(2,621	)		(2,102	)
Other property, plant and equipment, net		8,853			9,316
Other assets		133			235
Operating lease assets		1,153			1,113
Total assets	$	73,302		$	98,184
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,288		$	1,940
Accrued liabilities		4,248			3,212
Revenue payable		15,370			22,952
Current portion of operating lease liabilities		450			374
Total current liabilities		21,356			28,478
Long-term debt		17,100			17,100
Asset retirement obligations		19,145			18,499
Long-term portion of operating leases		704			524
Other long-term liabilities		408			739
Total long-term liabilities		37,357			36,862
Commitments and contingencies (Note 9)
Members’ equity:
Members’ equity		14,589			32,844
Total liabilities and members’ equity	$	73,302		$	98,184

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

F-32

BCE-MACH II LLC
STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands)

	Nine Months Ended September 30,
	2023			2022
Revenue
Oil, natural gas, and NGL sales	$	23,772		$	56,570
Gain (loss) on oil and natural gas derivatives		835			(4,345	)
Gathering revenue		319			359
Total revenues		24,926			52,584
Operating expenses
Gathering and processing		2,808			4,570
Gathering operating expense		350			348
Lease operating expense		9,926			9,905
Production taxes		1,142			3,266
Depreciation, depletion, amortization and accretion – oil and natural gas		3,320			3,365
Depreciation and amortization – other		519			499
General and administrative		(2,174	)		(2,199	)
Total operating expenses		15,891			19,754
Income from operations		9,035			32,830
Other (expense) income
Interest expense		(1,148	)		(630	)
Other income (expense), net		(1,937	)		12
Total other expense		(3,085	)		(618	)
Net income	$	5,950		$	32,212

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

F-33

BCE-MACH II LLC
STATEMENTS OF MEMBERS’ EQUITY (UNAUDITED)
(in thousands)

	Total Members’ Equity
Balance at December 31, 2022	$	32,844
Net income		5,950
Equity compensation		174
Distributions		(24,379	)
Balance at September 30, 2023	$	14,589
Balance at December 31, 2021	$	29,082
Net income		32,212
Equity compensation		507
Distributions	$	(23,700	)
Balance at September 30, 2022	$	38,101

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

F-34

BCE-MACH II LLC
STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)

	Nine Months Ended September 30,
	2023			2022
Cash flows from operating activities
Net income	$	5,950		$	32,212
Adjustments to reconcile net income to cash provided by operating activities
Depreciation, depletion, amortization and accretion		3,839			3,864
Gain (loss) on derivative instruments		(835	)		4,345
Cash receipts (payments) on settlement of derivative contracts, net		1,448			(4,777	)
Debt issuance costs amortization		100			100
Equity based compensation		174			507
Credit losses		767			—
Settlement of asset retirement obligations		(33	)		(39	)
Changes in operating assets and liabilities (decreasing) increasing cash:
Accounts receivable		8,728			(5,441	)
Revenue payable		(7,582	)		6,100
Accounts payable and accrued liabilities		460			390
Other		(593	)		(842	)
Net cash provided by operating activities		12,423			36,419
Cash flows from investing activities
Capital expenditures for oil and natural gas properties		(357	)		(562	)
Capital expenditures for other property and equipment		(56	)		46
Acquisition of assets		—			(13,617	)
Proceeds from sales of other property and equipment		2,193			—
Net cash provided by (used in) investing activities		1,780			(14,133	)
Cash flows from financing activities
Distributions to members		(24,379	)		(23,700	)
Repayments of borrowings		—			(4,500	)
Net cash used in financing activities		(24,379	)		(28,200	)
Net decrease in cash and cash equivalents		(10,176	)		(5,914	)
Cash and cash equivalents, beginning of period		19,303			29,588
Cash and cash equivalents, end of period	$	9,127		$	23,674

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

F-35

BCE-Mach II LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. Organization and Nature of Business

BCE-Mach II LLC (“the Company”) was formed on October 26, 2018, as a limited liability company under the laws of the State of Delaware. On July 9, 2019, the Company entered into the original LLC agreement with its initial member. An employee was admitted as a member of the Company in the LLC agreement as amended and restated on March 25, 2021. On September 13, 2019, and September 27, 2019, the Company closed on two acquisitions and operations subsequently began. The Company owns and operates producing wells and undeveloped acreage primarily in the Anadarko Basin in both Texas and Oklahoma.

2. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The unaudited financial statements included herein were prepared from records of the Company in accordance with generally accepted accounting principles in the United States (“US GAAP”). These financial statements should be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2022. Results for interim periods are not necessarily indicative of results to be expected for the full year ending December 31, 2023. 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.

Use of Estimates

The preparation of the financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, 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.

Cash and Cash Equivalents

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

Accounts Receivable

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

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

F-36

BCE-Mach II LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

2. Basis of Presentation and Summary of Significant Accounting Policies (cont.)

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 September 30, 2023 and December 31, 2022, the allowance for credit losses related to joint interest receivables and the credit losses related to sales of oil and natural gas was not material.

Derivative Instruments

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

Oil and Natural Gas Operations

The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, costs of both successful and unsuccessful exploration and development activities are capitalized as proved oil and natural gas properties. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities, which are expensed as incurred. Capitalized costs are depreciated using the unit of production method. Under this method, depletion is computed at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by a net equivalent proved reserves at the beginning of the period. The average depletion rate per barrel equivalent unit of production was $1.94 and $1.83 for the nine months ended September 30, 2023 and 2022, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $2.5 million and $2.6 million for the nine months ended September 30, 2023 and 2022, respectively.

Under the full cost method, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization, may not exceed the full cost “ceiling” at the end of each reporting period. The ceiling is calculated based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10%. The estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and natural gas properties. Estimated future net cash flows are calculated using the preceding 12-months’ average price based on closing prices on the first day of each month. The net book value is compared to the ceiling limitation on a quarterly basis. The excess, if any, of the net book value above the ceiling limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. The ceiling limitation computation is determined without regard to income taxes due to the Internal Revenue Service (“IRS”) recognition of the Company as a flow-through entity. No impairments on proved oil and natural gas properties were recorded for the nine months ended September 30, 2023 and 2022.

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

F-37

BCE-Mach II LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

2. Basis of Presentation and Summary of Significant Accounting Policies (cont.)

assigned. As of September 30, 2023, and December 31, 2022, 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, Net

Other property and equipment primarily consists of a gathering system, computer equipment and software, office furniture, and an office building for field operations. Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed as incurred. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from two to 39 years. Depreciation expense for other property and equipment was $0.5 million and $0.5 million for the nine months ended September 30, 2023 and 2022, respectively.

Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. No impairment of other property and equipment was recorded for the nine months ended September 30, 2023 or 2022.

Inventories

Inventories are stated at the lower of cost or net realizable value and consist of production equipment not placed in service as of September 30, 2023 and December 31, 2022. The Company’s equipment is primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations.

Debt Issuance Costs

Other assets include capitalized costs related to the credit facility of $0.7 million, net of accumulated amortization of $0.5 million as of September 30, 2023. As of December 31, 2022, Other assets include capitalized costs related to the credit facility of $0.7 million, net of accumulated amortization of $0.4 million. These costs are being amortized over the terms of the related credit agreements and are reported as interest expense on the Company’s statement of operations.

Income Taxes

The Company is an LLC taxed as a partnership, and any associated tax liability is the responsibility of the individual members of the LLC. Accordingly, no provision for income taxes has been made in these financial statements.

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 nine months ended September 30, 2023. The Company’s tax years 2022, 2021, and 2020 remain open for examination by state authorities.

F-38

BCE-Mach II LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

2. Basis of Presentation and Summary of Significant Accounting Policies (cont.)

General and Administrative Costs

General and administrative expenses include cost recovery from joint interest owners. Per the terms of the joint operating agreements with working interest owners, the Company has the right to recover costs using an established contractual rate. Recoveries for the nine months ended September 30, 2023, and 2022 were $4.7 million and $4.9 million, respectively.

Asset Retirement Obligations

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

The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future downhole plugging, dismantlement and removal of production equipment and facilities, and the restoration and reclamation of a field’s surface to a condition similar to that existing before oil and natural gas extraction or 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 nine months ended September 30, 2023 and 2022 (in thousands):

	September 30, 2023			September 30, 2022
Asset retirement obligation at beginning of period	$	18,499		$	16,469
Liabilities incurred		4			509
Liabilities settled		(127	)		(136	)
Liabilities revised		(43	)		635
Accretion expense		812			769
Asset retirement obligation at end of period	$	19,145		$	18,246

Revenue Recognition

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.

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and the Company expects this volatility to continue in the future. The prices the Company receives for production depend on many factors outside of our control. See Note 6 for a discussion of the Company’s management of price volatility.

F-39

BCE-Mach II LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

2. Basis of Presentation and Summary of Significant Accounting Policies (cont.)

Oil Sales

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

Natural Gas and NGL Sales

Under the Company’s natural gas and NGL sales contracts, it first delivers wet natural gas to a midstream processing entity. After processing, the residue gas is transported to the purchaser at the inlet to certain natural gas pipelines, where the purchaser takes control, title and risk of loss of the product. 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.

Gathering Revenue

The Company’s gathering revenue is generated from a majority owned gathering system acquired in one of the Company’s acquisitions. The Company charges a gathering rate per MMBtu transported through the gathering system. Gathering revenue and gathering operating expense are recorded net of the Company’s ownership interest in the system.

Transaction Price Allocated to Remaining Performance Obligations

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

Prior-Period Performance Obligations

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

F-40

BCE-Mach II LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

2. Basis of Presentation and Summary of Significant Accounting Policies (cont.)

Concentrations

The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. The following purchasers each accounted for more than 10% of the Company’s revenues for the nine months ended September 30, 2023 and 2022:

	Nine Months Ended September 30,
	2023		2022
ETC Field Services LLC	20.6	%	23.9	%
NextEra Energy Marketing, LLC	15.3	%	18.8	%
Wheeler Midstream LLC	14.5	%	11.2	%
Enbridge Inc	10.2	%	*

____________

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

The Company’s receivables as of September 30, 2023 and 2022 from oil and gas sales are concentrated with the same counterparties noted above. The Company does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

As of September 30, 2023 and December 31, 2022, the Company had one customer that represented approximately 55.1% and 63.0% of our total joint interest receivables.

Revenue Disaggregation

The following table displays the revenue disaggregated and reconciles disaggregated revenue to the revenue reported for the nine months ended September 30, 2023 and 2022 (in thousands):

	Nine Months Ended September 30,
	2023			2022
Revenues:
Oil	$	7,873		$	11,405
Natural gas		11,119			33,348
NGL		6,045			12,999
Gross oil, natural gas, and NGL sales		25,037			57,752
Transportation, gathering and marketing		(1,265	)		(1,182	)
Net oil, natural gas, and NGL sales	$	23,772		$	56,570

Supplemental Cash Flow Information

Supplemental disclosures to the statements of cash flows are presented below for the nine months ended September 30, 2023 and 2022 (in thousands):

	Nine Months Ended September 30,
	2023		2022
Supplemental disclosure of cash flow information:
Cash paid for interest	$	1,059	$	517
Supplemental disclosure of non-cash transactions:
Change in accrued capital expenditures	$	—	$	(61	)
Asset retirement cost capitalized	$	4	$	509
Right-of-use assets obtained in exchange for lease liabilities	$	303	$	1,330

F-41

BCE-Mach II LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

2. Basis of Presentation and Summary of Significant Accounting Policies (cont.)

Recent Accounting Pronouncements Adopted

In June 2016, the FASB issued Accounting Standards Update 2016-13, “Financial Instrument-Credit Losses: Measurement of Credit Losses on Financial Instruments,” which amends reporting guidance on credit loses for certain financial instruments. The Company’s primary risk for credit losses related to its receivables from joint interest owners in our operated oil and natural gas wells. This guidance is effective for periods after December 15, 2022, and the Company implemented it effective January 1, 2023, with no material impacts to the financial statements.

3. Property and Equipment

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

	September 30, 2023			December 31, 2022
Oil and natural gas properties
Proved properties	$	81,020		$	82,989
Accumulated depreciation and depletion		(40,532	)		(38,024	)
Oil and natural gas properties, net		40,488			44,965
Other property and equipment
Gathering system	$	8,600		$	8,600
Buildings		1,918			1,907
Vehicles		497			453
Office equipment		139			138
Land		320			320
Total other property and equipment		11,474			11,418
Accumulated depreciation, depletion and amortization		(2,621	)		(2,102	)
Total other property and equipment, net	$	8,853		$	9,316

4. Accrued Liabilities

Accrued liabilities consist of the following (in thousands):

	September 30, 2023		December 31, 2022
Lease operating expense	$	1,307	$	1,998
Payroll costs		664		895
General, administrative, and other		2,277		319
Total accrued liabilities	$	4,248	$	3,212

5. Long-Term Debt

The Company maintains a revolving credit facility (“the Credit Facility”) with a syndicate of banks, including East West Bank, who serves as sole book runner and lead arranger, maturing in September 2024. Outstanding obligations under the Credit Facility are secured by substantially all of the Company’s assets.

The credit agreement provides for a revolving Credit Facility in the maximum of $250.0million, subject to a borrowing base of $26.0 million as of September 30, 2023. As of September 30, 2023, $17.1million was outstanding under the Credit Facility. The amount available to be borrowed under the Credit Facility is subject to a borrowing base that is redetermined semiannually each April and October in an amount determined by the lenders. The Company’s borrowing base was last affirmed at $26.0 million in conjunction with the April 2023 re-determination.

F-42

BCE-Mach II LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

5. Long-Term Debt (cont.)

The Company entered into the fourth amendment to the credit agreement on December 8, 2022. The fourth amendment includes an excess cash threshold that sets a limit of the consolidated cash balance of the Company at $5.0. Excess cash will be swept only when the Company experiences an “anti-cash triggering event” defined as one or more of the following:

•Ratio of total debt to EBITDAX greater than 2.5 evaluated each fiscal quarter;

•Liquidity is less than 20% of the borrowing base; and

•An event of default or borrowing base deficiency occurs.

The consolidated cash balance is defined as the total unrestricted cash and cash equivalents held by the Company, less any cash set aside to pay royalty obligations, working interest obligations, suspense payments, severance taxes, payroll, payroll taxes, other taxes, employee wage and benefits.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios. Financial ratios the Company is required to maintain on a quarterly basis include the ratio of total debt to EBITDAX not greater than 2.5 and the ratio of current assets to current liabilities of no less than 1.0. As of September 30, 2023, and December 31, 2022, the Company was in compliance with all applicable covenants under the credit facility.

Outstanding borrowings under the credit agreement bear interest at a per annum rate that is equal to the SOFR rate (which is equal to the Term SOFR rate as published by the Chicago Mercantile Exchange, Inc., CME Group Inc. and their Affiliates or their successor as the administrator for Term SOFR two Business Days before commencement of such Interest Period, subject to SOFR adjustment periods one month: 0.10%, three months: 0.15%, and six months: 0.25%), plus the applicable margin. The applicable margin ranges from 1.25% to 2.25% in the case of the alternate base rate and from 2.25% to 3.25% in the case of SOFR, in each case depending on the amount of loans and letters of credit outstanding. The Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding. The effective interest rate as of September 30, 2023, and December 31, 2022, was 8.4% and 7.3%, respectively.

6. Derivative Contracts

The Company uses derivative contracts to reduce exposure to fluctuations in commodity prices. These transactions are in the form of fixed price swaps. 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 Company reports the fair value of derivatives on the balance sheet in derivative contracts assets and derivative contracts liabilities as either current or noncurrent based on the timing of expected future cash flows of individual trades. See Note 7 for additional information regarding fair value measurements.

F-43

BCE-Mach II LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

6. Derivative Contracts (cont.)

The following table summarizes the open financial derivative positions as of September 30, 2023, related to oil production:

Period	Volume (Mbbl)	Weighted Average
October 2023 – December 2023	21	$	83.56
January 2024 – June 2024	18	$	83.98

As of September 30, 2023 the Company has no natural gas volumes hedged due to offsetting swap positions of equal volumes.

Balance Sheet Presentation.The Company has master netting agreements with all of its derivative counterparties and presents its derivative assets and liabilities with the same counterparty on a net basis on the balance sheet. The following 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):

	September 30, 2023			December 31, 2022
Derivative contracts – current, gross	$	184		$	737
Netting arrangements		(102	)		—
Derivative contracts – current, net	$	82		$	737

Gains and Losses.The following table presents the settlement and mark-to-market (“MTM”) gains and losses presented as a loss or gain on derivatives in the statement of operations for the nine months ended September 30, 2023 and 2022 (in thousands):

	Nine Months Ended September 30,
	2023			2022
Settlements of oil derivatives	$	295		$	(2,952	)
Settlements of natural gas derivatives		1,195			(1,894	)
MTM gains (losses) on oil derivatives, net		(102	)		1,397
MTM gains (losses) on natural gas derivatives, net		(553	)		(896	)
Total gains (losses) on derivative contracts	$	835		$	(4,345	)

7. Fair Value Measurements

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

Level 1 —	Quoted prices are available in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2 —	Quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets.
Level 3 —	Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.

F-44

BCE-Mach II LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

7. Fair Value Measurements (cont.)

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Fair Value on a Recurring Basis

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

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2023 and December 31, 2022 (in thousands):

	Level 1		Level 2		Level 3		Fair Value
As of September 30, 2023
Assets:
Commodity derivative instruments	$	—	$	82	$	—	$	82
As of December 31, 2022
Assets:
Commodity derivative instruments	$	—	$	737	$	—	$	737

Fair Value on a Non-Recurring Basis

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

Fair Value of Other Financial Instruments

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

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

8. Equity Compensation and Deferred Compensation Plan

As part of the Company’s Amended and Restated LLC Agreement as of March 25, 2021, incentive units (Class B Units) were issued to certain employees as compensation for services to be rendered to the Company. In determining the appropriate accounting treatment, the Company considered the characteristics of the awards in terms of treatment as stock-based compensation. US GAAP generally requires that all equity awards granted to employees be accounted for at fair value and recognized as compensation cost over the vesting period.

The incentive units are subject to graded vesting over a period of 3 or 4 years (subject to accelerated vesting, as defined by the incentive unit agreement) and a holder of incentive units forfeits unvested incentive units upon ceasing to be an employee of the Company, excluding limited exceptions. The Company recognizes forfeitures as they occur. Holders of incentive units participate in distributions upon the Company meeting a certain requisite financial internal rate of return threshold as defined in the amended LLC agreement.

F-45

BCE-Mach II LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

8. Equity Compensation and Deferred Compensation Plan (cont.)

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 awards granted for 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:

•expected volatility based on the historical volatilities of similar sized companies that most closely represent the Company’s business of 62%;

•7 year expected term determined by management based on experience with similarly organized company and expectation of a future sale of the business; and

•a risk-free rate based on a U.S Treasury yield curve of 1.40%.

On March 25, 2021, all 20,000 authorized incentive units were granted. Total non-cash compensation cost related to the incentive units was $0.2 million and $0.5 million for the six months ended September 30, 2023, and 2022, respectively. As of September 30, 2023, there was $0.1 million in unrecognized compensation cost related to incentive units, which is expected to be recognized over a weighted-average period of 0.3 years.

A summary of the incentive unit awards as of September 30, 2023, and 2022 is as follows:

	Class B Units		Weighted Average Grant Date Fair Value
Unvested at December 31, 2021	10,333		$	213.39
Vested	(3,665	)	$	213.39
Unvested at September 30, 2022	6,668		$	213.39
Unvested at December 31, 2022	6,668		$	213.39
Vested	(3,667	)	$	213.39
Unvested at September 30, 2023	3,001		$	213.39

9. Commitments and Contingencies

Legal Matters.In the ordinary course of business, the Company may at times be subject to claims and legal actions including, but not limited to, title disputes, royalty disputes, contract claims, personal injury claims and employment claims. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters. Nevertheless, actual outcomes may differ significantly from the Company’s assessment. As of September30, 2023, the Company has accrued approximately $1.3million in accrued liabilities pertaining to these matters. Management does not expect that the impact of such matters will have a materially adverse effect on the Company’s financial position, results of operations or cash flows.

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

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

F-46

BCE-Mach II LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

9. Commitments and Contingencies (cont.)

Contributions to 401(k) Plan.The Company sponsors a 401(k) plan under which eligible employees may contribute a portion of their total compensation up to the maximum pre-tax threshold through salary deferrals. The plan provides a company match on 100% of salary deferrals that do not exceed 10% of compensation. We contributed $0.4 million and $0.4 million for the nine months ended September 30, 2023 and 2022, respectively.

10. Leases

Nature of Leases

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 2027. The vehicles are used for field operations and leased from third parties. The Company recognizes right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year. Short-term leases that have an initial term of one year or less are not capitalized.

Discount Rate

As most of the Company’s leases do not provide an implicit rate, the Company uses 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 September 30, 2023, were as follows (in thousands):

Remaining 2023	$	125
2024		472
2025		430
2026		176
2027		11
Total lease payments	$	1,214
Less: imputed interest		(60	)
Total	$	1,154

The following table summarizes our total lease costs before amounts are recovered from our joint interest partners, where applicable, for the nine months ended September 30, 2023 and 2022 (in thousands):

	Nine Months Ended September 30,
	2023		2022
Operating lease cost	$	356	$	142
Short-term lease cost		1,824		2,121
Total lease cost	$	2,180	$	2,263

The weighted-average remaining lease term as of September 30, 2023 was 2.62 years. The weighted-average discount rate used to determine the operating lease liability as of September 30, 2023 was 4.0%.

	Nine Months Ended September 30,
	2023		2022
Operating cash flows from operating leases	$	352	$	109

F-47

BCE-Mach II LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

11. Members’ Equity

Upon formation, the Company consisted of one class of common interests that were all owned by its initial member, BCE-Mach Holdings II. On March 25, 2021, per the Amended and Restated LLC Agreement and the Class A-2 Issuance Agreement, the Company issued 76,500 Class A-1 Units to the initial member, and 480 Class A-2 Units to an employee of MR for services performed for the Company. Additionally, Class A-2 Units were granted to the employee on a quarterly basis throughout 2021. In 2022, the Class A-2 Issuance Agreement was updated and there are no additional units being granted to the employee. As of September 30, 2022, there were 788 total Class A-2 Units issued to the employee, which have substantially all the same rights as the initial member. As part of a long-term incentive plan for certain employees, 20,000 Class B Units were outstanding as of September 30, 2022. The Class B Units represent a non-voting interest in the Company that allows the holder to participate in distributions once the Company’s Class A shares have met a certain requisite financial internal rate of return in accordance with the LLC agreement.

Distributions to the members for the nine months ended September 30, 2023 and 2022 were $24.4 million and $23.7 million, respectively. There were no contributions from the members for the nine months ended September 30, 2023, or 2022.

12. Related Party Transactions

Management Services Agreement.Upon formation of the Company, the Company entered into a management services agreement (“MSA”) with Mach Resources LLC (“MR”). Under the MSA, MR manages and performs all aspects of oil and gas operations and other general and administrative functions for the Company. On a monthly basis, the Company distributes funding to MR for performance under the MSA. During the nine months ended September 30, 2023, the Company paid MR $9.1 million, which was inclusive of $0.4 million in management fees. During the nine months ended September 30, 2022, the Company paid MR $8.1 million, which was inclusive of $0.2 million in management fees. As of September 30, 2023, and December 31, 2022, the Company had $0.6 million and $0.2 million in prepaid assets with MR, respectively.

BCE-Mach LLC and BCE-Mach III LLC.    BCE-Mach LLC and BCE-Mach III LLC are two related parties that also entered into a MSA with Mach Resources. These entities have shared ownership with the Company and operate primarily in different geographical locations than the Company. As of September 30, 2023 and December 31, 2022, the Company has receivables from these related parties for approximately $0.8 million and $0.5 million included in accounts receivable-joint interest and other, respectively.

13. Subsequent Events

The Company has evaluated its financial statements for subsequent events through August13, 2024 the date the financial statements were available to be issued to ensure that any subsequent events that met the criteria for recognition and disclosure in this report have been properly included.

Corporate Reorganization

On October 25, 2023, the Company was reorganized as a subsidiary of Mach Natural Resources LP, who underwent an initial public offering. In the reorganization, the existing equity holders of BCE-Mach II LLC exchanged their equity units in exchange for limited partnership interests in the newly formed public company, Mach Natural Resources LP.

New Credit Facility

Subsequent to September 30, 2023, the Company’s credit facility was paid in full, terminated, and replaced with a credit facility entered into by Mach Natural Resources LP and MidFirst Bank.

Legal Matters

Subsequent to September30, 2023, the Company was party to a settlement agreement for certain litigation matters. The effects of this settlement have been recorded in the financial statements as of and for the period ended September30, 2023, and further information can be found in Note 9.

F-48

Mach Natural Resources LP

7,853,403Common Units

Representing Limited Partner Interests

Joint Book-Running Managers

Raymond James Stifel Truist Securities

Co-Managers

Johnson Rice & Company Stephens Inc.

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

	Amount to Be Paid
SEC registration fee	$	25,461
FINRA filing fee		26,375
NYSE supplemental filing fee		43,350
Accountants’ fees and expenses		175,000
Legal fees and expenses		750,000
Engineering expenses		30,000
Printing and engraving expenses		32,000
Transfer agents’ fees and expenses		10,000
Total	$	1,092,186

Each of the amounts set forth above, other than the SEC registration fee, the NYSE supplemental listing fee and the FINRA filing fee, is an estimate. The Registrant will pay all of the expenses of this offering listed above.

Item 14. Indemnification of Directors and Officers.

Mach Natural Resources

Subject to any terms, conditions or restrictions set forth in our partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against any and all claims and demands whatsoever. The section of the prospectus entitled “Description of the Partnership Agreement — Indemnification” discloses that we will indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by law against all losses, claims, damages or similar events, unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the applicable person acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal, and is incorporated herein by this reference.

The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for the indemnification of Mach Natural Resources and our general partner, their officers and directors, and any person who controls our general partner, including indemnification for liabilities under the Securities Act.

Mach Natural Resources GP LLC

Subject to any terms, conditions or restrictions set forth in the general partner agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

Under the general partner agreement, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):

•any person who is or was an affiliate of our general partner (other than us and our subsidiaries);

•any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any affiliate of our general partner;

II-1

•any person who is or was serving at the request of our general partner or any affiliate of our general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person; and

•any person designated by our general partner.

Our general partner has purchased insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

Item 15. Recent Sales of Unregistered Securities.

Prior to closing of the initial public offering, the Company entered into a series of reorganization transactions pursuant to which all of BCE-Mach Aggregator, management members and Mach Resources’ respective membership interests in the Mach Companies were exchanged for a pro rata allocation of 100% of the limited partner interests in the Company.

The above issuances did not involve any underwriters, underwriting discounts or commissions, or any public offering and we believe such issuances are exempt from the registration requirements of the Securities Act by virtue of Section 4(a)(2) thereof.

Item 16. Exhibits and Financial Statement Schedules.

(a)The list of exhibits set forth under “Exhibit Index” at the end of this Registration Statement is incorporated by reference.

(b)No financial statement schedules are provided because the information called for is not required or is shown either in the financial statements or the notes thereto.

Item 17. Undertakings.

The undersigned Registrant hereby undertakes that:

(a)Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

(b)For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b) (1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(c)For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(d)For purposes of determining any liability under the Securities Act, each filing of the registrant’s annual report pursuant to section 13(a) or section 15(d) of the Exchange Act (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to section 15(d) of the Exchange Act) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-2

EXHIBIT INDEX

Exhibit Number	Description
1.1*	Form of Underwriting Agreement.
2.1†	Purchase and Sale Agreement, dated as of November 10, 2023, by and among Excalibur Resources, LLC, Travis Peak Resources, LLC, Paloma Partners IV, LLC and TPR Mid-Continent, LLC, as sellers, and Mach Natural Resources LP, as buyer (incorporated by reference to Exhibit 2.1 of the Company’s Form 8-K filed on November 13, 2023).
3.1	Certificate of Limited Partnership of Mach Natural Resources LP (incorporated by reference to Exhibit 3.1 to the Company’s Form S-1 (File No. 333-274662) filed on September 22, 2023).
3.2	Amended and Restated Agreement of Limited Partnership of Mach Natural Resources LP (incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K filed on October 27, 2023).
3.3	Amended and Restated Limited Liability Company Agreement of Mach Natural Resources GP, LLC (incorporated by reference to Exhibit 3.3 of the Company’s Form 10-Q filed on December 7, 2023).
3.4	Amendment No. 1 to the Amended and Restated Agreement of Limited Partnership of Mach Natural Resources LP, dated as of June 13, 2024 (incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K filed on June 13, 2024).
5.1*	Opinion of Kirkland & Ellis LLP.
8.1*	Opinion of Kirkland & Ellis LLP relating to tax matters.
10.1††	Mach Natural Resources LP 2023 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 of the Company’s Form 8-K filed on October 27, 2023).
10.2	Form of Mach Natural Resources LP 2023 Long-Term Incentive Plan Phantom Unit Agreement (Non-Employee Directors) (incorporated by reference to Exhibit 4.4 of the Company’s Form S-8 filed on October 27, 2023).
10.3	Form of Mach Natural Resources LP 2023 Long-Term Incentive Plan Phantom Unit Agreement (Executives) (incorporated by reference to Exhibit 4.5 of the Company’s Form S-8 filed on October 27, 2023).
10.4	Contribution Agreement, dated October 13, 2023, by and among Mach Natural Resources LP, Mach Natural Resources Holdco LLC, Mach Natural Resources Intermediate LLC and the other contributors party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed on October 27, 2023).
10.5	Management Services Agreement, dated October 27, 2023, by and between Mach Natural Resources LP and Mach Resources LLC (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed on October 27, 2023).
10.6	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to the Company’s Registration Statement on Form S-1, filed on September 29, 2023, File No. 333-274662).
10.7	Term Loan Credit Agreement, dated December 28, 2023, among Mach Natural Resources LP, the guarantors party thereto, the lenders party thereto, Texas Capital Bank, as the administrative agent, and Chambers Energy Management, LP, as the loan commitment arranger (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed on December 29, 2023).
10.8	First Amendment to Term Loan Credit Agreement, dated August 26, 2024, among Mach Natural Resources LP, the guarantors party thereto, the lenders party thereto, Texas Capital Bank, as the administrative agent, and Chambers Energy Management, LP, as the loan commitment arranger (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed on August 30, 2024).
10.9	Revolving Credit Agreement, dated December 28, 2023, among Mach Natural Resources LP, the guarantors party thereto, the lenders party thereto and MidFirst Bank, as the administrative agent (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed on December 29, 2023).
10.10	First Amendment to Revolving Credit Agreement, dated August 26, 2024, among Mach Natural Resources LP, the guarantors party thereto, the lenders party thereto and MidFirst Bank, as the administrative agent (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed on August 30, 2024).
10.11	Third Amendment to Credit Agreement, among BCE-Mach III LLC, as borrower, BCE-Mach III Midstream Holdings LLC, as guarantor, the several lenders from time to time parties thereto, and MidFirst Bank as administrative agent, collateral agent issuing bank and lender, dated January 27, 2023 (incorporated by reference to Exhibit 10.14 to the Company’s Form S-1 (File No. 333-274662) filed on September 22, 2023).

II-3

Exhibit Number	Description
10.12	Amended and Restated Credit Agreement, dated November 10, 2023, among Mach Natural Resources Holdco LLC, as borrower, the several lenders from time to time parties thereto and MidFirst Bank, as administrative agent and collateral agent for the lenders (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed on November 10, 2023).
21.1	List of Subsidiaries of Mach Natural Resources LP (incorporated by reference to Exhibit 21.1 of the Company’s Form 10-K filed on April 1, 2024).
23.1*	Consent of Grant Thornton LLP for Mach Natural Resources LP.
23.2*	Consent of Grant Thornton LLP for BCE-Mach LLC.
23.3*	Consent of Grant Thornton LLP for BCE-Mach II LLC.
23.4*	Consent of EEPB Company.
23.5*	Consent of Cawley, Gillespie & Associates.
23.6*	Consent of Kirkland & Ellis LLP (included in Exhibit 5.1).
24.1	Power of Attorney (included on signature page).
99.1	Report of Cawley, Gillespie & Associates of reserves of Mach Natural Resources LP, as of December 31, 2023 (incorporated by reference to Exhibit 21.1 of the Company’s Form 10-K filed on April 1, 2024).
99.2*	Report of Cawley, Gillespie & Associates of reserves for the Ardmore Basin Acquisition, as of July 31, 2024.
99.3*	Report of Cawley, Gillespie & Associates of reserves for the Western Kansas Acquisition, as of July 31, 2024.
107*	Filing Fee Table.

____________

*Filed herewith.

†Certain of the schedules and exhibits to the agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule or exhibit will be furnished to the SEC upon request.

††Management contract of compensatory plan or agreement.

II-4

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized in the City of Oklahoma City, State of Oklahoma, on September4, 2024.

Mach Natural Resources LP (Registrant)
By:	Mach Natural Resources GP LLC, its general partner
By:	/s/ Tom L. Ward
	Name:	Tom L. Ward
	Title:	Chief Executive Officer

Each person whose signature appears below appoints Tom L. Ward and Kevin R. White, and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys in fact and agents, with full power of substitution and resubstitution, for him or her and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys in fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or would do in person, hereby ratifying and confirming all that said attorneys in fact and agents or any of them or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities indicated below on September4, 2024.

Signature	Title
/s/ Tom L. Ward	Chief Executive Officer and Director
Tom L. Ward	(principal executive officer)
/s/ Kevin R. White	Chief Financial Officer
Kevin R. White	(principal financial officer and principal accounting officer)
/s/ William McMullen	Chairman of the Board
William McMullen
/s/ Edgar R. Giesinger	Director
Edgar R. Giesinger
/s/ Stephen Perich	Director
Stephen Perich
/s/ Francis A. Keating II	Director
Francis A. Keating II

II-5