As filed with the U.S. Securities and Exchange Commission on October 5, 2023.

Registration No. 333-274662

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

__________________________________________

Amendment No. 2
to

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 of the securities 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, a 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 that specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this Registration Statement shall become effective on such date as the Securities and Exchange 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, 2023

PRELIMINARY PROSPECTUS

Mach Natural Resources LP
Common Units
Representing Limited Partner Interests

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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. This is the initial public offering of the common units of Mach Natural Resources LP. We are offering common units representing limited partner interests. No public market currently exists for our common units. We expect the initial public offering price to be between $      and $     per common unit. We intend to apply to list our common units on the New York Stock Exchange,under the symbol “MNR.” We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act.

Investing in our common units involves risks. See “Risk Factors” beginning on page 27 of this prospectus.

These risks include the following:

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

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

•Unless we replace our produced reserves with acquired or developed new reserves, our reserves and production will decline, which would adversely affect our future cash flows, results of operations and cash available for distribution.

•Our operations are subject to stringent environmental laws and regulations that may affect our drilling and production operations and expose us to significant costs and liabilities that could exceed current expectations.

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

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

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

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

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

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PRICE $PER COMMON UNIT

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	Per Common Unit	Total
Public offering price	$	$
Underwriting discount(1)	$	$
Proceeds, before expenses	$	$

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(1)Includes an aggregate structuring fee equal to   % of the gross proceeds of this offering payable to Stifel, Nicolaus & Company, Incorporated and Raymond James & Associates, Inc. Please read “Underwriting.”

We have granted the underwriters a 30-day option to purchase up to an additionalcommon units on the same terms and conditions as set forth above if the underwriters sell more than   common units in this offering.

Neither the Securities and Exchange Commission 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.

The underwriters expect to deliver the common units on or about, 2023.

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Joint Book-Running Managers

Stifel Raymond James

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, 2023

TABLE OF CONTENTS

	Page
INDUSTRY AND MARKET DATA	iii
TRADEMARKS AND TRADE NAMES	iii
BASIS OF PRESENTATION	iv
PROSPECTUS SUMMARY	1
Risk Factor Summary	9
Risks Related to Cash Distributions	9
Risks Related to Our Business	9
Risks Inherent in an Investment in Us	10
Tax Risks to Common Unitholders	11
Reorganization Transactions, Partnership Structure and Expected Refinancing Transactions	11
Ownership and Organizational Structure of Mach Natural Resources	12
Management of Mach Natural Resources LP	13
Our Sponsor	14
Implications of Being an Emerging Growth Company	14
Principal Executive Offices and Internet Address	15
Summary of Conflicts of Interest and Duties	15
The Offering	17
Summary Historical and Pro Forma Financial and Operating Data	20
Non-GAAP Financial Measures	22
Summary of Reserve, Production and Operating Data	25
RISK FACTORS	27
Risks Related to Cash Distributions	27
Risks Related to Our Business	28
Risks Inherent in an Investment in Us	53
Tax Risks to Common Unitholders	63
USE OF PROCEEDS	68
CAPITALIZATION	69
DILUTION	70
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS	71
General	71
Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2022 and the Twelve Months Ended June 30, 2023	73
Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2024	75
Assumptions and Considerations	78
Sensitivity Analysis	84
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS	87
Distributions of Available Cash	87
Distributions of Cash Upon Liquidation	87
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA	88
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	90
BUSINESS AND PROPERTIES	119
MANAGEMENT	150
Management of Mach Natural Resources	150
Executive Officers and Directors of Our General Partner	150
Reimbursement of Expenses of Our General Partner	152
Board of Directors	152
Director Independence	153
Committees of the Board of Directors	153

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	Page
EXECUTIVE COMPENSATION AND OTHER INFORMATION	155
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	161
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	162
Distributions and Payments to Our General Partner and Its Affiliates	162
Agreements with Management	163
Agreements with Affiliates in Connection with the Reorganization Transactions	163
CONFLICTS OF INTEREST AND DUTIES	165
Conflicts of Interest	165
Duties of our General Partner	169
DESCRIPTION OF THE COMMON UNITS	172
The Units	172
Transfer Agent and Registrar	172
THE PARTNERSHIP AGREEMENT	174
Organization and Duration	174
Purpose	174
Capital Contributions	174
Limited Voting Rights	174
Applicable Law; Forum, Venue and Jurisdiction	175
Limited Liability	176
Issuance of Additional Partnership Interests	177
Amendment of the Partnership Agreement	178
Merger, Consolidation, Sale or Other Disposition of Assets	180
Termination and Dissolution	180
Liquidation and Distribution of Proceeds	181
Withdrawal or Removal of Our General Partner	181
Transfer of General Partner Interest	182
Transfer of Ownership Interests in Our General Partner	182
Election to be Treated as a Corporation	182
Change of Management Provisions	183
Limited Call Right	183
Meetings; Voting	183
Status as Limited Partner	184
Non-Citizen Unitholders; Redemption	184
Indemnification	184
Reimbursement of Expenses	185
Books and Reports	185
Right to Inspect Our Books and Records	185
Registration Rights	186
UNITS ELIGIBLE FOR FUTURE SALE	187
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES	189
INVESTMENT IN MACH NATURAL RESOURCES BY EMPLOYEE BENEFIT PLANS	209
UNDERWRITING	211
VALIDITY OF THE COMMON UNITS	215
EXPERTS	215
WHERE YOU CAN FIND MORE INFORMATION	215
FORWARD-LOOKING STATEMENTS	216
INDEX TO FINANCIAL STATEMENTS	F-1
APPENDIX A — AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF MACH NATURAL RESOURCES LP	A-1
APPENDIX B — GLOSSARY OF OIL AND GAS TERMS AND OTHER TERMS	B-1

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Neither we nor the underwriters have authorized anyone to provide you with any information or to make any representations other than those contained in this prospectus. We and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since such dates. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted.

Until , 2023 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

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 “Forward-Looking Statements.”

INDUSTRY AND MARKET DATA

The market data and certain other statistical information included in this prospectus are based on a variety of sources, including independent industry publications, government publications and other published independent sources. Some data is also based on our good faith estimates, which have been derived from management’s knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management’s knowledge and experience, we believe that these third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete. While we are not aware of any misstatements regarding the market, industry or similar data presented herein, such data involves risks and uncertainties and is subject to change based on various factors, including those discussed under the headings “Forward-Looking Statements” and “Risk Factors” in this prospectus.

TRADEMARKS AND TRADE NAMES

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

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BASIS OF PRESENTATION

Unless otherwise indicated, the historical financial information presented in this prospectus is that of BCE-Mach III LLC (“BCE-Mach III” or “predecessor”), a Delaware limited liability company, our predecessor for accounting purposes. The historical financial information of BCE-Mach LLC, a Delaware limited liability company, and BCE-Mach II LLC, a Delaware limited liability company, is also included herein as indicated.

This prospectus contains unaudited pro forma financial information, which presents certain financial information and operating data of our predecessor, BCE-Mach LLC and BCE-Mach II LLC on a pro forma combined basis to give effect to the initial public offering and the use of proceeds therefrom and the Reorganization Transactions as if they had occurred at the beginning of the periods presented. The production, reserve, acreage, well count, drilling locations, and other historical data in this prospectus are presented on a pro forma combined basis as if the Reorganization Transactions had occurred unless otherwise indicated.

Though the entities to be contributed in connection with the initial public offering and Reorganization Transactions have a high degree of common ownership, no individual or entity controls any of the entities and therefore the Reorganization Transactions are not accounted for as common control transactions.

Unless another date is specified, all production, reserve, acreage, well count and drilling location data presented in this prospectus is as of June 30, 2023.

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PROSPECTUS SUMMARY

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

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

Our Company

We are an independent upstream oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Anadarko Basin region of Western Oklahoma, Southern Kansas and the panhandle of Texas. Our experienced management team, led by industry veteran Tom L. Ward, possesses deep operational and industry experience, particularly in Oklahoma and the Anadarko Basin. We leverage our extensive experience to identify the most attractive exploitation and development opportunities and optimize the production of current wells, efficiently drill our existing inventory of undeveloped locations and identify attractive low-risk acquisition opportunities.

Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner, which we refer to as “available cash.” We believe the lower decline nature of our Legacy Producing Assets (as defined below) and large inventory of horizontal drilling locations with average royalty burdens of less than 25%, coupled with our lower cash operating costs and owned midstream infrastructure, will support our ability to make cash distributions to our unitholders. We expect to maintain a conservative capital structure with the long-term goal of remaining substantially debt free. Nevertheless, our quarterly cash distributions may vary from quarter to quarter as a direct result of variations in the performance of our business, including those caused by fluctuations in commodity prices. Any such variations may be significant, and as a result, we may pay limited or even no cash distributions to our unitholders.

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

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

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

We believe a key competitive advantage that we have over other operators is that we own an extensive portfolio of complementary midstream assets that are integrated with our upstream operations. These assets include gathering systems, processing plants and water infrastructure. Our midstream assets enhance the value of our properties by allowing us to optimize pricing, increase flow assurance and eliminate third-party costs and inefficiencies. In addition, our owned midstream systems generate third-party revenue, which effectively reduces the cost of operating our midstream assets and reduces our average breakeven costs compared to other operators. We believe the Anadarko Basin is uniquely positioned with legacy takeaway pipeline infrastructure enabling our oil, natural gas and NGLs to be easily transported to premium markets, such as Cushing, Oklahoma.

Our Properties

Our assets are located throughout Western Oklahoma, Southern Kansas and the panhandle of Texas and consist of approximately 4,500 gross operated PDP wells. Our average net daily production for the twelve months ended June30, 2023 was approximately 65 MBoe/d. We define our Focus Drilling Area assets as all of our horizontal properties that are located in Kingfisher and Logan Counties, Oklahoma, which we define as the Focus Drilling Area, and we define our “Legacy Producing Assets” as all of our legacy producing properties which are not in the Focus Drilling Area, as shown in the chart below. Based on our reserve report as of June30, 2023, 57% of our production is attributable to our Legacy Producing Assets, which have an average expected annual decline rate of approximately 15%. Our wells are located almost exclusively in the Anadarko Basin, which has a more predictable production profile compared to less mature basins. Our production benefits from both the diversity of our well vintage and the lack of concentration in any specific sub-area. Within our large and diversified PDP base, no single well accounts for more than 1% of our PDP PV-10.

Within our operating areas, our assets are prospective for multiple formations, most notably the Oswego, Meramec/Osage and Mississippi Lime formations. Our experience in the Anadarko Basin and these formations allows us to generate significant cash available for distribution from these low declining assets in a variety of commodity price environments.

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

Additionally, we own a portfolio of midstream assets which support our leases. As of June30, 2023, approximately 75% of our operated PDP reserves (and approximately 66% of our total PDP reserves) are supported by Company-owned midstream infrastructure.

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The following table presents our historical estimated oil, natural gas and NGL proved reserves as of June30, 2023.

	Estimated Proved Reserves
	Proved Developed Reserves(1)		Proved Reserves(1)		Estimated Probable Reserves(1)(2)
Oil (MBbl)		40,876		53,029		72,868
Natural gas (MMcf)		782,727		811,507		373,477
NGLs (MBbl)		50,190		50,911		19,576
Total equivalent (MBoe)(3)		221,520		239,191		154,690
PV-10 (in millions)(4)	$	2,131	$	2,435	$	1,039
Standardized Measure (in millions)(5)	$	2,131	$	2,435		—

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

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

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

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

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

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

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(1)Based on Management’s estimates.

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

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

The below table summarizes our identified horizontal drilling locations as of June30, 2023.

Target Horizontal Zones	Identified Horizontal Drilling Locations(1)(2)
	Focus Drilling Area Operated		Focus Drilling Area Non-Operated		Legacy Producing Assets		Total
Oswego	437		314		0		751
Meramec/Osage	265		228		0		493
Mississippi Lime	0		0		778		778
Total Horizontal Locations	702		542		778		2,022
Average Working Interest	82.6	%	16.4	%	29.7	%	44.5	%
Average Net Revenue Interest	69.0	%	14.1	%	24.0	%	37.0	%

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

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

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

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

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

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

Other Gas Gathering & Processing and Water Infrastructure

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

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

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

Development Plan and Capital Budget

Historically, our business plan has focused on acquiring and then exploiting the development and production of our assets. Funding sources for our acquisitions have included proceeds from borrowings under our revolving credit facilities, contributions from our equity partners and cash flow from operating activities. We spent approximately $290.6 million in 2022 on development costs and our budget for 2023 is approximately $316.2million (of which $207.6million has been incurred as of June30, 2023). For purposes of calculating our cash available for distribution, we define development costs as all of our capital expenditures, other than acquisitions. Our development efforts and capital for 2023 is focused on drilling Oswego wells given their high oil reserves and low breakeven costs.

During the year ended December 31, 2022, we spent approximately $270.2 million to drill 87.9 net wells and on related equipment, $9.1 million on remedial workovers and other capital projects, $11.3million on midstream and other property and equipment capital projects, and $142.9 million on acquisitions. During the six months ended June30, 2023, we spent approximately $182.0million to drill 50.4 net wells and on related equipment, $18.4million on remedial workovers and other capital projects, $7.2million on midstream and other property and equipment capital projects, and $1.5million on acquisitions.

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

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

Our Business Strategies

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

•Focus on low decline Legacy Producing Assets with additional meaningful horizontal development inventory.    Our ability to generate significant cash flow is supported by the predictable low decline production profile of our Legacy Producing Assets, which have an average expected annual decline rate of approximately 15%. Based on our reserve report as of June30, 2023, 57% of our production is attributable to our low decline Legacy Producing Assets. In addition, we believe we have the ability to maintain or modestly grow our average annual production with the development of our horizontal Focus Drilling Area inventory. We have identified over 2,000 horizontal drilling locations within our 936,000 net acre position, of which at a 10% internal rate of return, over 770 are currently economic at $50 per barrel of oil, over 1,100 at $70 per barrel of oil and over 2,000 at $90 per barrel of oil, each assuming a flat natural gas price per Mcf of 1/20th of the assumed oil price.

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

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

•Maintain low operating cost structure to support meaningful cash available for distribution.    Our average cash operating costs during the twelve months ended June30, 2023, including the benefit of our midstream infrastructure assets, were $12.51 per barrel of oil equivalent, which is 16% lower on average than other unconventional focused operators, and 58% lower on average than other conventional focused operators during the same period. We believe that our low cost structure will help enable us to make unitholder cash distributions during a negative commodity cycle.

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

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

Our Strengths

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

•Strong production and cash flow across a large acreage position.    Our average net daily production for the twelve months ended June30, 2023 was approximately 65 MBoe/d, with approximately 4,500 gross operated wells, and an average working interest of approximately 75%. We own extensive acreage in the Anadarko Basin, with approximately 936,000 net acres, approximately 99% of which is held by production. We believe our large acreage position enables us to optimize our development plan and support significant cash flow generation. For the six months ended June30, 2023 and year ended December31, 2022, on a pro forma basis, we generated $196million and $639million of net income, respectively, $256million and $714million of Adjusted EBITDA, respectively, and $43million and $402million of cash available for distribution, respectively. See “— Non-GAAP Financial Measures” and “Our Cash Distribution Policy and Restrictions on Distributions — Unaudited Pro Forma Cash Available for Distribution for the Year Ended December31, 2022 and the Twelve Months Ended June30, 2023.”

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

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•Optimized operations designed to make cash distributions to unitholders.    Our entrepreneurial culture focuses on operational optimization, cost-minimization, and nimble development to ultimately deliver cash distributions to unitholders across commodity cycles. Our asset profile consists of a large, low cost, and low declining PDP asset, complemented by low-cost horizontal development inventory. Our significant operating experience in the Anadarko Basin and economic advantage conferred by our midstream infrastructure significantly reduces lifting costs relative to other operators. For example, for the twelve months ended June30, 2023, we achieved a cash operating cost of approximately $12.51 per barrel of oil equivalent, inclusive of the benefit received from our midstream assets. Further, in the early stages of the Oswego horizontal development, a mixture of standard completion fluids and proppant were utilized in the stimulation. Since 2021, we have successfully further lowered our well costs to $3.0 million per well in the Oswego by using drilling efficiencies and utilizing acid in lieu of proppant within the stimulation. Due to our low completion costs, low operating costs, and our midstream advantage, we believe the average breakeven price for our Oswego drilling locations is $41.29 price per barrel of oil.

•Experienced management team with established track record of value creation.    We believe our management team’s experience in the Anadarko Basin offers a distinguishing advantage. The members of management have an average of 32 years of experience in the oil and gas industry and have successfully executed on a strategy of acquiring and exploiting long-lived and low decline assets. Additionally, our Chief Executive Officer, Tom L. Ward, has over a 40-year history in the oil and gas industry. Further, through our team’s history of operating in Oklahoma, we have built lasting relationships with sellers and developed a track record of successfully acquiring and integrating assets at attractive valuations. From January 2018 through September 2023, we have successfully executed 16 acquisitions for an aggregate purchase price of approximately $960million, increasing our net acreage to 936,000, and our average net daily production to approximately 65 MBoe/d for the twelve months ended June30, 2023. Additionally, during the same period, we distributed approximately $653million in cash to our members. We believe our management team has the experience, expertise and commitment to create significant value in the form of cash distributions to our unitholders.

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

Risk Factor Summary

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

Risks Related to Cash Distributions

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

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

Risks Related to Our Business

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

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

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

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

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

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

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

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

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

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

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

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

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

Risks Inherent in an Investment in Us

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

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

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

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

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

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

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

Tax Risks to Common Unitholders

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

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

Reorganization Transactions, Partnership Structure and Expected Refinancing Transactions

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

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

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

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

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

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

Expected Refinancing Transaction

As of September1, 2023, we had (i) $17.1million of outstanding borrowings under the BCE-Mach II credit facility, (ii) $65.0million of outstanding borrowings and $5million in outstanding letters of credit under the BCE-Mach credit facility and (iii) $91.9million of outstanding borrowings under the BCE-Mach III credit facility. We intend to use a portion of the net proceeds of this offering to repay in full and terminate the BCE-Mach II credit facility and repay in full and terminate the BCE-Mach credit facility, with any remaining net proceeds used to repay a portion of the BCE-Mach III credit facility and to purchase common units from the existing common unit owners as described herein. Please see “Use of Proceeds” for additional information.

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We are currently negotiating a new credit facility (the “New Credit Facility”) with prospective lenders that we anticipate entering into after the completion of this offering. The amount, maturity, interest rates and other terms of the New Credit Facility are under negotiations with prospective lenders; however, we expect the aggregate commitments thereunder will be in the range of $150million to $200million, that the New Credit Facility will be secured by substantially all of our assets and the covenants in the New Credit Facility will be on substantially the same terms as the BCE-Mach III credit facility. For a description of the covenants under the BCE-Mach III credit facility, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Year Ended December31, 2022 Compared to Year Ended December31, 2021 — Debt Agreements — Existing Credit Facilities.” Borrowings under the New Credit Facility may vary significantly from time to time depending on our cash needs at any given time. Once we have entered into the New Credit Facility, we expect to use borrowings under the New Credit Facility to repay in full and terminate the BCE-Mach III credit facility.

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

Ownership and Organizational Structure of Mach Natural Resources

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

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

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

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

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

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

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

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

(4)BCE-Mach Aggregator LLC and Mach Resources collectively wholly own Mach Natural Resources GP LLC, our general partner, with BCE-Mach Aggregator and Mach Resources owning approximately 80.3% and 19.7% of the outstanding membership interests, respectively.

Management of Mach Natural Resources

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

The members of our general partner are (i) BCE-Mach Aggregator, the majority of the membership interests of which are owned by investment funds managed by Bayou City Energy Management, LLC and its affiliates, which we refer to collectively as the Sponsor, and (ii) Mach Resources, which is controlled by Tom L. Ward, with such membership interests and Board appointment rights of such members held in proportion to their respective limited partnership interest ownership in us. Such proportional membership interest of Tom L. Ward includes certain ownership of trusts affiliated with Mr.Ward.

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Specifically, each of BCE-Mach Aggregator and Mach Resources shall separately be entitled to appoint (i) one director if its membership interests are greater than 0% but equal to or less than 25%, (ii) two directors if its membership interests are greater than 25% but equal to or less than 50%, (iii) three directors if its membership interests are greater than 50% but equal to or less than 75%, (iv) four directors if its membership interests are greater than 75% but less than 100% and (v) five directors if its membership interests are 100%. Further, to the extent each of BCE-Mach Aggregator and Mach Resources are entitled to appoint a director, each shall only be entitled to appoint one director that is not Independent (as defined in the general partner agreement). As a result, the Sponsor will control our general partner and will be entitled to appoint four members of the Board initially and Mach Resources shall be entitled to appoint one member of the Board initially, who shall be Tom L. Ward.

Additionally, pursuant to the general partner agreement, the Board shall have the right by delivery of written notice to BCE-Mach Aggregator and Mach Resources to require the Company, the Board and BCE-Mach Aggregator and Mach Resources, to take all necessary action to transfer all of the outstanding membership interests of our general partner to the Company for no additional consideration and amend our partnership agreement to provide the holders of common units with voting rights in the election of the members of the Board, as the general partner of the Company.

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

Our Sponsor

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

Implications of Being an Emerging Growth Company

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

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

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

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

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

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

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

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

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

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

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

Principal Executive Offices and Internet Address

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

Summary of Conflicts of Interest and Duties

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

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

•the manner in which our business is operated;

•the level of our borrowings;

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

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

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

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

Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the duties owed and remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of its fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including the Sponsor and its affiliates, are not restricted from competing with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement, each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Duties — Duties of Our General Partner” for a description of the duties imposed on our general partner by Delaware law, the replacement of those duties with contractual standards under our partnership agreement and certain legal rights and remedies available to holders of our common units.

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

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The Offering

Common units offered by us	common units representing limited partner interests (   common units if the underwriters exercise in full their option to purchase additional common units).
Units outstanding after this offering	common units representing limited partner interests in us (   common units if the underwriters exercise their option in full to purchase additional common units).
Use of proceeds	We expect the net proceeds from the offering to be approximately $million ($    million if the underwriters exercise their option to purchase additional units in full), based upon the assumed initial public offering price of $   per common unit (the mid-point of the price range set forth on the cover of this prospectus), after deducting underwriting discounts and estimated expenses. We expect to use approximately $            million of the proceeds from this offering as follows: to (i) repay in full and terminate the BCE-Mach II credit facility under which approximately $17.1million was outstanding as of September1, 2023 and (ii) repay in full and terminate the BCE-Mach credit facility under which approximately $65.0million was outstanding as of September1, 2023. Following the application of such proceeds, we expect to use the remainder to (i) repay a portion of the BCE Mach III credit facility under which $91.9million was outstanding as of September1, 2023 and (ii) purchase common units from the existing common unit owners on a pro rata basis for $            million (the “Exchanging Members”) (at a purchase price per unit based on the initial public offering price, net of underwriting discounts and commissions), with any remainder for general partnership purposes. To the extent the number of units in the offering is increased or decreased, the number of units purchased from the Exchanging Members will increase or decrease in the same proportion as the total number of units in the offering is increased or decreased. We are currently negotiating the New Credit Facility with prospective lenders and if we enter into the New Credit Facility after the closing of the offering, we would use borrowings under the New Credit Facility to repay in full and terminate the BCE-Mach III credit facility. See “Reorganization Transactions, Partnership Structure and Expected Refinancing Transactions — Expected Refinancing Transactions” for additional information. If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds would be approximately $million. The net proceeds from any exercise of such option will be used to purchase   common units from the Exchanging Members (at a purchase price per unit based on the initial public offering price, net of underwriting discounts and commissions). See “Use of Proceeds.”
Cash distributions	Within 60 days after the end of each quarter (other than the fourth quarter) and within 90 days after the end of the fourth quarter, beginning with the quarter ending, 2023, we expect to pay distributions of our available cash to unitholders of record on the applicable record date. The Board will adopt a policy pursuant to which distributions for each quarter will be paid to the extent we have sufficient cash after establishment of cash reserves and payment of expenses, development costs and fees, including payments to our general partner and its

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	affiliates. Our ability to pay such cash distributions is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.” We will prorate the amount of our distribution payable for the period from the closing of this offering through, 2023, based on the actual length of that period.
	Our partnership agreement generally provides that we will distribute all available cash each quarter to the holders of common units, pro rata.
	Pro forma cash available for distribution generated during the year ended December 31, 2022 and twelve months ended June 30, 2023 was approximately $402.0million and $220.6 million, respectively. As a result, for the year ended December 31, 2022 and twelve months ended June 30, 2023, we would have generated available cash sufficient to pay a cash distribution of $             and $            per unit per quarter, respectively ($             and $            on an annualized basis, respectively). For a calculation of our ability to pay distributions to our unitholders based on our pro forma results for the year ended December 31, 2022 and twelve months ended June 30, 2023, please read “Our Cash Distribution Policy and Restrictions on Distributions — Unaudited Pro Forma Cash Available for the Year Ended December 31, 2022 and Twelve Months Ended June 30, 2023.” We believe, based on our financial forecast and the related assumptions included under “Our Cash Distribution Policy and Restrictions on Distributions — Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2024,” that we will have sufficient cash available for distribution to make cash distributions of $per unit on all common units (on an annualized basis) for the four quarters ending June 30, 2024. We will 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. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”
Issuance of additional units	We can issue an unlimited number of additional units, including units that are senior to the common units in right of distributions, liquidation and voting, on terms and conditions determined by our general partner, without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Partnership Interests.”
Limited voting rights	Our general partner will manage us and operate our business. Unlike stockholders of a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66⅔% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering and the application of the use of proceeds as described under “Use of Proceeds,” affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) will own an aggregate of approximately% of our common units (or     % of our common units if the underwriters exercise in full their option to purchase additional common units) and, therefore, will be able to prevent the removal of our general partner. Please read “The Partnership Agreement — Limited Voting Rights.”

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Limited call right	If at any time our general partner and its affiliates own more than % of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement. Upon consummation of this offering, affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) will own an aggregate of approximately            % of our common units (or              % of our common units if the underwriters exercise in full their option to purchase additional common units). Please read “The Partnership Agreement — Limited Call Right.”
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 common units held by some or all unitholders to be converted into or exchanged for interests in the parent corporation. 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. Please read “Risk Factors — Risks Inherent in an Investment in Us — Our general partner may elect to convert or restructure us from a partnership to an entity taxable as a corporation for U.S. federal income tax purposes without unitholder consent” and “The Partnership Agreement — Election to be treated as a Corporation.”
Eligible Holders and redemption	Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem the units of certain non-citizen unitholders. We have the right (which we may assign to any of our affiliates), but not the obligation, to redeem all of the common units of any holder that is not an eligible holder pursuant to our partnership agreement or that has failed to certify or has falsely certified that such holder is an eligible holder. The purchase price for such redemption would be equal to the then-current market price of the common units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “Description of the Common Units — Transfer Agent and Registrar — Transfer of Common Units” and “The Partnership Agreement — Non-Citizen Unitholders; Redemption.”
Estimated ratio of taxable income to distributions	We estimate that if our unitholders own the common units purchased in this offering through the record date for distributions for the period ending December 31, 2025, such unitholders will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than % of the cash distributed to such unitholders with respect to that period. Please read “Material U.S. Federal Income Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” for the basis of this estimate.
Material tax consequences	For a discussion of other 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 read “Material U.S. Federal Income Tax Consequences.”
Listing and trading symbol	We have applied to list our common units on the NYSE under the symbol “MNR.”

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Summary Historical and Pro Forma Financial and Operating Data

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

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

The summary unaudited pro forma financial data as of June30, 2023 and for the six months ended June30, 2023 and year ended December31, 2022 are derived from the unaudited pro forma condensed combined financial statements of Mach Natural Resources included elsewhere in this prospectus, which reflect the historical results of our predecessor, BCE-Mach LLC and BCE-Mach II LLC on a pro forma basis to give effect to the following transactions, which are described in further detail below, as if they had occurred on June30, 2023, for pro forma balance sheet purposes, and on January1, 2022, for pro forma statements of operations purposes:

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

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

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

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

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

	Predecessor Historical												Mach Natural Resources Pro Forma
	Six Months Ended June 30,						Year Ended December 31,						Six Months Ended June 30, 2023			Year Ended December 31, 2022
(in thousands, except per unit amounts)	2023			2022			2022			2021
Statement of Operations Data:
Operating Revenues:
Oil, natural gas and NGL sales	$	312,613		$	408,442		$	860,388		$	397,500		$	399,686		$	1,165,420
Midstream revenue		13,318			19,883			44,373			31,883			13,531			44,832
Gain (loss) on oil and natural gas derivatives, net		15,742			(72,857	)		(67,453	)		(67,549	)		22,618			(113,322	)
Product sales		17,421			47,960			100,106			30,663			17,421			100,106
Total operating revenue		359,094			403,428			937,414			392,497			453,256			1,197,036
Operating Expenses:
Gathering and processing expense		17,510			20,812			47,484			27,987			33,430			87,887
Lease operating expense		60,615			39,592			95,941			45,391			87,439			145,267
Midstream operating expense		5,538			6,976			15,157			12,248			5,761			15,618
Cost of product sales		15,575			44,958			94,580			28,687			15,575			94,580
Production taxes		15,526			22,675			47,825			21,165			20,003			65,194
Depreciation, depletion, amortization and accretion expense – oil and natural gas		58,095			29,374			84,070			37,537			72,117			119,359
Depreciation and amortization expense – other		2,793			2,008			4,519			3,148			3,171			5,445
General and administrative expense		9,905			13,648			25,454			60,927			11,750			19,278
Total operating expenses		185,557			180,043			415,030			237,090			249,246			552,628
Income from operations		173,537			223,385			522,384			155,407			204,010			644,408
Other income (expenses):
Interest expense		(3,789	)		(1,876	)		(4,852	)		(1,656	)		(3,117	)		(4,241	)
Other income (expense), net		(245	)		1,121			(691	)		1,023			(4,966	)		(1,083	)
Loss on contingent consideration		—			—			—			(16,400	)		—			—
Total other income (expenses)		(4,034	)		(755	)		(5,543	)		(17,033	)		(8,083	)		(5,324	)
Net income	$	169,503		$	222,630		$	516,841		$	138,374		$	195,927		$	639,084
Net income per limited partner unit:
Basic	$			$			$			$						$
Diluted	$			$			$			$						$
Weighted average number of limited partner units outstanding:
Basic
Diluted
Other Financial Data:
Adjusted EBITDA(1)	$	226,766		$	276,408		$	594,429		$	248,617		$	255,639		$	714,295
Cash available for distribution(2)	$	30,418		$	155,857		$	300,944		$	184,445		$	43,290		$	402,022
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	275,145		$	227,936		$	553,542		$	198,462
Investing activities	$	(187,812	)	$	(212,951	)	$	(372,660	)	$	(194,743	)
Financing activities	$	(67,904	)	$	(27,236	)	$	(210,737	)	$	(4,584	)

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	Predecessor Historical							Mach Natural Resources Pro Forma
	Six Months Ended June 30,			Year Ended December 31,				Six Months Ended June 30, 2023		Year Ended December 31, 2022
(in thousands, except per unit amounts)	2023		2022	2022		2021
Balance Sheet Data (at period end):
Cash and cash equivalents	$	48,846		$	29,417	$	59,272	$	83,608
Oil and natural gas properties, net	$	744,071		$	610,420	$	277,922	$	1,085,208
Total assets	$	979,312		$	887,441	$	525,379	$	1,432,676
Total long-term liabilities	$	150,354		$	141,570	$	117,241	$	177,893
Members’/Partners’ capital	$	689,527		$	593,230	$	278,699	$	1,051,461

____________

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

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

Non-GAAP Financial Measures

Adjusted EBITDA

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

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

Cash Available for Distribution

Cash available for distribution is not a measure of net income or net cash flow provided by or used in operating activities as determined by GAAP. Cash available for distribution is a supplemental non-GAAP financial measure used by our management and by external users of our financial statements, such as investors, lenders and others (including industry analysts and rating agencies who will be using such measure), to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as net income less (1) interest expense, (2) depreciation, depletion and amortization, (3) unrealized (gain) loss on derivative settlements, (4) equity-based compensation expense, (5) loss on contingent consideration, (6) (gain) loss on sale of assets, (7) settlement of asset retirement obligations, (8) net cash interest expense, (9) development costs, (10) settlement of contingent consideration and (11) change in accrued realized derivative settlements. Development costs include all of our capital expenditures, other than acquisitions. Cash available for distribution will not reflect changes in working capital balances. Cash available for distribution is not a measurement of our financial performance or liquidity under GAAP and should not be considered as an alternative to, or more meaningful than, net income or net cash provided by or used in operating activities as determined in accordance with GAAP or as indicators of our financial performance and liquidity. The GAAP measures most

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directly comparable to cash available for distribution are net income and net cash provided by operating activities. Cash available for distribution should not be considered as an alternative to, or more meaningful than, net income or net cash provided by operating activities.

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

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

	Predecessor Historical												Mach Natural Resources Pro Forma
	Six Months Ended June 30,						Year Ended December 31,						Six Months Ended June 30, 2023			Year Ended December 31, 2022
(in thousands) (unaudited)	2023			2022			2022			2021
Net Income Reconciliation to Adjusted EBITDA:
Net income	$	169,503		$	222,630		$	516,841		$	138,374		$	195,927		$	639,084
Interest expense, net		3,294			1,876			4,852			1,656			2,280			4,231
Depreciation, depletion and amortization		60,888			31,382			88,589			40,685			75,288			124,804
Unrealized (gain) loss on derivative settlements		(8,212	)		16,735			(23,335	)		6,284			(18,622	)		(53,730	)
Equity-based compensation expense		1,294			3,763			7,527			45,303			—			—
Loss on contingent consideration		—			—			—			16,400			—			—
Credit losses		—			—			—			—			767			—
(Gain) loss on sale of assets		(1	)		22			(45	)		(85	)		(1	)		(94	)
Adjusted EBITDA		226,766			276,408			594,429			248,617			255,639			714,295
Net Income Reconciliation to Cash Available for Distribution:
Net income	$	169,503		$	222,630		$	516,841		$	138,374		$	195,927		$	639,084
Interest expense, net		3,294			1,876			4,852			1,656			2,280			4,231
Depreciation, depletion and amortization		60,888			31,382			88,589			40,685			75,288			124,804
Unrealized (gain) loss on derivative settlements		(8,212	)		16,735			(23,335	)		6,284			(18,622	)		(53,730	)
Equity-based compensation expense		1,294			3,763			7,527			45,303			—			—
Loss on contingent consideration		—			—			—			16,400			—			—
Credit losses		—			—			—			—			767			—
(Gain) loss on sale of assets		(1	)		22			(45	)		(85	)		(1	)		(94	)
Settlement of asset retirement obligations		(79	)		(49	)		(49	)		(35	)		(133	)		(206	)
Cash interest expense, net		(3,092	)		(1,690	)		(4,477	)		(1,344	)		(2,078	)		(3,856	)
Development costs(1)		(192,892	)		(113,068	)		(271,999	)		(55,124	)		(207,557	)		(290,636	)
Settlement of contingent consideration		—			(8,111	)		(13,547	)		(9,553	)		—			(13,547	)
Change in accrued realized derivative settlements		(285	)		2,367			(3,413	)		1,884			(2,581	)		(4,028	)
Cash Available for Distribution	$	30,418		$	155,857		$	300,944		$	184,445		$	43,290		$	402,022
Net Cash Provided by Operating Activities Reconciliation to Cash Available for Distribution:
Net cash provided by operating activities	$	275,145		$	227,936		$	553,542		$	198,462
Changes in operating assets and liabilities		(51,835	)		40,989			19,401			41,107
Development costs(1)		(192,892	)		(113,068	)		(271,999	)		(55,124	)
Cash Available for Distribution	$	30,418		$	155,857		$	300,944		$	184,445

____________

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

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Reconciliation of PV-10 to Standardized Measure

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

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

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

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Summary of Reserve, Production and Operating Data

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

Summary of Reserves

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

	Mach Natural Resources Pro Forma(1)
	As of June 30, 2023 SEC Pricing(2)		As of December 31, 2022 SEC Pricing(2)
Proved Developed:
Oil (MBbl)		40,876		43,306
Natural gas (MMcf)		782,727		838,298
Natural gas liquid (MBbl)		50,190		59,761
Oil equivalent (MBoe)		221,520		242,782
PV-10 (in millions)(3)	$	2,131	$	3,334
Proved Undeveloped:
Oil (MBbl)		12,153		23,438
Natural gas (MMcf)		28,781		144,380
Natural gas liquid (MBbl)		721		9,978
Oil equivalent (MBoe)		17,671		57,480
PV-10 (in millions)(3)	$	304	$	724
Total Proved:
Oil (MBbl)		53,029		66,744
Natural gas (MMcf)		811,507		982,678
Natural gas liquid (MBbl)		50,911		69,739
Oil equivalent (MBoe)		239,191		300,262
Standardized Measure (in millions)(3)	$	2,435	$	4,058
PV-10 (in millions)(3)	$	2,435	$	4,058
Probable:(4)
Oil (MBbl)		72,868		—
Natural gas (MMcf)		373,477		—
Natural gas liquid (MBbl)		19,576		—
Oil equivalent (MBoe)		154,690		—
PV-10 (in millions)(3)	$	1,039	$	—

__________

(1)The reduction in our proved developed, undeveloped and total proved reserves, total proved reserves standardized measure and PV-10 during the period from December 31, 2022 to June 30, 2023 was driven primarily by a decrease in oil and natural gas prices (based on SEC pricing) during the same period.

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

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

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

Select Production and Operating Statistics

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

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

	Mach Natural Resources Pro Forma
	Six Months Ended June 30, 2023			Year Ended December 31, 2022
Net Production Volumes:
Oil (MBbl)		3,370			5,982
Natural Gas (MMcf)		38,675			70,947
NGLs (MBbl)		2,045			4,246
Total (MBoe)		11,861			22,053
Average daily production (MBoe/d)		65.53			60.42
Average Wellhead Realized Prices (before giving effect to realized derivatives):
Oil (/Bbl)	$	74.93		$	93.60
Natural Gas (/Mcf)	$	2.50		$	6.21
NGLs (/Bbl)	$	24.72		$	38.85
Average Wellhead Realized Prices (after giving effect to realized derivatives):
Oil (/Bbl)	$	72.19		$	78.94
Natural Gas (/Mcf)	$	2.84		$	5.09
NGLs (/Bbl)	$	24.72		$	38.85
Operating costs and expenses (per Boe):
Gathering and processing expense	$	2.82		$	3.99
Lease operating expense	$	7.37		$	6.59
Production taxes expense (% of oil, natural gas and NGL sales)		5.0	%		5.6	%
Depreciation, depletion, amortization and accretion expense – oil and natural gas	$	6.08		$	5.41
Depreciation and amortization expense – other	$	0.27		$	0.25
General and administrative expense	$	0.99		$	0.87

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RISK FACTORS

Investing in our common units involves a high degree of risk. You should carefully consider the risks described below with all of the other information included in this prospectus before deciding to invest in our common units. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. Additionally, new risks may emerge at any time and we cannot predict those risks or estimate the extent to which they may affect financial performance.

If any of the following risks actually occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and our unitholders could lose all or part of their investment.

Risks Related to Cash Distributions

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

We may not have sufficient available cash each quarter to pay distributions on our common units. Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by our operating expenses, cash interest, development costs and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including development, optimization and exploitation of our oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders. The amount of available cash that we distribute to our unitholders will depend principally on the cash we generate from operations, which will depend on, among other factors:

•the amount of oil, natural gas and NGLs we produce;

•the prices at which we sell our oil, natural gas and NGL production;

•the amount and timing of settlements on our commodity derivative contracts;

•the level of our capital expenditures, including scheduled and unexpected maintenance expenditures;

•the level of our operating costs, including payments to our general partner and its affiliates for general and administrative expenses;

•the restrictive covenants in the BCE-Mach III credit facility and, to the extent entered into, the New Credit Facility (but not the BCE-Mach II credit facility and the BCE-Mach credit facility which are to be repaid in full and terminated with the proceeds of this offering) (collectively, the “Credit Facilities”) and other agreements governing indebtedness that limit our ability to pay dividends or distributions in respect of our equity; and

•the level of our interest expenses, which will depend on the amount of our outstanding indebtedness and the applicable interest rate.

Furthermore, the amount of cash we have available for distribution depends primarily on our cash flow, including cash from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.

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

Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. Our future business performance may be volatile, and our cash flows may be unstable. We will not have a minimum quarterly distribution. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero. Please read “Cash Distribution Policy and Restrictions on Distributions.”

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The assumptions underlying the forecast of cash available for distribution we include in “Our Cash Distribution Policy and Restrictions on Distributions” may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from our forecasted results.

Our management’s forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending June30, 2024. The assumptions underlying the forecast may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from those forecasted. If our actual results are significantly below forecasted results, or if our expenses are greater than forecasted, we may not be able to pay the forecasted annual distribution or any distribution on our common units, which may cause the market price of our common units to decline materially.

Risks Related to Our Business

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

Our revenues, operating results, cash available for distribution, liquidity and ability to grow depend primarily upon the prices we receive for the natural gas, oil and NGL we sell. We require substantial expenditures to replace our natural gas, oil and NGL reserves, sustain production and fund our business plans, including our development and exploratory drilling efforts. Historically, the markets for natural gas, oil and NGL have been volatile, and they are likely to continue to be volatile. Wide fluctuations in natural gas, oil and NGL prices may result from relatively minor changes in the supply of or demand for natural gas, oil and NGL, market uncertainty and other factors that are beyond our control, including:

•worldwide and regional economic conditions impacting the supply and demand for oil, natural gas and NGLs;

•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;

•actions of the Organization of the Petroleum Exporting Countries and its allies (“OPEC+”), including the ability and willingness of the members of OPEC+ and other exporting nations to agree to and maintain oil price and production controls;

•changes in seasonal temperatures, including the number of heating degree days during winter months and cooling degree days during summer months;

•the level of oil, natural gas and NGL exploration, development and production;

•the level of oil, natural gas and NGL inventories;

•the level of U.S. LNG exports;

•the impact on worldwide economic activity of an epidemic, outbreak or other public health events, such as COVID-19,

•prevailing prices on local price indexes in the areas in which we operate;

•the proximity, capacity, cost and availability of gathering and processing facilities;

•localized and global supply and demand fundamentals and transportation availability;

•the cost of exploring for, developing, producing and transporting reserves;

•the spot price of LNG on world markets;

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•changes in ocean freight capacity, which could adversely impact LNG shipping capacity or lead to material interruptions in service or stoppages in LNG transportation;

•political and economic conditions in or affecting major LNG consumption regions or countries, particularly Asia and Europe;

•weather conditions and natural disasters, including those influenced by climate change;

•technological advances affecting energy consumption;

•the impact of energy conservation efforts;

•the price and availability of alternative fuels;

•activities that to restrict the exploration, development and production of oil and natural gas to minimize greenhouse gas (“GHG”) emissions;

•speculative trading in oil and natural gas derivative contracts;

•increased end-user conservation;

•U.S. trade policies and their effect on U.S. oil and natural gas exports;

•expectations about future commodity prices; and

•U.S. federal, state and local and non-U.S. governmental regulation and taxes, including legislation or regulations addressing GHG emissions or requiring the reporting of GHG emissions or climate-related information.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements accurately. Lower commodity prices may reduce our operating margins, cash flow and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves or make acquisitions could be adversely affected. Also, using lower prices in estimating proved and probable reserves may result in a reduction in proved and probable reserve volumes due to economic limits. In addition, sustained periods with oil and natural gas prices at levels lower than current WTI and Henry Hub strip prices may adversely affect our drilling economics, cash flow and our ability to raise capital, which may require us to re-evaluate and postpone or substantially restrict our development program, and result in the reduction of some of our proved and probable undeveloped reserves and related PV-10. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, cash available for distribution, liquidity and ability to meet our financial commitments or cause us to delay our planned capital expenditures.

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

As a result of our geographic concentration, adverse industry developments in our operating area could have a greater impact on our financial condition and results of operations than if we were more geographically diverse. We may also be disproportionately exposed to the impact of regional supply and demand factors, governmental regulations or midstream capacity constraints. Delays or interruptions caused by such adverse developments could have a material adverse effect on our financial condition and results of operations.

Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field wide rules, which could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has recently been the case in our operating areas, we are subject to increasing competition for drilling rigs, workover rigs, tubulars and other well equipment, services, supplies as well as increased labor costs and a decrease in qualified personnel, which may lead to periodic shortages or delays. The curtailments arising from these and similar circumstances may last from a few days to several months or even longer, and, in many cases, we may be provided only limited, if any, notice as to when these circumstances will arise and their duration.

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

Our future financial condition and results of operations will depend on the success of our development, production and acquisition activities, which are subject to numerous risks beyond our control. For example, we cannot assure you that wells we drill will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil, natural gas and NGLs often involves unprofitable efforts from wells that do not produce sufficient oil, natural gas and NGLs to return a profit at then-realized prices after deducting drilling, operating and other costs. In addition, our cost of drilling, completing and operating wells is often uncertain.

Our decisions to develop or purchase prospects or properties will depend, in part, on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “— Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

Further, many factors may increase the cost of, curtail, delay or cancel our scheduled drilling projects, including:

•declines in oil, natural gas and NGL prices;

•increases in the cost of, and shortages or delays in the availability of, proppant, acid, equipment, services and qualified personnel or in obtaining water for hydraulic fracturing activities;

•equipment failures, accidents or other unexpected operational events;

•capacity or pressure limitations on gathering systems, processing and treating facilities or other related midstream infrastructure;

•any future lack of available capacity on interconnecting transmission pipelines;

•delays imposed by, or resulting from, compliance with regulatory requirements, including limitations on freshwater sourcing, wastewater disposal, emissions of GHGs and hydraulic fracturing;

•pressure or irregularities in geological formations;

•limited availability of financing on acceptable terms;

•issues related to compliance with or liability arising under environmental laws and regulations;

•environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the air, surface and subsurface environment;

•compliance with contractual requirements;

•competition for surface locations from other operators that may own rights to drill at certain depths across portions of our leasehold;

•lack of available gathering facilities or delays in construction of gathering facilities;

•adverse weather conditions, such as hurricanes, lightning storms, flooding, tornadoes, snow or ice storms and changes in weather patterns;

•the availability and timely issuance of required governmental permits and licenses;

•title issues or legal disputes regarding leasehold rights; and

•other market limitations in our industry.

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

We have specifically identified and scheduled certain drilling locations as an internal estimation of our future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, availability and cost of capital, drilling and production costs, availability of drilling services and equipment, availability and cost of sand and other proppant used in hydraulic fracturing operations and acid used for acid stimulation, drilling results, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution and disposal systems, access to and availability of saltwater disposal systems, regulatory approvals, the cooperation of other working interest owners and other factors. Because of these uncertain factors, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce oil and natural gas from these or any other drilling locations. As such, our actual drilling activities may materially differ from those presently identified.

As a result of the limitations described in this prospectus, we may be unable to drill many of our identified locations. In addition, although we plan to fund our drilling program entirely with cash flow from operations, if our cash flows are less than we expect or we alter our drilling plans, we may be required to borrow more under the Credit Facilities than we expect or issue new debt or equity securities in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. See “— Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.” Any drilling activities we are able to conduct on these locations may not be successful, may not result in production or additions to our estimated proved and probable reserves and could result in a downward revision of our estimated proved and probable reserves, which in turn could have a material adverse effect on the borrowing base under the Credit Facilities or our future business and results of operations. Additionally, if we curtail or cancel our drilling program, we may be required to reduce our estimated proved and probable reserves, which could in turn reduce the borrowing base under the Credit Facilities.

Properties that we decide to drill may not yield oil and natural gas in commercially viable quantities.

Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of geologic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess recoverable reserves, future oil and natural gas prices and their applicable differentials, development and operating costs, and potential liabilities, including environmental liabilities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices, but such a review may not reveal all existing or potential problems. Such assessments are inexact and inherently uncertain. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as any groundwater contamination or pipe corrosion, when a review is performed. We also may be unable to obtain contractual indemnities from the seller for liabilities arising prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. For these reasons, the properties we have acquired or will acquire in the future may not produce as expected or may not increase our cash available for distribution.

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

As of June30, 2023, approximately 7% of our total estimated proved reserves were classified as PUDs using SEC Pricing. Further, all of our probable reserves were classified as undeveloped. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Estimated future development costs relating to the development of our PUDs at June30, 2023 are approximately $261.0 million over the next five years. Estimated future development costs relating to the development of our probable reserves at June30, 2023 are approximately $2.4billion. Our ability to fund these expenditures is subject to a number of risks. See “— Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.” Delays in the development of our PUDs, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the PV-10 value of our estimated PUDs and future net cash flows estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify some of our PUDs as unproved reserves. Furthermore, there is no certainty that we will be able to convert our undeveloped reserves to developed reserves or that our PUDs will be economically viable or technically feasible to produce.

Further, SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. As a result, we may be required to reclassify certain of our PUDs if we do not drill those wells within the required five-year timeframe.

Part of our business strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Difficulties that we face while completing our wells include:

•the ability to fracture stimulate the planned number of stages with the planned amount of proppant;

•the ability to source acid for our acid stimulation completion techniques;

•the ability to run tools through the entire length of the wellbore during completion operations; and

•the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. If our development and production results are less than anticipated, the return on our investment for a particular well or region may not be as attractive as we anticipated, and we could incur material write-downs of our undeveloped acreage and its value could decline in the future.

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

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of gathering, treating, processing and transportation pipelines, plants and other midstream facilities, a significant portion of which is owned by third parties. Some of our oil and natural gas production is collected from the wellhead by third-party gathering lines and transported to a gas processing or treating facility or transmission pipeline. We do not control these third-party facilities and our access to them may be limited, curtailed or denied. Pipelines, plants, and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements, and curtailments of receipts or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. The third-party facilities may experience unplanned downtime or maintenance for a variety of reasons outside our control and our production could be materially negatively impacted as a result of such outages. Insufficient production from our wells in the properties we do not operate to support the construction of pipeline facilities by third parties or a significant disruption in the availability of our or third-party midstream facilities

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or other production facilities could adversely impact our ability to deliver to market or produce our natural gas and thereby causing a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement gathering, treating, processing or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.

If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, our revenues and cash flows and our ability to make cash distributions to our unitholders could be materially adversely affected.

Our gathering systems connect to third-party pipelines and other midstream facilities, such as processing plants, rail terminals and produced water disposal facilities. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable due to issues including, but not limited to, testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from other hazards. In addition, we do not have interconnect agreements with all of these pipelines and other facilities and the agreements we do have may be terminated in certain circumstances and/or on short notice. If any of these pipelines or other midstream facilities become unavailable for any reason, or, if these third parties are otherwise unwilling to receive or transport the oil, natural gas and produced water that we gather and/or process, our revenues, cash flows and ability to make cash distributions to our unitholders could be materially adversely affected.

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

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary materially from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected and production declines may be greater than we estimate and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates of proved and probable reserves to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant change could materially affect the estimated quantities and present value of our reserves. Furthermore, our development plan calls for completing horizontal wells using tighter well spacing and acid stimulation, which may increase the risk that these wells interfere with production from existing or future wells in the same spacing section and horizon, which in turn may result in lower recoverable reserves. There can be no assurance that our reserves will ultimately be produced or that our proved undeveloped reserves will be developed within the periods anticipated.

You should not assume that the present values of future net cash flows from our reserves presented in this prospectus are the current market value of our estimated reserves. Actual future prices and costs may differ materially from those used in our present value estimates using SEC Pricing. If spot prices or future actual prices are below the prices used in our current reserve estimates, using those prices in estimating proved and probable reserves may result in a decrease in proved and probable reserve volumes due to economic limits. You should not assume that the standardized measure of proved reserves and PV-10 values of our estimated reserves are accurate estimates of the current fair value of our estimated oil, natural gas and NGL reserves.

Estimates of probable reserves, and the future cash flows related to such estimates, are inherently imprecise and are more uncertain than estimates of proved reserves and the future cash flows related to such estimates but have not been adjusted for risk due to such uncertainty. Because of such uncertainty, estimates of probable reserves, and the future cash flows related to such estimates, may not be comparable to estimates of proved reserves and the future

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cash flows related to such estimates and should not be summed arithmetically with estimates of proved reserves and the future cash flows related to such estimates. When producing an estimate of the amount of natural gas, NGLs and oil that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. All of our probable reserves as of June30, 2023 were estimated using a deterministic method, which involves two distinct determinations: (i) an estimation of the quantities of recoverable oil and natural gas and (ii) an estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves uses the same generally accepted analytical procedures as are used in estimating proved reserves, namely production performance-based methods, material balance-based methods, volumetric-based methods and analogy. In the case of probable reserves, the recoverable reserves cannot be said to have a “high degree of confidence that the quantities will be recovered”, but are “as likely as not to be recovered.” The lower degree of certainty can come from several factors including: (1) direct offset production that does not meet an economic threshold, despite localized averages that do meet that threshold, (2) an increased distance from offset production to the probable location of over one mile but under three miles, (3) a perceived risk of communication or depletion from nearby producers, (4) a perceived risk of attempting new drilling or completion technologies that have not been used in direct offset production or (5) an uncertainty regarding geologic positioning that could affect recoverable reserves. When considering the factors referenced above, the lower degree of certainty of our probable reserves came from a combination of these factors. Many of the probable locations assigned in our reserve report as of June30, 2023 had few uncertainties and resemble proved undeveloped locations except for their distance from commercial production. Other probable locations had uncertainties related to not only distance from commercial production, but also related to well spacing and development timing. In general, we did not book probable locations if there was geologic uncertainty or if there was not commercial production to support such locations.

The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves.

The present value of future net cash flow from our proved reserves, or standardized measure, may not represent the current market value of our estimated proved oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.

Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. For example, our estimated proved reserves as of June30, 2023 were calculated under SEC rules using the unweighted arithmetic average first day of the month prices for the prior 12 months of $4.763/MMBtu for natural gas and $82.82/Bbl for oil at June30, 2023, which, for certain periods during this period, were substantially different from the available spot prices. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with Accounting Standards Codification 932, “Extractive Activities — Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Unless we replace our produced reserves with acquired or developed new reserves, our reserves and production will decline, which would adversely affect our future cash flows, results of operations and cash available for distribution.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of

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operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market natural gas, secure trained personnel and raise additional capital.

Our ability to acquire additional oil and gas properties and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and gas industry. Many of our competitors possess and employ greater financial, technical and personnel resources than we do. Those companies may be able to pay more for oil and natural gas properties and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Those larger companies may also have a greater ability to continue development activities during periods of low oil prices and to absorb the burden of present and future federal, state, local and other laws and regulations. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. We may not be able to compete successfully in the future in acquiring natural gas properties, developing reserves, marketing our production, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

A portion of our estimated drilling locations are based on our management’s internal estimates and were not based on evaluations prepared by Cawley, Gillespie & Associates Inc.

Approximately 665 of our 2,022 total identified drilling locations are on properties that we do not anticipate to operate and were based on our management’s internal estimates and not based on evaluations of Cawley, Gillespie & Associates Inc., our independent reserve engineer. Nonetheless, management’s internal estimates were based upon the same guidelines as used within the Cawley, Gillespie & Associates Inc. evaluation, being production performance-based methods, material balance-based methods, volumetric-based methods and analogy. As a result, these estimates have greater uncertainty than those identified drilling locations evaluated by Cawley, Gillespie & Associates Inc.

Our midstream services contracts are generally structured as short-term and long-term, fixed-fee contracts, which may negatively impact our operating margins and cash flow during periods of lower oil and natural gas prices.

We have entered into short-term and long-term, fixed-fee contracts with third parties for gathering, processing and transportation services, including four firm transportation contracts, three of which are fully utilized and one that is partially utilized, with the remainder released to other shippers or unutilized. The impact of the unutilized portion of this contract is assumed under the weighted average sales price in the reserves. The total liability as of June30, 2023 under the firm transportation contracts is $10.6 million. In addition, under these short-term and long-term, fixed-fee arrangements, our gathering and processing expenses are generally fixed on a per unit basis for the term of the applicable contract and do not automatically adjust in response to a decline in oil and natural gas prices. In the event of a prolonged period of lower commodity prices, our revenue will decline while the per unit fees we pay for natural gas gathering, treating and compression services generally will not, which would negatively impact our operating margins and cash flow. In addition, during periods of depressed oil and natural gas prices, the market prices for such services may be lower than what we are contractually obligated to pay to our current third-party midstream service providers. Furthermore, to the extent certain future taxes or assessments are imposed on certain midstream assets we utilize, under certain circumstances we may be required by our midstream services contracts to reimburse the midstream service provider for such taxes or assessments, which could negatively affect our operating margins and cash flow. Our third-party midstream service providers are under no obligation to renegotiate their contracts with us. Our failure to obtain these services on competitive terms could materially harm our business.

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The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

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

We do not directly employ directors, officers or employees. Pursuant to the MSA with Mach Resources, an entity that is wholly owned by Tom L. Ward and his family, all of our executive management personnel are employees of Mach Resources, and we use a significant number of Mach Resources’ employees to operate our properties and provide us with general and administrative services. If Mach Resources were to become unable or unwilling to provide such services, we would need to develop these services internally or arrange for the services from another service provider. Developing the capabilities internally or by retaining another service provider could have an adverse effect on our business, and the services, when developed or retained, may not be of the same quality as provided to us by Mach Resources. Additionally, if the MSA were to terminate, we would lose our key personnel.

Certain factors could require us to write down the carrying values of our properties, including commodity prices decreasing to a level such that our future undiscounted cash flows from our properties are less than their carrying value.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, drilling and completion results, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down constitutes a non-cash impairment charge to earnings. Lower commodity prices in the future could result in impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. We could experience further material write-downs as a result of other factors, including low production results or high lease operating expenses, capital expenditures or transportation fees.

We may incur losses as a result of title defects in the properties in which we invest.

The existence of a material title deficiency can render a lease worthless and adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

We own non-operating interests in properties developed and operated by third parties and some of our leasehold acreage could be pooled by a third-party operator. As a result, we are unable, or may become unable as a result of pooling, to control the operation and profitability of such properties.

We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over such operations. As a participant, we rely on the third-party operators to successfully operate these properties pursuant to joint operating agreements and other contractual arrangements. Similarly, our acreage in Oklahoma and Texas may be pooled by third-party operators under state law. If our acreage is involuntarily pooled under state forced pooling statutes, it would reduce our control over such acreage and we could lose operatorship over a portion of our acreage that we plan to develop.

We may not be able to maximize the value associated with acreage that we own but do not operate in the manner we believe appropriate, or at all. We cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In

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addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, breach of applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our business, financial condition and results of operations.

We may be unable to make accretive acquisitions or may make opportunistic dispositions. Any such acquisitions, if not integrated or conducted successfully, or such dispositions, if not conducted successfully, may disrupt our business and hinder our growth potential.

We may be unable to make accretive acquisitions or may make opportunistic dispositions. Any such acquisitions, if not integrated or conducted successfully, or such dispositions, if not conducted successfully, may disrupt our business and hinder our growth potential. Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that result in an increase in cash available for distribution. There is intense competition for acquisition opportunities in our industry and we may not be able to identify attractive acquisition opportunities. In the future we may make acquisitions of assets or businesses that complement or expand our current business. However, there is no guarantee we will be able to identify attractive acquisition opportunities. In the event we are able to identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions. In addition, from time to time, we may consider opportunistic dispositions, including dispositions of non-operating properties, having the potential to further limit future production.

The success of completed acquisitions will depend on our ability to effectively integrate the acquired businesses into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, the Credit Facilities imposes or will impose certain limitations on our ability to enter into mergers or combination transactions and to incur certain indebtedness, which could indirectly limit our ability to acquire assets and businesses.

Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

The oil and gas industry is capital-intensive. A number of factors could cause our cash flow to be less than we expect, including the results of our drilling and completion program. Moreover, our capital budgets are based on a number of assumptions, including expected elections by working interest partners, drilling and completion costs, midstream service costs, oil and natural gas prices, and drilling results, and are therefore subject to change. If our cash flows are less than we expect, we decide to pursue acquisitions, or we change our capital budgets, we may be required to borrow more under credit facility than we expect or issue debt or equity securities to consummate such acquisitions or fund our drilling and completion program. The incurrence of additional indebtedness, either through borrowings under the Credit Facilities, the issuance of additional debt securities or otherwise, would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund capital expenditures, our development plan, acquisitions and cash distributions to unitholders. Additionally, the market demand for equity issued by master limited partnerships has been significantly lower in recent years than it has been historically, which may make it more challenging for us to finance our capital expenditures with the issuance of additional equity. The issuance of additional equity securities may be dilutive to our unitholders The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things: oil and natural gas prices; actual drilling results; the availability and cost of drilling rigs and labor and other services and equipment; the availability, cost and adequacy of midstream gathering, processing, compression and transportation infrastructure; and regulatory, technological and competitive developments.

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Our cash flow from operations and access to capital are subject to a number of variables, including:

•the prices at which our production is sold;

•the amount of our proved reserves;

•the amount of hydrocarbons we are able to produce from existing wells;

•our ability to acquire, locate and produce new reserves;

•the amount of our operating expenses;

•cash settlements from our derivative activities;

•our ability to borrow under the Credit Facilities; and

•our ability to access the debt and equity capital markets or sell non-core assets.

If our revenues or the borrowing bases under the Credit Facilities decrease as a result of lower commodity prices, operational difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to make acquisitions or sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under the Credit Facilities are insufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of the development of our properties, which in turn could lead to a decline in our reserves and production and could materially and adversely affect our business, financial condition and results of operations.

Increased costs of capital could adversely affect our business.

Our business could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. For example, since March 2022, the Federal Reserve has raised its target range for the federal funds rate multiple times, and additional rate hikes may continue to occur. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our activities. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our business strategy and cash flows.

We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.

Historically, capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices and drilling activity in our areas of operation and other major shale basins throughout the United States. These cost increases result from a variety of factors beyond our control, such as increases in the cost of sand and other proppant used in hydraulic fracturing operations or acid used for acid stimulation, and steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities. Furthermore, high oil prices have historically led to more development activity in oil-focused shale basins and resulted in service cost inflation across all U.S. shale basins, including our areas of operation. Higher levels of development activity in oil-focused shale basins have also historically resulted in higher levels of associated gas production that places downward pressure on natural gas prices. To the extent natural gas prices decline due to a period of increased associated gas production and we experience service cost inflation during such period, our cash flow, profitability and ability to make distributions to our unitholders may be materially adversely impacted.

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

The demand for drilling rigs, frac crews, pipe and other equipment and supplies, including sand and other proppant used in hydraulic fracturing operations and acid used for acid stimulation, as well as for qualified and experienced field personnel, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with commodity prices or drilling activity in our areas of operation and in other shale basins in the United States, causing periodic shortages of supplies and needed personnel and rapid increases in costs. Increased drilling activity could materially increase the demand for and prices of these goods and services, and we could encounter rising costs and delays in or an inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to conduct our drilling and development activities, which could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs could have a material adverse effect on our cash flow and profitability.

We depend upon several significant purchasers for the sale of most of our oil, natural gas and NGL production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.

For the six months ended June30, 2023, two purchasers each accounted for more than 10% of our predecessor’s revenue: Phillips 66 Company (52.0%) and NextEra Energy Marketing, LLC (16.7%). For the year ended December 31, 2022, three purchasers each accounted for more than 10% of our predecessor’s revenue: Hinkle Oil and Gas Inc. (31.5%), NextEra Energy Marketing, LLC (17.0%) and Phillips 66 Company (16.9%). For the year ended December 31, 2021, four purchasers each accounted for more than 10% of our predecessor’s revenue: Phillips 66 Company (33.5%), NextEra Energy Marketing, LLC (20.2%), Hinkle Oil and Gas Inc. (13.3%) and ONEOK Hydrocarbon L.P. (13.9%). No other purchaser accounted for more than 10% of our predecessor’s revenue during these periods. We do not have long-term contracts with our customers; rather, we sell the substantial majority of our production contracts with terms of 12 months or less, including on a month-to-month basis, to a relatively small number of customers. The loss of any one of these purchasers, the inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation could materially adversely affect our financial condition, results of operations and ability to make distributions to our unitholders. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have ready access to suitable markets for our future production. See “Business and Properties — Marketing and Customers.”

The availability of a ready market for any hydrocarbons we produce depends on numerous factors beyond our control, including, but not limited to, the extent of domestic production and imports of oil, the proximity and capacity of oil, natural gas and NGL pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil, natural gas and NGL production and federal regulation of oil, natural gas and NGLs sold in interstate commerce.

Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects.

On a pro forma basis as of June30, 2023, after giving effect to the Reorganization Transactions and this offering and the use of proceeds therefrom, we expect to have $           million outstanding under the BCE-Mach III credit facility. In the future, we and our subsidiaries may incur substantial additional indebtedness (including secured indebtedness and any borrowings under the New Credit Facility). The Credit Facilities contain or will contain restrictions on the incurrence of additional indebtedness, and these restrictions will be subject to waiver and a number of significant qualifications and exceptions, and indebtedness incurred in compliance with these restrictions could be substantial. Additionally, the Credit Facilities permit or will permit us to incur certain amounts of additional indebtedness.

Although we expect to remain substantially debt free following consummation of the offering, our level of indebtedness, if any, could affect our operations in several ways, including the following:

•requiring us to dedicate a substantial portion of our cash flow from operations to service our debt, thereby reducing the cash available to finance our operating and investing activities;

•limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

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•increasing our vulnerability to downturns and adverse developments in our business and industry;

•limiting our ability to raise capital on favorable terms;

•limiting our ability to raise available financing, make investments, lease equipment, sell assets and engage in business combinations;

•making us vulnerable to increases in interest rates;

•putting us at a competitive disadvantage relative to our competitors; and

•limiting our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities, due to covenants contained in our New Credit Facility, including financial covenants.

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

The agreements governing the Credit Facilities contain or will contain a number of significant covenants, including restrictive covenants that will, subject to certain qualifications, limit our ability to, among other things:

•make certain payments, including paying dividends or distributions in respect of our equity;

•incur additional indebtedness;

•make loans to others;

•make certain acquisitions and investments;

•make or pay distributions on our common units, if an event of default or borrowing base deficiency exists;

•merge or consolidate with another entity;

•hedge future production or interest rates;

•incur liens;

•sell assets; and

•engage in certain other transactions without the prior consent of the lenders.

In addition, the Credit Facilities require or will require us to maintain compliance with certain financial covenants.

The restrictions in the agreements governing or that will govern the Credit Facilities, also impacts our ability to obtain capital to withstand a downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our debt arrangements may impose on us.

A breach of any covenant in the Credit Facilities will result in a default under our credit agreement and an event of default if there is no grace period or if such default is not cured during any applicable grace period. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under the applicable agreement and in an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Any significant reduction in our borrowing base under the Credit Facilities as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

The Credit Facilities limit or is expected to limit the amounts we can borrow up to certain borrowing base amounts, which the administrative agent in good faith and in accordance with its usual and customary procedures for evaluating oil and gas loans and related assets at that particular time and otherwise acting in its sole discretion, will

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determine and which will be approved by the required lenders or all lenders, as applicable in the case of an increase in the borrowing base, on a semi-annual basis based upon projected revenues from our natural gas properties, our commodity derivative contracts securing our loan and certain other information (including, without limitation, the status of title information with respect to the oil and gas properties and the existence of any other indebtedness, liabilities, fixed charges, cash flow, business, properties, prospects, management and ownership, hedged and unhedged exposure to price, price and production scenarios, interest rate and operating cost changes). In addition to the scheduled redeterminations, the Company and the required lenders may be expected to request unscheduled interim redeterminations of the borrowing base not more than once between scheduled redeterminations. Any increase in the borrowing base will require the consent of all lenders (other than defaulting lenders). If the requisite number of required lenders or all lenders, as applicable in the case of an increase in the borrowing base, do not agree to a proposed borrowing base, then the borrowing base will be the highest borrowing base acceptable to such lenders. We will be required to repay outstanding borrowings in excess of the borrowing base. The borrowing base may also automatically decrease upon the occurrence of certain events.

In the future, we may not be able to access adequate funding under the Credit Facilities as a result of a decrease in our borrowing bases due to the issuance of new indebtedness, the outcome of a borrowing base redetermination, or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover a defaulting lender’s portion. Furthermore, our borrowing base may be reduced if we sell assets in the future. Declines in commodity prices could result in a determination to lower the borrowing base and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions, make distributions to our unitholders or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under the Credit Facilities bear or will bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our business, financial condition and results of operations and cash available for distribution.

The credit risk of financial institutions could adversely affect us.

We have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to financial institutions in the form of derivative transactions in connection with our hedges and insurance companies in the form of claims under our policies and deposit accounts held at regional banks. In addition, if any lender under the Credit Facilities is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under the credit agreement.

Some of the Company’s deposit accounts are held at regional banks. The recent high-profile bank failures involving Silicon Valley Bank, Signature Bank, and First Republic Bank have generated significant market volatility and, in particular, for regional banks. While the Department of the Treasury, the Federal Reserve, and the FDIC have made statements ensuring that depositors of recently failed banks would have access to their deposits, including uninsured deposit accounts, there is no guarantee that such actions will continue for future failed banks, including the regional banks that hold our deposit accounts.

Our ability to obtain financing on terms acceptable to us may be limited in the future by, among other things, increases in interest rates.

We require continued access to capital and our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. We may use the Credit Facilities to finance a portion of our future growth, and these factors could cause our cost of doing business

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to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Volatility in the global financial markets, significant losses in financial institutions’ U.S. energy loan portfolios, or environmental and social concerns may lead to a contraction in credit availability impacting our ability to finance our operations or our ability to refinance the Credit Facilities or other outstanding indebtedness. An increase in interest rates could increase our interest expense and materially adversely affect our financial condition. A significant reduction in cash flow from operations or the availability of credit could materially and adversely affect our ability to carry out our development plan, our cash available for distribution and operating results.

We cannot assure you that we will be able to obtain the New Credit Facility to refinance the indebtedness under the BCE-Mach III credit facility, or that we will be able to refinance the indebtedness we will incur under the New Credit Facility.

There can be no assurance that the New Credit Facility will be obtained on the terms described herein, or at all. In order to obtain the New Credit Facility, we must first obtain commitments from lenders for the New Credit Facility, and agree on final definitive documentation for the New Credit Facility with the lenders. We may not be able to arrange such commitments, or the pricing, size, covenants or other terms of the facility may be less favorable than the New Credit Facility described herein, which could increase our interest costs, reduce our operational or financial flexibility, or reduce our access to liquidity. If we are unable to obtain binding commitments for the New Credit Facility on acceptable terms or at all, the BCE-Mach III credit facility will remain outstanding. After this offering, we expect to apply the net proceeds from the offering of approximately $          , based on the midpoint of the price range on the cover of this prospectus, to partially repay the BCE-Mach III credit facility and to repay in full the BCE-Mach credit facility and the BCE-Mach II credit facility. We cannot assure you that after this offering we will obtain binding commitments for the New Credit Facility sufficient to refinance in full and terminate the BCE-Mach III credit facility. No assurance can be given that any refinancing or additional financing will be possible when needed or that we will be able to negotiate favorable terms. In addition, our access to capital is affected by prevailing conditions in the financial and capital markets and other factors beyond our control. There can be no assurance that market conditions will be favorable at the times that we require new or additional financing. Further, changes by any rating agency to our credit rating may negatively impact the value and liquidity of both our debt and equity securities, as well as the potential costs associated with refinancing our debt, including the BCE-Mach III credit facility and, if ultimately agreed, the New Credit Facility. Downgrades in our credit ratings could also affect the terms of any such financing and restrict our ability to obtain additional financing in the future. Failure to obtain the New Credit Facility or to refinance the indebtedness under the BCE-Mach III credit facility or the New Credit Facility could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we enter into derivative contracts for a portion of our projected oil and natural gas production, primarily consisting of swaps. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosure About Market Risk — Commodity price risk — Commodity derivative activities.” Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

•production is less than the volume covered by the derivative instruments;

•the counterparty to the derivative instrument defaults on its contractual obligations;

•there is an increase in the differential between the underlying price in the derivative instrument and actual prices received for the sale of our production; or

•there are issues regarding legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future

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capital expenditures, make payments on our indebtedness and make distributions to our unitholders, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties and oil and natural gas prices.

The cost to drill and complete oil and natural gas wells often increases in times of rising oil and natural gas prices. To the extent our drilling and completion costs increase, but our derivative arrangements limit the benefit we receive from increases in oil and natural gas prices, our margins could be limited, which could have a material adverse effect on our financial condition. In addition, the amount we pay in severance taxes is calculated without taking our derivative arrangements into account, and if our derivative arrangements limit the benefit we receive from increases in oil and natural gas prices, the effective tax rate we pay in severance taxes could increase.

Our derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of declining commodity prices our derivative contract receivable positions would generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our derivative contracts.

The failure of our hedge counterparties, significant customers or working interest holders to meet their obligations to us may adversely affect our financial results.

Our hedging transactions expose us to the risk that a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make such party unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. Any default by a counterparty to these derivative contracts when they become due could have a material adverse effect on our financial condition and results of operations.

Our ability to collect payments from the sale of oil and natural gas to our customers depends on the payment ability of our customer base, which includes several significant customers. If any one or more of our significant customers fail to pay us for any reason, we could experience a material loss. In addition, if any of our significant customers cease to purchase our oil and natural gas or reduce the volume of the oil and natural gas that they purchase from us, the loss or reduction could have a detrimental effect on our revenues and may cause a temporary interruption in sales of, or a lower price for, our oil and natural gas.

We also face credit risk through joint interest receivables. Joint interest receivables arise from billing entities who own partial working interests in the wells we operate. Though we often have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings, the inability or failure of working interest holders to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

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

Widespread public health crises, epidemics, and outbreaks of infectious diseases, which can give rise to a threat of recession and related economic repercussions can create significant volatility, uncertainty and turmoil in the global economy and oil and gas industry, as did COVID-19 during 2020 through the beginning of 2022. These variables are beyond our control and may have the effect of disrupting the normal operations of many businesses, including the temporary closure or scale-back of business operations and/or the imposition of either quarantine or remote work or meeting requirements for employees, either by government order or on a voluntary basis. While the effects of the COVID-19 outbreak have lessened, widespread public health crises, epidemics and outbreaks of infectious diseases spreading throughout the U.S. and globally, including from a renewed outbreak of COVID-19, could result in significant disruptions to our operations. The global economy, our markets and our business have been, and may continue to be, materially and adversely affected by widespread public health crises, epidemics and

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outbreaks of infectious diseases, which could significantly disrupt our business and operational plans and adversely affect our liquidity, financial condition, results of operations, cash flows and ability to pay distributions on our common units.

Declining general economic, business or industry conditions and inflation may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial market and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. Although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021, which has continued into 2023, due to a substantial increase in money supply, a stimulative fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery. Inflation rose from 7.5% in January 2022 to a peak of 9.1% in June 2022 and then decreased to 6.5% in December 2022. In August 2023, inflation was 3.7%. We continue to undertake actions and implement plans to strengthen our supply chain to address these pressures and protect the requisite access to commodities and services.

Nevertheless, we expect for the foreseeable future to experience supply chain constraints and inflationary pressure on our cost structure. We also may face shortages of these commodities and labor, which may prevent us from fully executing our development plan. These supply chain constraints and inflationary pressures will likely continue to adversely impact our operating costs and, if we are unable to manage our supply chain, it may impact our ability to procure materials and equipment in a timely and cost- effective manner, if at all, which could impact our ability to distribute available cash and result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

We continue to take actions to mitigate supply chain and inflationary pressures. We are working closely with other suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical suppliers which are critical to many of our operations. However, these mitigation efforts may not succeed or may be insufficient.

In addition, continued hostilities related to the Russian invasion of Ukraine and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors and other factors, such as another surge in COVID-19 cases or decreased demand from China, combined with volatile commodity prices, and declining business and consumer confidence may contribute to an economic slowdown and a recession. Recent growing concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our business, financial condition and results of operations.

Oil and gas exploration and production companies are frequently subject to litigation claims from landowners, royalty owners and other interested parties, particularly during periods of declining commodity prices.

Title to oil and gas properties is often unclear and subject to claims by third parties. Additionally, oil and gas companies are frequently subject to claims with respect to underpayment of royalties, environmental hazards and contested ownership of properties, especially during periods of declining commodity prices and therefore revenue and royalty payments. The oil and gas exploration and production business is especially susceptible to increased cost of capital, hedging losses and declining revenues which can result in defaults on third party obligations. These risk and others can result in the incurrence of significant attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

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We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We maintain insurance against some, but not all, operating risks and losses. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

Our operations are subject to all of the risks associated with drilling for and producing oil, natural gas and NGLs and operating gathering and processing facilities including the possibility of:

•environmental hazards, such as releases of pollutants into the environment, including groundwater, surface water, soil and air contamination;

•abnormally pressured formations;

•mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

•ruptures, fires and explosions;

•damage to pipelines, processing plants, compression assets, water infrastructure, and related equipment and surrounding properties caused by tornadoes, floods, freezes, fires and other natural disasters;

•inadvertent damage from construction, vehicles, farm and utility equipment;

•personal injuries and death;

•natural disasters; and

•terrorist attacks targeting oil and natural gas related facilities and infrastructure.

Any of these events could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims by government agencies or third parties for:

•injury or loss of life;

•damage to and destruction of property, natural resources and equipment;

•pollution and other environmental damage;

•regulatory investigations and penalties; and

•repair and remediation costs.

These events may also result in curtailment or suspension of our gathering and processing facilities. A natural disaster or any event such as those described above affecting the areas in which we and our third-party customers operate could have a material adverse effect on our operations. Accidents or other operating risks could further result in loss of service available to us and our third-party customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on portions or all of our gathering facilities.

We may elect not to obtain insurance for certain of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, in some instances, certain insurance could become unavailable or available only for reduced amounts of coverage, including for pollution and other environmental risks. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Extreme weather conditions and the physical risks of climate change could adversely affect our ability to conduct drilling activities in the areas where we operate and the operations of our gathering and processing facilities and have a negative impact on our business and results of operations.

The majority of the scientific community has concluded that climate change may result in more frequent and/or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, which could affect some, or all, of our operations. If any

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such effects were to occur, they could adversely affect or delay demand for oil or natural gas products or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves, which may not be fully insured. For example, our development, optimization and exploitation activities and equipment could be adversely affected by extreme weather conditions, such as hurricanes, thunderstorms, tornadoes and snow or ice storms, or other climate-related events such as wildfires and floods, in each case which may cause a loss of operational efficiency or production from temporary cessation of activity or lost or damaged facilities and equipment. Further, these types of interruptions could result in a decrease in the volumes supplied to our gathering systems, and delays and shutdowns caused by severe weather may have a material negative impact on the continuous operations of our gathering and processing facilities, including interruptions in service. These types of interruptions could negatively impact our ability to meet our contractual obligations to our third-party customers and thereby give rise to certain termination rights or other liabilities under our contracts. Such extreme weather conditions and events could also impact other areas of our operations, including the costs of insurance, access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary resources, such as water, and third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations. Given that our operations are concentrated exclusively in the Anadarko Basin, a number of our properties could experience any of the same weather conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more geographically diversified portfolio of properties. Our ability to mitigate the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning.

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

Increasing attention from governmental and regulatory bodies, investors, consumers, industry and other stakeholders on combating climate change, together with changes in consumer and industrial/commercial behavior, societal pressure on companies to address climate change, investor and societal expectations regarding voluntary climate-related disclosures, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in the enactment of climate change-related regulations, policies and initiatives at the government, regulator, corporate and/or investor community levels, including alternative energy requirements, new fuel consumption standards, energy conservation and emissions reductions measures and responsible energy development; technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in wind, solar and hydrogen power, as well as battery technology); increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services. These developments may in the future adversely affect the demand for products manufactured with, or powered by, petroleum products, as well as the demand for, and in turn the prices of, oil and natural gas products. Such developments may also adversely impact, among other things, our stock price and access to capital markets, and the availability to us of necessary third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to successfully carry out our business strategy. Climate change-related developments may also impact the market prices of or our access to raw materials such as energy and water and therefore result in increased costs to our business.

More broadly, the enactment of climate change-related legislation and regulatory initiatives may in the future result in increases in our compliance costs and other operating costs. For further discussion regarding the risks posed to us by climate change-related legislation and regulatory initiatives, see “— Climate change legislation or regulations restricting emissions of GHGs or requiring the reporting of GHG emissions or climate-related information could result in increased operating costs, impact the demand for the oil and natural gas we produce, and adversely affect our business.”

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Negative perceptions regarding the Company’s industry and related reputational risks may also in the future adversely affect the Company’s ability to successfully carry out the Company’s business strategy by adversely affecting the Company’s access to capital. There have been efforts in recent years, for example, to influence the investment community, including investment advisors, insurance companies, and certain sovereign wealth, pension and endowment funds and other groups, by promoting divestment of fossil fuel equities and pressuring lenders to limit funding and insurance underwriters to limit coverages to companies engaged in the extraction of fossil fuel reserves. Certain financial institutions and members of the investment community have shifted, and others may elect in the future to shift, some or all of their investment into non-fossil fuel related sectors. There is also a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Certain investment banks and asset managers based both domestically and internationally have announced that they are adopting climate change guidelines for their banking and investing activities. Institutional lenders who provide financing to energy companies, such as the Company, have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding. Ultimately, this could make it more difficult to secure funding for exploration and production activities or adversely impact the cost of capital for both the Company and its customers, and could thereby adversely affect the demand and price of the Company’s securities. Limitation of investments in and financings for energy companies could also result in the restriction, delay, or cancellation of infrastructure projects and energy production activities.

More broadly, negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about climate change or other sustainability-related matters, may also lead to increased reputational and litigation risk and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new laws, regulations, guidelines and enforcement interpretations targeting our industry. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations, and such activism could materially and adversely impact our ability to operate our business and raise capital. The foregoing factors may result in downward pressure on the stock prices of oil and gas companies, including the Company’s, and cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. For example, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas, or claims alleging that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or customer. Although the Company is not a party to any such litigation, we could be named in actions making similar allegations, which could lead to costs and materially impact our financial condition in an adverse way.

Our operations are subject to stringent environmental laws and regulations that may affect our operations and expose us to significant costs and liabilities that could exceed current expectations.

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, the release, disposal or discharge of materials into the environment, and occupational health and safety aspects of our operations. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting regulated drilling activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; the prohibition of noise-producing activities; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including threatened and endangered species habitats; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. We may be required to make significant capital and operating expenditures or perform remedial or other corrective actions at our wells and properties to comply with the requirements of these environmental laws and regulations or the terms or conditions of permits issued pursuant to such requirements. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

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There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations (including plugging and abandonment obligations) and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that could occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. For example, lawsuits in which landowners sue every operator in the chain of title for environmental damages to their property are not uncommon in states in which we operate. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In certain instances, citizen groups also have the ability to bring legal proceedings against us regarding our compliance with environmental laws, or to challenge our ability to receive environmental permits that we need to operate. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations or historical oil and natural gas production in our areas of operation, which have been producing oil in certain instances for several decades. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.

The long-term trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, particularly in light of the Biden administration’s focus on addressing climate change, resulting in increased costs of doing business and consequently affecting profitability. For example, in January 2021, President Biden signed an executive order directing the U.S. Department of the Interior (“DOI”) to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program. In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed subject to certain limitations, although litigation over the leasing pause remains ongoing. As a result, it is difficult to predict if and when such areas may be made available for future exploration activities. Further, for example, on November 15, 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources. The proposed rule imposes emissions reduction standards on both new and existing sources in the oil and natural gas industry, expands the scope of Clean Air Act (“CAA”) regulation, and imposes emissions reductions targets to meet the stated goals of the U.S. federal administration. On December6, 2022, the EPA issued the proposed rule supplementing the November 2021 proposed rule. Among other things, the December 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” The EPA’s issuance of the final rule is pending. Further, in September 2021, President Biden publicly announced the Global Methane Pledge, an international pact that aims to reduce global methane emissions to at least 30% below 2020 levels by 2030, and in August 2022, President Biden signed the Inflation Reduction Act of 2022 into law, which incentivizes the reduction of methane emissions and would impose a fee on methane produced by petroleum and natural gas facilities in excess of a specified threshold, among other initiatives. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry as well as our own results of operations, competitive position or financial condition.

To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Climate change legislation or regulations restricting emissions of GHGs or requiring the reporting of GHG emissions or climate-related information could result in increased operating costs, impact the demand for the oil and natural gas we produce, and adversely affect our business.

More stringent laws and regulations relating to climate change and GHGs may be adopted and could cause us to incur material expenses to comply with such laws and regulations. In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment and in the absence of

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comprehensive federal legislation on GHG emission control, the EPA has adopted regulations pursuant to the CAA to monitor, report, and/or reduce GHG emissions from various sources. We cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility.

In addition, Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions, such as by means of cap and trade programs. Cap and trade programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. At the international level, in April 2016, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France, which resulted in an agreement intended to nationally determine their contributions and set GHG emission reduction goals every five years beginning in 2020. In November 2019, plans were formally announced for the U.S. to withdraw from the Paris Agreement with an effective exit date in November 2020. In February 2021, the current administration announced reentry of the U.S. into the Paris Agreement along with a new “nationally determined contribution” for U.S. GHG emissions that would achieve emissions reductions of at least 50% relative to 2005 levels by 2030. In September 2021, President Biden publicly announced the Global Methane Pledge, an international pact that aims to reduce global methane emissions to at least 30% below 2020 levels by 2030. To date, over 150 countries have joined the pledge. Various state and local governments have also vowed to continue to enact regulations to satisfy their proportionate obligations under the Paris Agreement.

Any legislation or regulatory programs addressing GHG emissions could increase the cost of consuming, and thereby reduce demand for, the natural gas we produce, and could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements, and to monitor and report on GHG emissions. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Moreover, incentives or requirements to conserve energy, use alternative energy sources, reduce GHG emissions in product supply chains, and increase demand for low-carbon fuel or zero-emissions vehicles, could reduce demand for the oil and natural gas we produce. The Inflation Reduction Act of 2022, for example, provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture and other programs directed at addressing climate change. Additionally, the SEC issued a proposed rule in March 2022 that would mandate extensive disclosure of climate-related data, risks and opportunities, including financial impacts, physical and transition risks, related governance and strategy and GHG emissions, for certain public companies.

Although it is not currently possible to predict how these executive orders, national commitments or any proposed or future GHG or climate change legislation or regulation promulgated by Congress, the states or multi- state regions and their respective regulatory agencies will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate could result in increased compliance or operating costs or additional operating restrictions or reduced demand for our products, and could have a material adverse effect on our business, financial condition and results of operations. For further discussion of certain existing and proposed climate-related rules and regulations, see “Business and Properties — Legislative and regulatory environment.”

Increased scrutiny of ESG matters could have an adverse effect on our business, financial condition and results of operations and damage our reputation.

In recent years, companies across all industries are facing increasing scrutiny from a variety of stakeholders, including investor advocacy groups, proxy advisory firms, certain institutional investors and lenders, investment funds and other influential investors and rating agencies, related to their ESG and sustainability practices. If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters as they continue to evolve, or if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, we may suffer from reputational damage and our business, financial condition and/or stock price could be materially and adversely affected. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such

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ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.

Further, our operations, projects and growth opportunities require us to have strong relationships with various key stakeholders, including our shareholders, employees, suppliers, customers, local communities and others. We may face pressure from stakeholders, many of whom are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability while at the same time remaining a successfully operating company. If we do not successfully manage expectations across these varied stakeholder interests, it could erode stakeholder confidence and thereby affect our brand and reputation. Such erosion of confidence could negatively impact our business through decreased demand and growth opportunities, delays in projects, increased legal action and regulatory oversight, adverse press coverage and other adverse public statements, difficulty hiring and retaining top talent, difficulty obtaining necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and difficulty securing investors and access to capital.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays, limit the areas in which we can operate, and reduce our oil and natural gas production, which could adversely affect our production and business.

Hydraulic fracturing is a common practice used to stimulate production of oil and/or natural gas from dense subsurface rock formations and is important to our business. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We and our third-party operators use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies or trigger seismic activity. Proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing.

Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. Local governments may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibiting the performance of well drilling in general or hydraulic fracturing in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

In addition, the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities. The EPA also finalized rules under the Clean Water Act (“CWA”) in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under some circumstances. In March 2016, the U.S. Occupational Safety and Health Administration issued a final rule to impose stricter standards for worker exposure to silica, which went into effect in June 2018 and applies to use of sand as a proppant for hydraulic fracturing. The U.S. Department of the Interior’s Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. Following years of litigation, the BLM rescinded this rule in December 2017. However, California and various environmental groups filed lawsuits in January 2018 challenging the BLM’s rescission of the rule and, in March 2020, the U.S. District Court for the Northern District of California upheld the BLM’s decision to rescind the rule. However, there is ongoing litigation regarding the BLM rules, and future implementation of these rules is uncertain at this time. On November 30, 2022, the BLM also issued a proposed rule to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on Federal and Indian leases. New laws or regulations that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic

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fracturing activities and thereby affect our determination of whether a well is commercially viable and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material adverse effect on our business, prospects, financial condition, results of operations and liquidity.

Legislation or regulatory initiatives intended to address the disposal of saltwater gathered from our drilling activities could limit our ability to produce oil and natural gas economically and have a material adverse effect on our business.

We dispose of large volumes of saltwater gathered from our drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of saltwater gathered from our drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

We are responsible for the decommissioning, abandonment, and reclamation costs for our facilities, which could decrease our cash available for distribution.

We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, abandonment and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, abandonment and reclamation reserve funds to provide for payment of future decommissioning, abandonment and reclamation costs, which could decrease our cash available for distribution. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, abandonment and reclamation costs and we will be responsible for the payment of the balance of such costs.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife and/or habitats. The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in material restrictions to land use and may materially delay or prohibit land access for natural gas development. The Trump administration issued rules that narrowed the definition of “habitat” and altered a policy in a way that made it easier to exclude territory from critical habitat. In October 2021, the Biden administration published two rules that reversed those changes, and in June and July 2022, the FWS issued final rules rescinding Trump-era regulations concerning the definition of “habitat” and critical habitat exclusions. The designation of previously unprotected species as threatened or endangered or new critical or suitable habitat designations in areas where we conduct operations could result in limitations or prohibitions on our operations and could adversely impact our business, and it is possible the new rules could increase the portion of our lease areas that could be designated as critical habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the United States. Permanent restrictions imposed to protect threatened or endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered or further changes to regulations could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures which may adversely impact our business or operations.

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The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swap contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The full impact of the Dodd-Frank Act’s swap regulatory provisions and the related rules of the CFTC on our business will not be known until all of the rules to be adopted under the Dodd-Frank Act have been adopted and fully implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.

In addition, the European Union and other non-U.S. jurisdictions have implemented and continue to implement regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, which could have adverse effects on our operations similar to the possible effects on our operations of the Dodd-Frank Act’s swap regulatory provisions and the rules of the CFTC.

We may be involved in legal and regulatory proceedings that could result in substantial liabilities.

Like many oil and gas companies, we are, or may be, from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters, alleged violations of federal or state securities laws and personal injury, environmental damage or property damage matters, in the ordinary course of our business. Additionally, members of our management and our directors may, from time to time, be involved in various legal and other proceedings against the Company naming those officers or directors as co-defendants. Such legal and regulatory proceedings are inherently uncertain, and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition and affect the value of our common units. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material. The defense of any legal proceedings against us or our officers or directors, could take resources away from our operations and divert management attention. As of the date of this prospectus, the Company is not aware of any material legal or environmental proceedings contemplated to be brought against the Company or its management.

Loss of our information and computer systems could adversely affect our business. Our business could be negatively impacted by security threats, including cyber-security threats and other disruptions.

We are heavily dependent on our information systems and computer-based programs, including our well operations information, geologic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches or attacks, possible consequences include our loss of communication links, inability to find, produce, process and sell natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such

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as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.

We are subject to a number of privacy and data protection laws, rules and directives (collectively, data protection laws) relating to the processing of personal data.

The regulatory environment surrounding data protection laws is uncertain. Varying jurisdictional requirements could increase the costs and complexity of compliance with such laws, and violations of applicable data protection laws can result in significant penalties. A determination that there have been violations of applicable data protection laws could expose us to significant damage awards, fines and other penalties that could materially harm our business and reputation.

Any failure, or perceived failure, by us to comply with applicable data protection laws could result in proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and complexity of compliance and adversely affect our business. As noted above, we are also subject to the possibility of security and privacy breaches, which themselves may result in a violation of these laws. Additionally, the acquisition of a company that is not in compliance with applicable data protection laws may result in a violation of these laws.

Risks Inherent in an Investment in Us

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

Our general partner will have control over all decisions related to our operations. Upon consummation of this offering, the Sponsor and Tom L. Ward through his ownership of Mach Resources will own all of the membership interests in our general partner which will be in the same proportion to each other as their limited partner interest ownership in us. The Sponsor and Tom L. Ward through his ownership of Mach Resources will also own an aggregate of approximately and     , respectively, of our outstanding common units (or    and   , respectively, of our outstanding common units if the underwriters exercise in full their option to purchase additional common units). Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of us and our unitholders, the executive officers and directors of our general partner also have a duty to manage our general partner at the direction of the Sponsor and Tom L. Ward through his ownership of Mach Resources. As a result of these relationships, conflicts of interest may arise in the future between the Sponsor, Tom L. Ward in his capacity as a member of our general partner through his ownership of Mach Resources and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand; provided, however, that upon our adoption of our code of business conduct, we would expect that any such member of our management, so long as they are an executive officer, will be required to avoid personal conflicts of interest and not compete against us, in each case unless approved by the Board. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of us and our common unitholders. These conflicts include, among others, the following:

•Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

•Neither our partnership agreement nor any other agreement requires the Sponsor (excluding our general partner) to pursue a business strategy that favors us;

•The Sponsor is not limited in its ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer or sell assets to us;

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•Our general partner determines the amount and timing of our development operations and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;

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

•Our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

•Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

•Our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

•Our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than       % of the common units;

•Our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

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

Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Duties.”

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

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Affiliates of our general partner are not prohibited from owning projects or engaging in businesses that compete directly or indirectly with us. Similarly, our partnership agreement does not limit the Sponsor’s ability to compete with us and the Sponsor does not have any obligation to present business opportunities to us.

In addition, certain of our officers and directors may in the future hold similar positions with investment partnerships or other private entities that are in the business of identifying and acquiring mineral and royalty interests. In such capacities, these individuals would likely devote significant time to such other businesses and would be compensated by such other businesses for the services rendered to them. The positions of these directors and officers may give rise to duties that are in conflict with duties owed to us. In addition, these individuals may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may be affiliated. Due to these potential future affiliations, they may have duties to present potential business opportunities to those entities prior to presenting them to us, which could cause additional conflicts of interest. The Sponsor will be under no obligation to make any acquisition opportunities available to us. See “Conflicts of Interest and Duties.”

Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and holders of our common units.

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

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with different contractual standards. For example, our partnership agreement provides that:

•whenever our general partner (acting in its capacity as our general partner), the Board or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the Board and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was not adverse to our best interests, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or equitable principle;

•our general partner may make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and 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 the partnership agreement does not provide for a clear course of action. This provision 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 our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

•how to allocate corporate opportunities among us and its other affiliates;

•whether to exercise its limited call right;

•whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the Board; provided, however, the MSA will require 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;

•how to exercise its voting rights with respect to the units it owns;

•whether to sell or otherwise dispose of any units or other partnership interests it owns; and

•whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

•our general partner will not have any liability to us or our unitholders for breach of any duty in connection with decisions made in its capacity as general partner so long as it acted in good faith (meaning that it subjectively believed that the decision was not adverse to our best interest);

•our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions 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 and directors 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

•our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

•approved by the conflicts committee of the Board, although our general partner is not obligated to seek such approval;

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

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•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 among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our 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 satisfies either of the standards set forth in the third and fourth sub-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.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production and make acquisitions.

Our partnership agreement provides that we distribute each quarter all of our available cash, which we define as cash on hand at the end of each quarter, less reserves established by our general partner. As a result, we expect to rely primarily upon our cash reserves and external financing sources, including the issuance of additional common units and other partnership securities and borrowings under our New Credit Facility, to fund future acquisitions and finance our growth. To the extent we are unable to finance growth with our cash reserves and external sources of capital, the requirement in our partnership agreement to distribute all of our available cash may impair our ability to grow.

A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:

•general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;

•conditions in the oil and gas industry;

•the market price of, and demand for, our common units;

•our results of operations and financial condition; and

•prices for oil, natural gas and NGLs.

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are and will be no limitations in our partnership agreement or the Credit Facilities on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our business strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase. In addition, as with other yield-oriented securities, our unit price is impacted by the level of our cash distributions to our unitholders and implied distribution yield. This implied distribution yield is often used by investors to compare and rank similar yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity or incur debt. See “— Increased costs of capital could adversely affect our business.”

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Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem the units of certain non-citizen unitholders.

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. 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. Please read “The Partnership Agreement — Non-Citizen Unitholders; Redemption.”

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

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business.

Our unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The Board, including the independent directors, is chosen entirely by the Sponsor and Tom L. Ward through his ownership of Mach Resources, as a result of their ownership of our general partner, and not by our unitholders. Please read “Management — Management of Mach Natural Resources” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Our general partner will have control over all decisions related to our operations. Since, upon consummation of this offering, affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) collectively will own and control the voting of an aggregate of approximately% of our outstanding common units (or   % of our outstanding common units if the underwriters exercise in full their option to purchase additional common units), the other unitholders will not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. However, our partnership agreement can generally be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources)). Assuming we do not issue any additional common units and affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) do not transfer any of their common units, affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) will generally have the ability to control any amendment to our partnership agreement, including our policy to distribute all of our cash available for distribution to our unitholders. Furthermore, the goals and objectives of the affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) that hold our common units relating to us may not be consistent with those of a majority of the other unitholders. Please read “— Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.”

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

The public unitholders will be unable initially to remove our general partner without its consent because affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) will own sufficient units upon completion of this offering to be able to prevent the removal of our general partner. Our general partner may not be removed except by vote of the holders of at least 66⅔% of all outstanding units voting together as a single class is required to remove our general partner. Following consummation of this offering, affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) will own approximatelyof our outstanding common units (or     of our outstanding common units if the underwriters exercise in full their option to purchase additional common units), which will enable those holders, collectively, to prevent the removal of our general partner.

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Control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the Sponsor or Tom L. Ward through his ownership of Mach Resources which controls our general partner, from transferring all or a portion of their ownership interests in our general partner to a third party. The new owner of our general partner would then be in a position to replace the Board and officers of our general partner with their own choices and thereby influence the decisions made by the Board and officers.

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

Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

•our unitholders’ proportionate ownership interest in us will decrease;

•the amount of cash available for distribution on each unit may decrease;

•the ratio of taxable income to distributions may increase;

•the relative voting strength of each previously outstanding unit may be diminished; and

•the market price of our common units may decline.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group owning 20% or more of any class of common units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the Board, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.

Once our common units are publicly traded, the Existing Owners may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered hereby, the Sponsor will own            common units (or              of our common units if the underwriters exercise in full their option to purchase additional common units), or approximately            % of our limited partner interests (or      % of our limited partner interests if the underwriters exercise in full their option to purchase additional common units), and management will own common units (or       of our common units if the underwriters exercise in full their option to purchase additional common units), or approximately    % of our limited partner interests (or    % of our limited partner interests if the underwriters exercise in full their option to purchase additional common units). 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, which includes the Sponsor and Tom L. Ward through his ownership of Mach Resources. Once our common units are publicly traded, the sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

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

If at any time our general partner and its affiliates own more than % of the then outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result,

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you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercises its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. At the closing of this offering, affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) will own approximately% of our common units (or    % of our common units if the underwriters exercise in full their option to purchase additional common units). For additional information about this call right, please read “The Partnership Agreement — Limited Call Right.”

Our partnership agreement will designate the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner or its directors, officers or other employees.

Our partnership agreement will provide that, with certain limited exceptions, the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court in the State of Delaware with subject matter jurisdiction) will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our 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), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a 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, (4) asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act or (5) asserting a claim against us governed by the internal affairs doctrine. 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

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partner is irrevocably consenting to these limitations, provisions and obligations 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 court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us, our general partner and our general partner’s directors and officers. For additional information about the exclusive forum provision of our partnership agreement, please read “The Partnership Agreement — Applicable Law; Forum, Venue and Jurisdiction.”

Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf pursuant to the MSA will reduce cash available for distribution to our unitholders. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. The amount and timing of such reimbursements will be determined by our general partner.

At the closing of this offering, we and our general partner will also enter into a MSA with Mach Resources pursuant to which Mach Resources will manage and perform all aspects of our oil and gas and midstream operations and other general and administrative functions in exchange for reimbursement of certain expenses. On a monthly basis, we will reimburse our general partner and its affiliates for certain expenses they incur and payments they make on our behalf pursuant to the MSA. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. 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 partnership agreement provides that our general partner will determine the expenses that are allocable to us. The reimbursement of expenses to our general partner and its affiliates will reduce the amount of cash available for distribution to our unitholders. For the six months ended June30, 2023, we paid $39.0 million to Mach Resources, which consists of $3.6million for an annual management fee and $35.4million for reimbursements of its costs and expenses under the existing management services agreements among Mach Resources and the Mach Companies.

The NYSE does not require a publicly traded limited partnership like us to comply, and we do not intend to comply, with certain of its governance requirements generally applicable to corporations.

We have applied to list our common units on the NYSE under the symbol “MNR.” Because we will be a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements. Please read “Management — Management of Mach Natural Resources.”

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a Delaware limited partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:

•a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•a unitholder’s right to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.

Please read “The Partnership Agreement — Limited Liability” for a discussion of the implications of the limitations of liability on a unitholder.

Our unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

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Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Our unitholders may have limited liquidity for their common units, a trading market may not develop for the common units and our unitholders may not be able to resell their common units at the initial public offering price.

Prior to this offering, there has been no public market for the common units. After this offering, there will bepublicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Our unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, a lack of liquidity would likely result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

If our common unit price declines after the initial public offering, our unitholders could lose a significant part of their investment.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

•changes in commodity prices;

•changes in securities analysts’ recommendations and their estimates of our financial performance;

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

•fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded partnerships and limited liability companies;

•changes in market valuations of similar companies;

•departures of key personnel;

•commencement of or involvement in litigation;

•variations in our quarterly results of operations or those of other oil and natural gas companies;

•variations in the amount of our quarterly cash distributions to our unitholders;

•changes in tax law;

•an election by our general partner to convert or restructure us as a taxable entity;

•future issuances and sales of our common units; and

•changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry.

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

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For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies, including those relating to auditing standards and disclosure about our executive compensation. Taking advantage of the longer phase-in periods for the adoption of new or revised financial accounting standards applicable to emerging growth companies may make our common units less attractive to investors.

The JOBS Act contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to auditing standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) 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, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.

We intend to take advantage of all of the reduced reporting requirements and exemptions available to emerging growth companies under the JOBS Act, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act, until we are no longer an emerging growth company. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.

Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. We cannot predict if investors will find our common units less attractive because we will rely on these exemptions. If some investors find our common units less attractive as a result, there may be a less active trading market for our common units and our common unit price may be more volatile. Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards until such time as those standards apply to private companies.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. As a newly public company, we will not be required to make our first annual assessment of our internal controls over financial reporting pursuant to Section 404 until the year following our first annual report to be filed with the SEC, but we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis. We will not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls over financial reporting until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

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Our general partner may elect to convert or restructure us from a partnership to an entity taxable as a corporation for U.S. federal income tax purposes without unitholder consent.

Under our partnership agreement, our general partner may, without unitholder approval, cause us to be treated as an entity taxable as a corporation or subject to entity-level taxation for U.S. federal income tax purposes, whether by election of the partnership or conversion of the partnership or by any other means or methods. In addition and as part of such determination, affiliates of our general partner may choose to retain their partnership interests in us and cause us to enter into a transaction in which our interests held by other persons are converted into or exchanged for interests in a new entity, taxable as a corporation or subject to entity-level taxation for U.S. federal purposes, whose sole assets are interests in us. 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 be material to such unitholder and may vary depending on the unitholder’s particular situation and may vary from the tax liability of us or of any affiliates of our general partner who choose to retain their partnership interests in us. 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. Please read “The Partnership Agreement — Election to be Treated as a Corporation.”

We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs. The amount of our expenses or reserves for expenses, including the costs of being a publicly traded partnership will reduce the amount of cash we have for distribution to our unitholders. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a public company.

Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded company, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting.

We also expect to incur additional expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on the Board or as executive officers than it was prior to this offering.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our units or if our operating results do not meet their expectations, our unit price could decline.

The trading market for our common units will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our unit price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common units or if our operating results do not meet their expectations, our unit price could decline.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, prospective unitholders should read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material U.S. federal income tax consequences of owning and disposing of our common units.

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

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based on our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our classification as a partnership for U.S. federal income tax purposes.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate and we would also likely pay additional state and local income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distribution to our unitholders could be reduced. Thus, treatment of us as a corporation could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which would cause a reduction in the value of our common units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, capital, and other forms of business taxes, as well as subjecting nonresident partners to taxation through the imposition of withholding obligations and composite, combined, group, block, or similar filing obligations on nonresident partners receiving a distributive share of state “sourced” income. We currently own property or do business in Oklahoma, Kansas and Texas, among other states. Imposition on us of any of these taxes in jurisdictions in which we own assets or conduct business or an increase in the existing tax rates could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which would cause a reduction in the value of our common units.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

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 legislative, judicial or administrative changes and differing interpretations. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships or an investment in our common units, including elimination of partnership tax treatment for certain 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.

Any changes to U.S. federal income tax laws or interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to be treated as a partnership for U.S. federal income tax purposes or otherwise adversely affect our business, financial condition or results of operations. Any such changes to U.S. federal income tax laws or interpretations thereof could adversely impact the value of an investment in our common units.

Certain U.S. federal income tax incentives currently available with respect to oil and natural gas exploration and production may be reduced or eliminated as a result of future legislation.

In recent years, legislation has been proposed that would, if enacted, make significant changes to U.S. tax laws, including the reduction or elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes 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

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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.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.

We will generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of the common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A successful IRS contest of the U.S. federal income tax positions we take may adversely impact the market for our common units and the cost of any IRS contest will reduce our cash available for distribution to unitholders.

The IRS has made no determination as to our status as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. As a result, any such contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade. In addition, our costs of any contest with the IRS, principally legal, accounting and related fees, will be indirectly borne by our unitholders because the costs will reduce our cash available for distribution.

If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. If we bear such payment, our cash available for distribution to our unitholders might be substantially reduced.

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 the Mach Companies in respect of periods beginning prior to the closing of this offering), it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. 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 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.

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

Because our unitholders will be treated as partners to whom we will allocate taxable income, our unitholders may be required to pay U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from their share of our taxable income.

Tax gains or losses on the disposition of our common units could be more or less than expected.

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in the unitholder’s common units, the amount,

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if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than the unitholder’s tax basis in those common units, even if the price received is less than the unitholder’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items such as depreciation, depletion, amortization and accretion expense and intangible drilling costs. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of the cash received from the sale.

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

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

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investments in our common units by tax-exempt entities, such as individual retirement accounts (“IRAs”) or other retirement plans, raise issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. A tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to 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 entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor regarding the impact of these rules on an investment in our common units.

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our common units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable marginal tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.

Moreover, upon the sale, exchange or other disposition of a common unit by a non-U.S. 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. Distributions to non-U.S. unitholders may also be subject to additional 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. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

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We will treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation, depletion, amortization and accretion positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.

Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.

In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes imposed by the various jurisdictions in which we do business or own property now or in the future, even if the unitholder does not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property or conduct 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 or entity-level income tax. It is the responsibility of each unitholder to file its own U.S. federal, state and local tax returns, as applicable.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, the unitholder 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.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from lending their common units.

We will adopt certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our respective 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. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction. A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

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USE OF PROCEEDS

We expect the net proceeds from the offering to be approximately $million ($  million if the underwriters exercise their option to purchase additional units in full), based upon the assumed initial public offering price of $   per common unit (the midpoint of the price range set forth on the cover of this prospectus), after deducting underwriting discounts and estimated expenses. We expect to use the proceeds from this offering as follows: to (i) repay in full and terminate the BCE-Mach II credit facility under which approximately $17.1million was outstanding as of September1, 2023 and (ii) repay in full and terminate the BCE-Mach credit facility under which approximately $65.0million was outstanding as of September1, 2023. Following the application of such proceeds, we expect to use the remainder to (i) repay a portion of the BCE-Mach III credit facility under which $91.9million was outstanding as of September1, 2023 and (ii) purchase common units from the existing common unit owners on a pro rata basis for $            million (the “Exchanging Members”) (at a purchase price per unit based on the initial public offering price, net of underwriting discounts and commissions), with any remainder for general partnership purposes. To the extent the number of units in the offering is increased or decreased, the number of units purchased from the Exchanging Members will increase or decrease in the same proportion as the total number of units in the offering is increased or decreased. We are currently negotiating the New Credit Facility with prospective lenders and if we enter into the New Credit Facility after the closing of the offering, we would use borrowings under the New Credit Facility to repay in full and terminate the BCE-Mach III credit facility. See “Reorganization Transactions, Partnership Structure and Expected Refinancing Transactions — Expected Refinancing Transactions” for additional information.

If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds would be approximately $    million. The net proceeds from any exercise of such option will be used to purchase  common units from the Exchanging Members (at a purchase price per unit based on the initial public offering price, net of underwriting discounts and commissions). Please read “Underwriting.”

As of September1, 2023, we had (i) $65.0million of outstanding borrowings and $5million in outstanding letters of credit under the BCE-Mach credit facility, (ii) $17.1million of outstanding borrowings under the BCE-Mach II credit facility and (iii) $91.9million of outstanding borrowings under the BCE-Mach III credit facility. The BCE-Mach credit facility matures in September 2026, the BCE-Mach II credit facility matures in September 2024 and the BCE-Mach III credit facility matures in May 2026. Borrowings outstanding under the Existing Credit Facilities bore an effective interest rate between 8.3% and 8.5% as of June30, 2023. Borrowings under the Existing Credit Facilities have been incurred primarily to fund our capital expenditures and acquisitions. The Existing Credit Facilities will be repaid as described above in connection with this offering. For more information on our Existing Credit Facilities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt agreements — Existing Credit Facilities.”

A $1.00 increase or decrease in the assumed initial public offering price of $            per common unit would cause the net proceeds from this offering, after deducting underwriting discounts and estimated offering expenses payable by us, to increase or decrease, respectively, by approximately $            million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of         million common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $   per common unit, would increase net proceeds to us from this offering by approximately $      million. Similarly, each decrease of     million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price of $    per common unit, would decrease the net proceeds to us from this offering by approximately $   million. Any change in proceeds retained by us as a result of any change in the initial public offering price would impact the amount of proceeds that we could use to purchase common units from the Exchanging Members.

The sources and use of our proceeds may differ from those set forth above. The foregoing represents our current intentions with respect to the use and allocation of the net proceeds of this offering based upon our present plans and business condition, but our management will have significant flexibility and discretion in applying the net proceeds. The occurrence of unforeseen events or changed business conditions could result in application of the net proceeds of this offering in a manner other than as described in this prospectus.

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CAPITALIZATION

The following table shows:

•our predecessor’s historical capitalization as of June30, 2023; and

•our capitalization as adjusted to give effect to (i) the Reorganization Transactions and (ii) this offering and the application of the net proceeds as described under “Use of Proceeds.”

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical and unaudited pro forma condensed combined financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” For a description of the pro forma adjustments, please read our unaudited pro forma condensed combined financial statements.

	As of June 30, 2023
	Predecessor Historical		As Adjusted
Cash and cash equivalents	$	48,846	$
Long-term debt:
Existing Credit Facilities(1)	$	91,900	$
Members’/partners’ capital/net equity:
Common equity held by the public	$	—	$
Common equity held by the Existing Owners	$	689,527	$
Total members’/partners’ capital/net equity	$	689,527	$
Total capitalization	$	781,427	$

____________

(1)As of September 1, 2023, we had approximately $17.1 million of outstanding borrowings under our BCE-Mach II credit facility, approximately $65.0 million of outstanding borrowings under our BCE-Mach credit facility and approximately $91.9 million of outstanding borrowings under our BCE-Mach III credit facility. Following completion of this offering, we expect to enter into the New Credit Facility. Once we have entered into the New Credit Facility, we expect to use borrowings under the New Credit Facility to repay in full and terminate the BCE-Mach III credit facility. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt agreements — Existing Credit Facilities” and “Use of Proceeds.”

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per common unit after this offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial offering price of $   per common unit (the midpoint of the price range set forth on the cover of this prospectus), on a pro forma basis as of June30, 2023, after giving effect to the Reorganization Transactions, this offering of common units and the application of the related net proceeds, our net tangible book value would have been $            million, or $            per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for accounting purposes, as illustrated in the following table:

Assumed initial public offering price per common unit		$
Pro forma net tangible book value per common unit before this offering(1)	$
Decrease in net tangible book value per common unit attributable to purchasers in the offering
Less: Pro forma net tangible book value per common unit after this offering(2)
Immediate dilution in net tangible net book value per common unit to purchasers in the offering(3)(4)		$

____________

(1)Determined by dividing the pro forma net tangible book value of our net assets immediately prior to the offering by the number of common units held by the Existing Owners, after giving effect to the Reorganization Transactions.

(2)Determined by dividing our pro forma as adjusted net tangible book value, after giving effect to the application of the net proceeds of this offering, by the total number of units to be outstanding after this offering after giving effect to the Reorganization Transactions.

(3)If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $and $, respectively.

(4)Because the total number of units outstanding following the consummation of this offering will be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will be retained by us, there will be a change to the dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the underwriters’ option to purchase additional common units.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by the Existing Owners and by the purchasers of common units in this offering upon the closing of the transactions contemplated by this prospectus after giving effect to the Reorganization Transactions:

	Units Acquired		Total Consideration
	Number	Percent	Amount	Percent
		(in thousands)
Existing Owners(1)(2)(3)		%		%
Purchasers in the offering(2)		%		%
Total		100.0%		100.0%

____________

(1)Total consideration is after deducting underwriting discounts and estimated offering expenses.

(2)Assumes the underwriters’ option to purchase additional common units from us is not exercised.

(3)BCE-Mach LLC and BCE-Mach II LLC were recorded at fair value in accordance with GAAP, while our Predecessor was recorded at book value in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates, as of June 30, 2023, after giving effect to the application of the net proceeds of the offering, is as follows:

	(in thousands)
Book value of net assets contributed	$
Less: Proceeds to Exchanging Members from net proceeds of this offering
Net consideration	$

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading “— Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

General

Our Cash Distribution Policy

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. Generally, we define available cash as the sum of our (i) cash on hand at the end of a quarter after the payment of our costs and expenses and the establishment of cash reserves, (ii) cash on hand on the date on which our general partner determines the amount of cash available for distribution, which we refer to as 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, and (iii) if our general partner so determines, cash on hand at the date of determination resulting from working capital borrowings made after the end of the quarter. We may, but are under no obligation to, borrow funds to make quarterly distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Further, we may rely upon our cash reserves (including the net proceeds that we will retain from this offering) and external financing sources, including borrowings under the Credit Facilities (under which no amounts will be outstanding at the closing of this offering) and the issuance of debt and equity securities, to fund future acquisitions and other expenditures. We also plan to continue our practice of opportunistically entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations, and therefore reduce volatility in quarterly distributions. Because we are not subject to an entity-level U.S. federal income tax, we expect to have more cash to distribute to our unitholders than would be the case if we were subject to such U.S. federal income tax.

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.

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.

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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.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

Although our partnership agreement requires that we distribute all of our available cash quarterly, there is no guarantee that we will make quarterly cash distributions from our available cash to our unitholders at the level currently estimated or at all, and we have no legal obligation to do so. Our current cash distribution policy is subject to certain restrictions, as well as the considerable discretion of our general partner in determining the amount of our available cash each quarter. The following factors will affect our ability to make cash distributions, as well as the amount of any cash distributions we make:

•Our cash distribution policy may be subject to restrictions on distributions under the Credit Facilities or other debt agreements that we may enter into in the future. Specifically, the BCE-Mach III credit facility contains and we expect the New Credit Facility will contain financial tests and covenants that we must satisfy. These financial tests and covenants are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt agreements.” Should we be unable to satisfy these restrictions, or if a default occurs under the Credit Facilities, we would be prohibited from making cash distributions to our unitholders notwithstanding our stated cash distribution policy. Any future indebtedness may contain similar or more stringent restrictions.

•The amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Specifically, our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders. If our general partner does not set aside sufficient cash reserves, or make sufficient cash capital expenditures to maintain the current production levels over the long-term of our oil and natural gas properties, we will be unable to pay any cash distributions from cash generated from operations. We are unlikely to be able to sustain our current level of distributions without making accretive acquisitions or capital expenditures that maintain the current production levels of our oil and natural gas properties. Decreases in commodity prices from current levels will adversely affect our ability to pay distributions.

•Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Mach Resources, for all direct and indirect expenses they incur on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. 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 partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay cash distributions to our unitholders.

•Although our partnership agreement requires us to distribute all of our available cash each quarter, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by affiliates of our general partner). At the closing of this offering, the affiliates of our general partner (including the Sponsor and Tom L. Ward through his ownership of Mach Resources) will own approximately % of our outstanding common units (or% of our outstanding common units if the underwriters exercise in full their option to purchase additional common units). For more information, please read “The Partnership Agreement — Amendment of the Partnership Agreement.”

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•Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner.

•Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

•We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including decreases in commodity prices, decreases in our oil and natural gas production, or increases in our general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements or anticipated cash needs.

•If and to the extent our cash available for distribution materially declines, we may reduce our quarterly distribution in order to service or repay our debt or fund maintenance or growth capital expenditures.

•We will not have a minimum quarterly distribution. Furthermore, none of our limited partner interests, including those held by the Existing Owners, will be subordinate in right of payment to the common units sold in this offering.

•Our general partner may reduce our distributions if action is taken by our general partner as described under “The Partnership Agreement — Election to be treated as a Corporation” that results in our becoming taxable as a corporation or otherwise subject to taxation as an entity for U.S. federal income tax purposes. In such an event, the distribution levels may be reduced to account for any current and future estimated tax liabilities we would incur as a corporation. The distributions will also be proportionately adjusted in the event of any distribution, combination or subdivision of common units in accordance with the partnership agreement. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Our Partnership Agreement Requires That We Distribute All of Our Available Cash, Which Could Limit Our Ability to Grow

Our partnership agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, our growth may not be as fast as the growth of businesses that reinvest all of their available cash to expand ongoing operations. Further, we may rely upon our cash reserves (including the net proceeds that we will retain from this offering) and external financing sources, including borrowings under the Credit Facilities and the issuance of debt and equity securities, to fund future acquisitions and other capital expenditures. To the extent we require external sources of capital to fund our growth and are unable to access such sources, the requirement in our partnership agreement to distribute all of our available cash and our current cash distribution policy may impair our ability to grow. The Credit Facilities limit, and any future debt agreements may limit, our ability to incur additional debt, including through the issuance of debt securities. Please read “Risk Factors — Risks Related to Our Business — Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Year Ended December31, 2022 Compared to Year Ended December31, 2021 — Debt Agreements — Existing Credit Facilities.” To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our cash distributions per unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to our common units, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. If we incur additional debt to finance our business strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders. Please read “Risk Factors — Risks Related to Our Business — Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.”

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2022 and the Twelve Months Ended June 30, 2023

On a pro forma basis, assuming we had completed this offering on January 1, 2022, our cash available for distribution for the year ended December 31, 2022 and the twelve months ended June30, 2023 would have been approximately $402.0million and $220.6million, respectively. This amount would have been sufficient to pay a cash distribution of $            per unit per quarter ($            on an annualized basis) during the year ended December 31, 2022, and a cash distribution of $            per unit per quarter ($            on an annualized basis) during the twelve months ended June30, 2023.

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The unaudited pro forma financial data does not give pro forma effect to the incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership. We estimate that these incremental general and administrative expenses initially will be approximately $6.0million per year. Such incremental general and administrative expenses are not reflected in our historical or pro forma financial statements.

The pro forma financial statements, from which pro forma cash available for distribution is derived, do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, cash available for distribution is a cash accounting concept, while our unaudited pro forma financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution stated above in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods.

The following table illustrates, on an unaudited pro forma basis for the year ended December 31, 2022 and the twelve months ended June30, 2023, the amount of available cash that would have been available for distribution to our unitholders, assuming in each case that this offering had been consummated on January 1, 2022.

Mach Natural Resources
Unaudited Pro Forma Cash Available for Distribution

	Pro Forma Year Ended December 31, 2022			Pro Forma Twelve Months Ended June 30, 2023
	(in thousands, except per unit amounts)
Net Income	$	639,084		$	563,361
Interest expense, net		4,231			4,831
Depreciation, depletion and amortization		124,804			150,605
Unrealized (gain) loss on derivative settlements		(53,730	)		(95,493	)
Equity-based compensation expense		—			—
Loss on contingent consideration		—			—
Credit losses		—			767
(Gain) loss on sale of assets		(94	)		(142	)
Adjusted EBITDA(1)	$	714,295		$	623,929
Net Income	$	639,084		$	563,361
Interest expense, net		4,231			4,831
Depreciation, depletion and amortization		124,804			150,605
Unrealized (gain) loss on derivative settlements		(53,730	)		(95,493	)
Equity-based compensation expense		—			—
Loss on contingent consideration		—			—
Credit losses		—			767
(Gain) loss on sale of assets		(94	)		(142	)
Settlement of asset retirement obligations		(206	)		(133	)
Cash interest expense, net		(3,856)			(4,440	)
Development costs		(290,636	)		(382,501	)
Settlement of contingent consideration		(13,547	)		(5,436	)
Change in accrued realized derivative settlements		(4,028	)		(10,852	)
Cash Available for Distribution(2)	$	402,022		$	220,567
Pro Forma Annualized Distributions Per Unit	$			$
Pro Forma Estimated Annual Cash Distributions:
Distributions on common units held by purchasers in this offering
Distributions on common units held by our Existing Owners
Total estimated annual cash distributions	$			$

____________

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

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

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Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2024

The financial forecast presents, to the best of our knowledge and belief, our expected results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending June30, 2024. Based upon the assumptions and considerations set forth in the table below, we estimate that we will generate $334.1million in cash available for distribution for the twelve months ending June30, 2024, which would be sufficient to pay cash distributions of $            per common unit. The number of outstanding common units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering, including the expected award of            phantom units (based on the mid-point of the price range set forth on the cover of this prospectus) to certain executives and key employees. Furthermore, the financial forecast assumes that we do not make any acquisitions of properties during the twelve months ending June30, 2024.

The table below under “— Our Estimated Cash Available for Distribution” reflects our judgment, as of the date of this prospectus, of conditions we expect to exist and the course of action we expect to take in order to be able to be able to generate cash available for distribution in the amount of $   per common unit, or $334.1million in the aggregate for the twelve months ending June30, 2024. The assumptions discussed below under “— Assumptions and Considerations” are those that we believe are significant to our ability to generate the requisite Adjusted EBITDA. Based on such assumptions, we believe our actual results of operations and cash flow will be sufficient to generate the Adjusted EBITDA necessary to pay the forecasted aggregate annualized cash distribution. We can, however, give you no assurance that we will generate this amount. There will likely be differences between our estimated Adjusted EBITDA and our actual results, and those differences could be material. If we fail to generate the estimated Adjusted EBITDA contained in our forecast, our annualized cash distribution to all of our unitholders may be less than expected. We can give you no assurance that our assumptions will be realized or that we will generate any available cash, in which event we will not be able to pay quarterly cash distributions from our available cash on our common units.

While we do not, as a matter of course, make public projections as to future sales, earnings or other results, our management has prepared the prospective financial information that is the basis of our estimated Adjusted EBITDA below to substantiate our belief that we will have sufficient cash to pay the forecasted cash distribution on all of our common units for twelve months ending June30, 2024. This forecast is a forward-looking statement and should be read together with our historical financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, is substantially consistent with those guidelines and was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions and considerations on which we base our belief that we can generate Adjusted EBITDA necessary for us to pay cash distribution on all of our outstanding common for the twelve months ending June30, 2024 equal to $            per common unit. Readers of this prospectus are cautioned not to place undue reliance on this prospective financial information. Please read “— Assumptions and Considerations,” including the sensitivity analysis included therein.

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Grant Thornton LLP has not compiled, examined or performed any procedures with respect to the accompanying prospective financial information and, accordingly, Grant Thornton LLP does not express any opinion or any other form of assurance with respect thereto. The Grant Thornton LLP reports included in the registration statement relate to our historical financial information. It does not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate the Adjusted EBITDA necessary to pay the forecasted aggregate annualized cash distribution on all of our outstanding common units for the twelve months ending June30, 2024.

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We are providing the table below under “— Our Estimated Cash Available for Distribution” to supplement our historical financial statements and in support of our belief that we will have sufficient available cash to pay the forecasted aggregate annualized cash distribution on all of our outstanding common units for the twelve months ending June30, 2024. Please read below under “— Assumptions and Considerations” for further information about the assumptions we have made for the financial forecast.

We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective financial information or to update this prospective financial information to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

Our Estimated Cash Available for Distribution

The following table shows how we calculate estimated available cash for the twelve months ending June30, 2024 and for each quarter during that twelve-month period that would be available for distribution to our unitholders. All of the amounts for the twelve months ending June30, 2024 in the table below are estimates. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in “— Assumptions and Considerations.”

Neither our independent registered public accounting firm nor any other independent registered public accounting firm has compiled, examined or performed any procedures with respect to the forecasted financial information contained herein, nor has it expressed any opinion or given any other form of assurance on such information or its achievability, and it assumes no responsibility for such forecasted financial information.

Our independent registered public accounting firm’s reports included elsewhere in this prospectus relate to our audited historical financial statements. These reports do not extend to the table and the related forecasted information contained in this section and should not be read to do so.

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	Three Months Ending September 30, 2023			Three Months Ending December 31, 2023			Three Months Ending March 31, 2024			Three Months Ending June 30, 2024			Twelve Months Ending June 30, 2024
	(in thousands, except per unit amounts) (unaudited)
Estimated Net Income(1)	$	99,390		$	105,302		$	100,703		$	85,785		$	391,180
Interest expense		1,132			1,132			1,116			1,116			4,496
Depreciation, depletion and amortization		32,736			33,820			32,940			32,533			132,029
Unrealized (gain) loss on derivative settlements(2)		—			—			—			—			—
Equity-based compensation expense(3)		—			—			—			—			—
Loss on contingent consideration(4)		—			—			—			—			—
(Gain) loss on sale of assets(5)		—			—			—			—			—
Estimated Adjusted EBITDA(6)	$	133,258		$	140,254		$	134,759		$	119,434		$	527,705
Estimated Net Income(1)	$	99,390		$	105,302		$	100,703		$	85,785		$	391,180
Interest expense		1,132			1,132			1,116			1,116			4,496
Depreciation, depletion and amortization		32,736			33,820			32,940			32,533			132,029
Unrealized (gain) loss on derivative settlements(7)		—			—			—			—			—
Equity-based compensation expense		—			—			—			—			—
Loss on contingent consideration(8)		—			—			—			—			—
(Gain) loss on sale of assets(9)		—			—			—			—			—
Settlement of asset retirement obligations(10)		—			—			—			—			—
Cash interest expense, net		(1,132	)		(1,132	)		(1,116	)		(1,116	)		(4,496	)
Development costs(11)		(67,531	)		(41,100	)		(39,462	)		(41,050	)		(189,143	)
Settlement of contingent consideration(12)		—			—			—			—			—
Change in accrued realized derivative settlements(13)		—			—			—			—			—
Estimated Cash Available for Distribution(14)	$	64,595		$	98,022		$	94,181		$	77,268		$	334,066
Estimated Cash distribution per unit	$			$			$			$			$
Estimated cash distributions(15):
Distributions on common units held by purchasers in this offering ( )	$			$			$			$			$
Distributions on common units held by the Existing Owners ( )(16)	$			$			$			$			$
Total estimated annual cash distributions	$			$			$			$			$

____________

(1)Includes the forecasted effect of cash settlements of commodity derivative instruments. This amount does not include unrealized commodity derivative gains (losses), as such amounts represent non-cash items and cannot be reasonably estimated in the forecast period.

(2)Does not include an estimate of unrealized derivative (gain)/loss because the forecast period assumes the commodity prices set forth below under “— Assumptions and Considerations — Operations and Revenue — Prices” remain constant during the period. For additional information regarding the impact of changes in commodity prices, please see “— Sensitivity Analysis” below.

(3)Does not include an estimate of equity-based compensation expense for the forecast period because the amount of such expense is not known at this time, including any unit awards that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.

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(4)There is no additional contingent consideration to record losses in the forecasted periods. The settlement of contingent consideration in previous periods was due to the contingent overriding royalty interest described in Note 9 of the financial statements of BCE-Mach III included herein, which was settled in 2022.

(5)Does not include estimated non-cash (gain)/loss, which cannot be accurately forecasted for future periods.

(6)Adjusted EBITDA is a non-GAAP financial measure, please see “Prospectus Summary — Non-GAAP Financial Measures” above.

(7)Does not include an estimate of unrealized (gain) loss on derivative settlements because the forecast period assumes the commodity prices set forth below under “— Assumptions and Considerations — Operations and Revenue —Prices” remain constant during the period. For additional information regarding the impact of changes in commodity prices, please see “— Sensitivity Analysis” below.

(8)There is no additional contingent consideration to record losses in the forecasted periods. The settlement of contingent consideration in previous periods was due to the contingent overriding royalty interest described in Note 9 of the financial statements of BCE-Mach III included herein, which was settled in 2022.

(9)Does not include (gain) loss on sale of assets, which cannot be accurately forecasted for future periods.

(10)Does not include settlement of asset retirement obligations, which are not forecasted for future periods at this time.

(11)Our development costs decrease in the periods following the three months ended September 30, 2023 because we have recently reduced our rig count from three to two rigs.

(12)There is no additional contingent consideration to record losses in the forecasted periods. The settlement of contingent consideration in previous periods was due to the contingent overriding royalty interest described in Note 9 of the financial statements of BCE-Mach III included herein, which was settled in 2022.

(13)Does not include an estimate of change in accrued realized derivative settlements because the forecast period assumes the commodity prices set forth below under “— Assumptions and Considerations — Operations and Revenue — Prices” remain constant during the period. For additional information regarding the impact of changes in commodity prices, please see “— Sensitivity Analysis” below.

(14)Cash available for distribution is a non-GAAP financial measure, please see “Prospectus Summary — Non-GAAP Financial Measures” above.

(15)The number of outstanding common units assumed herein does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.

(16)Assumes   common units of the Exchanging Members are redeemed, assuming the underwriters do not exercise their option to purchase additional units. See “Use of Proceeds.”

Assumptions and Considerations

Based upon the specific assumptions outlined below, we expect to generate cash available for distribution for the twelve months ending June30, 2024 of approximately $334.1million.

On January1, 2023, we assumed operations of a significant amount of properties where we previously were a non-operating partner in the properties and provided midstream services. As a result of these properties becoming operated properties as opposed to non-operated properties, offsetting accounting changes occurred resulting in reduced midstream operating expense, reduced midstream revenue, increased LOE, and increased price realizations. Our forecast takes into consideration these accounting changes.

While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the forecasted estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not correct, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate, in which event the market price of our common units may decline substantially. When reading this section, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors” and “Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Operations and Revenue

Production.Our ability to generate sufficient cash from operations to pay cash distributions to unitholders is a function of two primary variables: (i) production volumes and (ii) commodity prices. Production volumes directly impact our revenue. Any negative effect on production volumes could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution. Our existing production will naturally decline over time as the applicable reservoir is depleted. Our decline rate for our oil and gas properties over the next four quarters is currently estimated to be approximately 24%.

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The following table presents historical production volumes for our properties on a pro forma basis for the Mach Companies for the year ended December 31, 2022 and the twelve months ended June30, 2023 and on a forecasted basis for the twelve months ending June30, 2024:

	Pro Forma Year Ended December 31, 2022	Pro Forma Twelve Months Ended June 30, 2023	Forecasted Twelve Months Ending June 30, 2024
Annual production:
Oil and condensate (MBbl)	5,982	6,612	6,083
Natural gas (MMcf)	70,947	77,255	69,442
Natural gas liquids (MBbl)	4,246	4,234	4,038
Total (MBoe)	22,053	23,721	21,694
Average net daily production:
Oil and condensate (MBbl/d)	16.39	18.11	16.67
Natural gas (MMcf/d)	194.38	211.66	190.25
Natural gas liquids (MBbl/d)	11.63	11.60	11.06
Total (MBoe/d)	60.42	64.99	59.44

We estimate that our total oil and natural gas production for the twelve months ending June30, 2024 will be 59 MBoe/d as compared to 60 MBoe/d on a pro forma basis for the year ended December 31, 2022 and 65 MBoe/d on a pro forma basis for the twelve months ended June30, 2023. We intend to maintain our forecasted production level of 59 MBoe/d for the twelve months ending June30, 2024 with cash generated from operations.

Prices.Our results of operations depend on many factors, particularly the price of our commodity production and our ability to market our production effectively. Oil and natural gas prices have historically been volatile. During the period from December 31, 2020 through June30, 2023, prices for crude oil and natural gas reached a high of $123.64 per Bbl and $23.86 per MMBtu, respectively, and a low of $47.47 per Bbl and $1.74 per MMBtu, respectively. A future decline in commodity prices may adversely affect our business, financial condition or results of operations. Lower commodity prices may not only decrease our revenues, but also the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing bases under our Existing Credit Facilities, which are redetermined semi-annually.

The NYMEX WTI, for oil prices, and NYMEX Henry Hub, for gas prices, are widely used benchmarks for the pricing of oil and natural gas in the United States. The price we receive for our oil and natural gas production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. The differentials to published oil and natural gas prices are based upon our analysis of the historic price differentials for production from the mineral interests with consideration given to gravity, quality and transportation and marketing costs that may affect these differentials. There is no assurance that these assumed differentials will occur. The table below illustrates the relationship between average oil, natural gas and NGLs realized sales prices and average NYMEX prices as of June30, 2023, on a pro forma basis for the Mach Companies for the year ended December 31, 2022 and the twelve months ended June30, 2023, as well as our forecast for the twelve months ending June30, 2024.

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	Pro Forma Year Ended December 31, 2022			Pro Forma Twelve Months Ended June 30, 2023			Forecasted Twelve Months Ending June 30, 2024
Average oil sales prices (Bbl):
Average daily NYMEX-WTI oil price	$	94.33		$	81.00		$	84.86
Differential to NYMEX-WTI oil (excluding derivatives)		(0.78	)%		(0.51	)%		(0.54	)%
Realized oil sales price (excluding derivatives)	$	93.60		$	80.58		$	84.40
Realized oil sales price (including derivatives)	$	78.94		$	75.34		$	82.91
Average natural gas sales prices (Mcf):
Average daily NYMEX-Henry Hub natural gas price	$	6.54		$	4.81		$	3.00
Differential to NYMEX-Henry Hub natural gas (excluding derivatives)		(5.07	)%		(7.87	)%		(7.94	)%
Realized natural gas sales price (excluding derivatives)	$	6.21		$	4.43		$	2.76
Realized natural gas sales price (including derivatives)	$	5.09		$	3.99		$	2.80
Average natural gas liquids sales prices (Bbl):
Average daily NYMEX-WTI oil price	$	94.33		$	81.00		$	84.86
Percentage of NYMEX-WTI oil price (excluding derivatives)		41.18	%		36.46	%		35.26	%
Realized natural gas liquids sales price (excluding derivatives)	$	38.85		$	29.53		$	29.92
Realized natural gas liquids sales price (including derivatives)	$	38.85		$	29.53		$	29.92

Hedging Activities.We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosure About Market Risk — Commodity price risk — Commodity derivative activities” for more information.

As of the date of this prospectus, our commodity derivative contracts will cover 1,715 MBbl, or approximately 28%, of our forecasted total oil production of 6,083 MBbl, none of our forecasted total NGL production of 4,038 MBbl, and 486 MMcf, or approximately 1%, of our forecasted total natural gas production of 69,442 MMcf, for the twelve months ending June30, 2024. Our commodity derivative contracts consist of swap agreements based upon NYMEX-WTI prices and NYMEX-Henry Hub prices. The table below shows the volumes and prices covered by the commodity derivative contracts for the twelve months ending June30, 2024. For purposes of our forecast, we have assumed that we will not enter into additional natural gas or oil derivative contracts during the forecast period, although we may do so on an opportunistic basis if market conditions are favorable. See “Risk Factors — Risks Related to Our Business — Our derivative activities could result in financial losses or could reduce our earnings.”

	Swaps
	Volume	Weighted Avg. Price		Percentage of Forecasted Production
Oil:
July 2023 – September 2023 (Bbl)	193,000	$	61.00	11	%
October 2023 – December 2023 (Bbl)	869,000	$	82.81	56	%
January 2024 – March 2024 (Bbl)	499,300	$	83.47	34	%
April 2024 – June 2024 (Bbl)	152,800	$	84.07	11	%
Natural Gas:
July 2023 – September 2023 (MMBtu)	486,000	$	5.07	3	%
October 2023 – December 2023 (MMBtu)	—		—	—
January 2024 – March 2024 (MMBtu)	—		—	—
April 2024 – June 2024 (MMBtu)	—		—	—

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Operating Revenues and Realized Commodity Derivative Gains.The following table illustrates the primary components of operating revenues and realized commodity derivative gains on a pro forma basis for the year ended December 31, 2022 and the twelve months ended June30, 2023 and on a forecasted basis for the twelve months ending June30, 2024:

(in thousands)	Pro Forma Year Ended December 31, 2022			Pro Forma Twelve Months Ended June 30, 2023			Forecasted Twelve Months Ending June 30, 2024
Oil:
Oil revenues (excluding the effects of derivative instruments)	$	559,881		$	532,782		$	513,372
Realized oil derivative instruments gain (loss)		(87,672	)		(34,655	)		(9,061	)
Total	$	472,209		$	498,127		$	504,311
Natural gas:
Natural gas revenues (excluding the effects of derivative instruments)	$	440,571		$	342,601		$	191,968
Realized natural gas derivative instruments gain (loss)		(79,380	)		(34,297	)		2,182
Total	$	361,191		$	308,304		$	194,150
Natural gas liquids:
Natural gas liquids revenue (excluding the effects of derivative instruments)	$	164,968		$	125,039		$	120,816
Realized natural gas liquids derivative instruments gain (loss)		—			—			—
Total	$	164,968		$	125,039		$	120,816
Total:
Operating revenues	$	1,165,420		$	1,000,422		$	826,156
Realized derivative instruments gain (loss)		(167,052	)		(68,952	)		(6,879	)
Operating revenue and realized commodity derivative instruments losses	$	998,368		$	931,470		$	819,277

Midstream Revenues.Our midstream revenue is generated from owned gathering and compression systems and processing plants. The Company charges a gathering, compression, processing rate per MMBtu transported through the gathering system and processing plant. The Company also gathers and disposes of salt water from producing wells through an owned pipeline system and disposal wells. The Company charges a fixed rate per barrel of water for disposal. The assumption of operatorship of a significant amount of properties as of January1, 2023 has reduced our midstream revenues. The following table summarizes midstream revenues on a pro forma basis for the year ended December31, 2022 and the twelve months ended June30, 2023 and on a forecasted basis for the twelve months ending June30, 2024:

	Pro Forma Year Ended December 31, 2022		Pro Forma Twelve Months Ended June 30, 2023		Forecasted Twelve Months Ended June 30, 2024(1)
Midstream revenue (in thousands)	$	44,832	$	38,235	$	23,739

____________

(1)Midstream revenues have decreased in the forecast period as compared to historical periods because we have assumed operations of a significant amount of properties where we previously were a non-operating partner in the properties and provide midstream services. Midstream revenue averaged approximately $2.255million per month on a pro forma basis for the six months ended June 30, 2023 compared to a forecasted average of approximately $1.978 million per month for the twelve months ending June 30, 2024. For additional information, please see “Assumptions and Considerations.”

Costs and Expenses

Development Costs.Our estimated development costs for the twelve months ending June30, 2024 of $189.1million represent our estimate of the annual capital expenditures necessary to achieve our forecasted production level of 59 MBoe/d for the twelve months ending June30, 2024. Our development costs are less in the forecasted periods because we have recently reduced our rig count from three to two rigs.

Gathering and Processing Expense.Gathering and processing expense consists primarily of gathering fees and processing fees. Gathering and processing costs are recognized when change of control of the natural gas we sell occurs at the tailgate of the processing plant. This expense can also fluctuate based on acquisitions, commodity

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prices, and overall product mix. We evaluate gathering and processing on a per Boe basis to monitor costs to ensure that they are at acceptable levels. Gathering and processing expense per Boe for the year ended December31, 2022 and the twelve months ended June30, 2023 were higher than those forecasted for the twelve months ended June30, 2024 due to (i) oil as a percentage of our total production has increased and continues to increase, (ii) fuel costs were higher due to higher natural gas prices compared to those in the forecast period, and (iii) our gas production over time decreases in our Legacy Producing Assets which result in higher gathering and processing costs than our Focus Drilling Area. Lower gathering and processing costs in our Legacy Producing Assets resulting from lower gas production are slightly offset by increasing gas production in our Focus Drilling Area. The following table summarizes gathering and processing expense on a pro forma basis for the year ended December31, 2022 and the twelve months ended June30, 2023 and on a forecasted basis for the twelve months ended June30, 2024:

	Pro Forma Year Ended December 31, 2022		Pro Forma Twelve Months Ended June 30, 2023		Forecasted Twelve Months Ended June 30, 2024(1)
Gathering and processing expense (in thousands)	$	87,887	$	80,989	$	66,834
Gathering and processing expense (per Boe)	$	3.99	$	3.41	$	3.08

____________

(1)Gathering and processing expenses are lower in the forecasted periods due to (i) oil as a higher percentage of total production, (ii) fuel costs are lower in the forecast period and (iii) our gas production continues to shift to our Focus Drilling Area with lower gathering and processing costs. For additional information, please see “Assumptions and Considerations.”

Lease Operating Expenses.The following table summarizes lease operating expenses on an aggregate basis and on a per Boe basis for the year ended December 31, 2022, pro forma and the twelve months ended June30, 2023, pro forma, and on a forecasted basis for the twelve months ending June30, 2024:

	Pro Forma Year Ended December 31, 2022		Pro Forma Twelve Months Ended June 30, 2023		Forecasted Twelve Months Ended June 30, 2024
Lease operating expenses (in thousands)	$	145,267	$	170,394	$	169,203
Lease operating expenses (per Boe)	$	6.59	$	7.18	$	7.80

We estimate that our lease operating expenses for the twelve months ending June30, 2024 will be approximately $169.2million. Lease operating expenses consist of expenses incurred for the operation and maintenance of wells and related equipment. On a pro forma basis, for the year ended December 31, 2022 and the twelve months ended June30, 2023, and, on a forecasted basis, for the twelve months ended June30, 2024, lease operating expenses were $145.3million, $170.4million and $169.2million, respectively.

Production Taxes.Production taxes consist primarily of severance taxes. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold at fixed rates established by state or local taxing authorities. In general, the severance taxes we pay correlate to the changes in oil and natural gas revenues. We evaluate production taxes on a percentage of revenue basis to monitor costs to ensure that they are at acceptable levels. This expense can also fluctuate based on acquisitions, commodity prices, and overall product mix. The following table summarizes production taxes on a pro forma basis for the year ended December 31, 2022 and the twelve months ended June30, 2023 and on a forecasted basis for the twelve months ending June30, 2024:

	Pro Forma Year Ended December 31, 2022			Pro Forma Twelve Months Ended June 30, 2023		Forecasted Twelve Months Ended June 30, 2024(1)
Production taxes (in thousands)	$	65,194		$	53,681	$	44,005
Production taxes (% of oil, natural gas and NGL sales)		5.6	%		5.4%		5.3	%

____________

(1)Production taxes decreased in the forecasted period due to lower production.

Midstream Operating Expense.Our midstream operating expense is generated from expenses incurred in the operation of our owned gathering and compression systems and processing plants. The Company also incurs expenses related to the gathering and disposal of salt water from producing wells through an owned pipeline system

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and disposal wells. The assumption of operatorship of a significant amount of properties as of January1, 2023 has reduced our midstream operating expense. The following table summarizes midstream operating expense on a pro forma basis for the year ended December31, 2022 and the twelve months ended June30, 2023 and on a forecasted basis for the twelve months ending June30, 2024:

	Pro Forma Year Ended December 31, 2022		Pro Forma Twelve Months Ended June 30, 2023		Forecasted Twelve Months Ended June 30, 2024(1)
Midstream operating expense (in thousands)	$	15,618	$	14,186	$	9,998

____________

(1)Midstream operating expense is lower in the forecasted period because the assumption of operatorship of a significant amount of properties as of January 1, 2023 has reduced our midstream operating expense. Midstream operating expenses averaged approximately $0.96 million per month on a pro forma basis for the six months ended June 30, 2023 compared to a forecasted average of approximately $0.833 million per month for the twelve months ending June 30, 2024. For additional information, please see “Assumptions and Considerations.”

General and Administrative Expenses.General and administrative expenses consist primarily of personnel related costs, professional fees and services and general office expenses and are partially offset by certain reimbursements of overhead expenses. In connection with the consummation of this offering, we expect to incur additional costs related to being a public company of approximately $6.0million per year. However, we do not expect to experience a material change in our cash cost structure, except as may be affected by our recent property acquisitions, the volatility of commodity prices, increased expenses as a publicly traded partnership, the effects of our commodity derivative contracts, and the effects of impairment on our producing properties. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors Affecting the Comparability of Our Financial Condition and Results of Operations.”

Furthermore, we will (i) pay Mach Resources an annual management fee of approximately $7.4million and (ii) reimburse Mach Resources for the costs and expenses of the services provided pursuant to the MSA, including, but not limited to, (a) all reasonable third party costs and expenses incurred by or paid by Mach Resources or its affiliates in the performance of the services, including the costs of any person engaged by the service provider pursuant to the terms of the MSA, and (b) all general, administrative and supervision costs and expenses. We will reimburse Mach Resources on a quarterly basis or at other intervals that we and Mach Resources may agree from time to time. We estimate that payments under the MSA to Mach Resources would be $97.2million for the twelve months ended June30, 2024. We anticipate that the size of the reimbursements to Mach Resources will vary with the size and scale of our operations, among other factors. See “Certain Relationships and Related Party Transactions — Agreements with Affiliates in Connection with the Reorganization Transactions — New Management Services Agreement.”

The following table summarizes general and administrative expenses on a pro forma basis for the year ended December31, 2022 and the twelve months ended June30, 2023 and on a forecasted basis for the twelve months ending June30, 2024:

	Pro Forma Year Ended December 31, 2022		Pro Forma Twelve Months Ended June 30, 2023		Forecasted Twelve Months Ended June 30, 2024
General and administrative expenses (in thousands)	$	19,278	$	20,163	$	28,596
General and administrative expenses (per Boe)	$	0.87	$	0.85	$	1.32

Interest Expense.    Interest expense is primarily the result of borrowings on the Credit Facilities to fund operations and acquisitions of properties as well as the amortization of debt issuance costs associated with these borrowings. Interest expense can fluctuate with our level of indebtedness as well as changes in interest rates. We assume that the weighted average of borrowings under the Credit Facilities will be $62.75million with a weighted average interest rate of 8.4%.

Regulatory, Industry and Economic Factors

Our forecast for the twelve months ending June30, 2024 is based on the following significant assumptions related to regulatory, industry and economic factors:

•There will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or any interpretation of existing regulations, that will be materially adverse to our business;

•There will not be any material nonperformance or credit-related defaults by suppliers, customers or vendors, or shortage of skilled labor;

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•All supplies and commodities necessary for production and sufficient transportation will be readily available;

•There will not be any major adverse change in commodity prices or the energy industry in general;

•There will not be any material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated events, including any events that could lead to force majeure under any of our marketing agreements;

•There will not be any adverse change in the markets in which we operate resulting from supply or production disruptions, reduced demand for our product or significant changes in the market prices for our product; and

•Market, insurance, regulatory and overall economic conditions will not change substantially.

Sensitivity Analysis

Our ability to generate sufficient cash from operations to pay cash distributions to our unitholders is a function of two primary variables: (i) production volumes; and (ii) commodity prices. In the tables below, we illustrate the effect that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the forecasted cash distributions on our outstanding common units for the twelve months ending June30, 2024.

We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is impracticable to provide because of the number of assumptions and variables involved that have interdependent effects on the potential outcome.

Production Volume Changes

Production volumes directly impact our revenue. Any negative effect on production volumes could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution. The following table shows estimated Adjusted EBITDA under production levels of 80%, 100% and 120% of the production level we have forecasted for the twelve months ending June30, 2024. The estimated Adjusted EBITDA amounts shown below are based on the assumptions used in our forecast.

	Percentage of Forecasted Net Production
	80%		100%		120%
	(in thousands, except per unit amounts)
Forecasted net production:
Oil (MBbl)		4,866		6,083		7,299
Natural gas (MMcf)		55,554		69,442		83,330
Natural gas liquids (MBbl)		3,230		4,038		4,845
Total (MBoe)		17,355		21,694		26,033
Oil (MBbl/d)		13,332		16,665		19,998
Natural gas (MMcf/d)		152,202		190,252		228,302
Natural gas liquids (MBbl/d)		8,849		11,062		13,274
Total (MBoe/d)		47,548		59,435		71,322
Forecasted prices:
NYMEX-WTI oil price (per Bbl)	$	84.86	$	84.86	$	84.86
Realized oil price (per Bbl) (excluding derivatives)		84.40		84.40		84.40
Realized oil price (per Bbl) (including derivatives)		82.54		82.91		83.16
NYMEX-Henry Hub natural gas price (per Mcf)		3.00		3.00		3.00
Realized natural gas sales price (per Mcf) (excluding derivatives)		2.76		2.76		2.76
Realized natural gas sales price (per Mcf) (including derivatives)		2.80		2.80		2.79
NYMEX-WTI oil price (per Bbl)	$	84.86	$	84.86	$	84.86
Realized natural gas liquids sales price (per Bbl) (excluding derivatives)		29.92		29.92		29.92
Realized natural gas liquids sales price (per Bbl) (including derivatives)		29.92		29.92		29.92
Estimated Net Income(1)	$	265,236	$	391,180	$	517,106
Interest expense		4,496		4,496		4,496
Depreciation, depletion and amortization		112,939		132,029		151,134
Unrealized (gain) loss on derivative settlements(2)		—		—		—
Equity-based compensation expense		—		—		—
Loss on contingent consideration		—		—		—
(Gain) loss on sale of assets(3)		—		—		—

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	Percentage of Forecasted Net Production
	80%			100%			120%
	(in thousands, except per unit amounts)
Estimated Adjusted EBITDA(4)	$	382,671		$	527,705		$	672,736
Settlement of asset retirement obligations		—			—			—
Cash interest expense, net		(4,496	)		(4,496	)		(4,496	)
Development costs		(189,143	)		(189,143	)		(189,143	)
Settlement of contingent consideration		—			—			—
Change in accrued realized derivative settlements		—			—			—
Estimated Cash Available for Distribution(5)	$	189,032		$	334,066		$	479,097

____________

(1)Includes the forecasted effect of cash settlements of commodity derivative instruments. This amount does not include unrealized commodity derivative gains (losses), as such amounts represent non-cash items and cannot be reasonably estimated in the forecast period.

(2)Does not include an estimate of unrealized derivative (gain)/loss because the forecast period assumes the commodity prices set forth below under “— Assumptions and Considerations — Operations and Revenue — Prices” remain constant during the period. For additional information regarding the impact of changes in commodity prices, please see “— Commodity Price Changes” below.

(3)Does not include estimated non-cash (gain)/loss, which cannot be accurately forecasted for future periods.

(4)Adjusted EBITDA is a non-GAAP financial measure, please see “Prospectus Summary — Non-GAAP Financial Measures” above.

(5)Cash available for distribution is a non-GAAP financial measure, please see “Prospectus Summary — Non-GAAP Financial Measures” above.

As reservoir pressures decline, production from a given well or formation decreases. Maintaining or growing our future production and reserves will depend on our ability to continue to replace current production with new reserves. Accordingly, we plan to focus on maintaining reserves through both the drill bit and acquisitions, while maintaining a conservative financial profile. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel, and successfully identify and consummate acquisitions. See “Risk Factors — Risks Related to Our Business” for a discussion of these and other risks affecting our proved reserves and production.

Commodity Price Changes

Our major market risk exposure is in the pricing that we receive for our oil, NGL and natural gas production. Pricing for oil, NGLs and natural gas has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil, NGL, and natural gas production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.

To reduce the impact of fluctuations in oil, NGL and natural gas prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil, NGL and natural gas production through various transactions that limit the risks of fluctuations of future prices. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. While there is a risk we may not be able to realize the full benefits of rising prices, these hedging activities are intended to limit our exposure to product price volatility and to maintain stable cash flows.

The following table shows estimated Adjusted EBITDA under various assumed NYMEX-WTI oil and NYMEX-Henry Hub natural gas prices for the twelve months ending June30, 2024. For the twelve months ending June30, 2024, we have assumed that commodity derivative contracts will cover (i) 1,715 MBbl, or approximately 28% of our estimated total oil production from proved reserves for the twelve months ending June30, 2024, at a weighted average floor price of $80.66 per Bbl, (ii) none of our estimated total NGL production from proved reserves for the twelve months ending June30, 2024 and (iii) 486 MMcf, or approximately 1% of our estimated total natural gas production from proved reserves for the twelve months ending June30, 2024. In addition, the estimated Adjusted EBITDA amounts shown below are based on forecasted realized commodity prices that take into account assumptions based on our average historical NYMEX commodity price differentials as set forth in our June30, 2023 reserve report. We have assumed no changes in our production based on changes in prices. The estimated Adjusted EBITDA amounts shown below are based on forecasted realized commodity prices that take into account our average NYMEX commodity price differential assumptions.

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	Percentage of Forecasted Prices
	80%			100%			120%
	(in thousands, except per unit amounts)
Forecasted net production:
Oil and condensate (MBbl)		6,083			6,083			6,083
Natural gas (MMcf)		69,442			69,442			69,442
Natural gas liquids (MBbl)		4,038			4,038			4,038
Total (MBoe)		21,694			21,694			21,694
Oil and condensate (MBbl/d)		16,665			16,665			16,665
Natural gas (MMcf/d)		190,252			190,252			190,252
Natural gas liquids (MBbl/d)		11,062			11,062			11,062
Total (MBoe/d)		59,435			59,435			59,435
Forecasted prices:
NYMEX-WTI oil price (per Bbl)	$	67.89		$	84.86		$	101.83
Realized oil price (per Bbl) (excluding derivatives)		67.43			84.40			101.37
Realized oil price (per Bbl) (including derivatives)		70.82			82.91			95.00
NYMEX-Henry Hub natural gas price (per Mcf)		2.40			3.00			3.60
Realized natural gas sales price (per Mcf) (excluding derivatives)		2.17			2.76			3.36
Realized natural gas sales price (per Mcf) (including derivatives)		2.20			2.80			3.39
NYMEX-WTI oil price (per Bbl)	$	67.89		$	84.86		$	101.83
Realized natural gas liquids sales price (per Bbl) (excluding derivatives)		24.65			29.92			35.19
Realized natural gas liquids sales price (per Bbl) (including derivatives)		24.65			29.92			35.19
Estimated Net Income(1)	$	264,050		$	391,180		$	518,308
Interest expense		4,496			4,496			4,496
Depreciation, depletion and amortization		132,029			132,029			132,029
Unrealized (gain) loss on derivative settlements(2)		—			—			—
Equity-based compensation expense		—			—			—
Loss on contingent consideration		—			—			—
(Gain) loss on sale of assets(3)		—			—			—
Estimated Adjusted EBITDA(4)		400,575			527,705			654,833
Settlement of asset retirement obligations		—			—			—
Cash interest expense, net		(4,496	)		(4,496	)		(4,496	)
Development costs		(189,143	)		(189,143	)		(189,143	)
Settlement of contingent consideration		—			—			—
Change in accrued realized derivative settlements		—			—			—
Estimated Cash Available for Distribution(5)	$	206,936		$	334,066		$	461,194

____________

(1)Includes the forecasted effect of cash settlements of commodity derivative instruments. This amount does not include unrealized commodity derivative gains (losses), as such amounts represent non-cash items and cannot be reasonably estimated in the forecast period.

(2)Does not include an estimate of unrealized derivative (gain)/loss because the forecast period assumes the commodity prices set forth below under “— Assumptions and Considerations — Operations and Revenue — Prices” remain constant during the period.

(3)Does not include estimated non-cash (gain)/loss, which cannot be accurately forecasted for future periods.

(4)Adjusted EBITDA is a non-GAAP financial measure, please see “Prospectus Summary — Non-GAAP Financial Measures” above.

(5)Cash available for distribution is a non-GAAP financial measure, please see “Prospectus Summary — Non-GAAP Financial Measures” above.

If NYMEX oil, NGLs and natural gas prices decline, our estimated Adjusted EBITDA would not decline proportionately for two reasons: (1) the effects of our commodity derivative contracts; and (2) production taxes, which are calculated as a percentage of our oil, NGLs and natural gas revenues, excluding the effects of our commodity derivative contracts, and which decrease as commodity prices decline. Furthermore, we have assumed no decline in estimated production or oil, NGLs and natural gas operating costs during the twelve months ending June30, 2024. However, over the long-term, a sustained decline in prices would likely lead to a decline in production and operating costs, as well as a reduction in our realized oil, NGLs and natural gas prices. Therefore, the foregoing table is not illustrative of all of the potential effects of changes in commodity prices for periods subsequent to June30, 2024.

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 60 days after the end of each quarter (other than the fourth quarter) and within 90 days after the end of the fourth quarter, beginning with the quarter ending  , we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the amount of our cash distribution for the period from the closing of this offering through , based on the actual length of that period.

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 intend to 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.

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.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The selected historical consolidated financial data set forth below as of and for each of the years ended December 31, 2022 and 2021 have been derived from our predecessor’s audited consolidated financial statements included elsewhere in this prospectus. The selected historical consolidated financial data set forth below as of June30, 2023 and for the six months ended June30, 2023 and 2022 are derived from our unaudited financial statements and related notes included elsewhere in this prospectus.

The selected unaudited pro forma financial data as of June30, 2023 and for the six months ended June30, 2023 are derived from the unaudited pro forma condensed financial statements of Mach Natural Resources included elsewhere in this prospectus, which reflect the historical results of our predecessor, BCE-Mach LLC and BCE-Mach II LLC on a pro forma basis to give effect to the following transactions, which are described in further detail below, as if they had occurred on June30, 2023, for pro forma balance sheet purposes, and on January1, 2022, for pro forma statements of operations purposes:

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

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

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

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

You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our historical financial statements and our unaudited pro forma condensed combined financial statements and the notes thereto included elsewhere in this prospectus. Among other things, those historical financial statements and the unaudited pro forma condensed combined financial statements include more detailed information regarding the basis of presentation for the following information.

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	Predecessor Historical												Mach Natural Resources Pro Forma
	Six Months Ended June 30,						Year Ended December 31,						Six Months Ended June 30, 2023			Year Ended December 31, 2022
(in thousands, except per unit amounts)	2023			2022			2022			2021
Statement of Operations Data:
Revenues:
Oil, natural gas, and NGL sales	$	312,613		$	408,442		$	860,388		$	397,500		$	399,686		$	1,165,420
Midstream revenue		13,318			19,883			44,373			31,883			13,531			44,832
Loss (gain) on oil and natural gas derivatives, net		15,742			(72,857	)		(67,453	)		(67,549	)		22,618			(113,322	)
Product sales		17,421			47,960			100,106			30,663			17,421			100,106
Total operating revenues	$	359,094		$	403,428		$	937,414		$	392,497		$	453,256		$	1,197,036
Operating Expenses:
Gathering and processing expense	$	17,510		$	20,812		$	47,484		$	27,987		$	33,430		$	87,887
Lease operating expense		60,615			39,592			95,941			45,391			87,439			145,267
Midstream operating expense		5,538			6,976			15,157			12,248			5,761			15,618
Cost of product sales		15,575			44,958			94,580			28,687			15,575			94,580
Production taxes		15,526			22,675			47,825			21,165			20,003			65,194
Depreciation, depletion, amortization and accretion expense – oil and natural gas		58,095			29,374			84,070			37,537			72,117			119,359
Depreciation and amortization expense – other		2,793			2,008			4,519			3,148			3,171			5,445
General and administrative		9,905			13,648			25,454			60,927			11,750			19,278
Total operating expenses	$	185,557		$	180,043		$	415,030		$	237,090		$	249,246		$	552,628
Operating income	$	173,537		$	223,385		$	522,384		$	155,407		$	204,010		$	644,408
Other income (expenses):
Interest expense	$	(3,789	)	$	(1,876	)	$	(4,852	)	$	(1,656	)	$	(3,117	)	$	(4,241	)
Other (expense) income, net		(245	)		1,121			(691	)		1,023			(4,966	)		(1,083	)
Loss on contingent considerations		—			—			—			(16,400)			—			—
Total other expenses	$	(4,034)		$	(755)		$	(5,543)		$	(17,033)		$	(8,083)		$	(5,324)
Net income	$	169,503		$	222,630		$	516,841		$	138,374		$	195,927		$	639,084
Net income per limited partner unit:
Basic	$			$			$			$			$			$
Diluted	$			$			$			$			$			$
Weighted average number of limited partner units outstanding (basic and diluted):
Basic
Diluted
Other Financial Data:
Adjusted EBITDA(1)	$	226,766		$	276,408		$	594,429		$	248,617		$	255,639		$	714,295
Cash Available for Distribution(2)	$	30,418		$	155,857		$	300,944		$	184,445		$	43,290		$	402,022
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	275,145		$	227,936		$	553,542		$	198,462