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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


x			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2025


o			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______

Commission file number 001-41849

Mach Natural Resources LP

(Exact name of registrant as specified in its charter)


Delaware			93-1757616
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

14201 Wireless Way, Suite 300, Oklahoma City, Oklahoma			73134
(Address of Principal Executive Offices)			(Zip Code)

(405) 252-8100

Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Units	MNR	New York Stock Exchange

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days. Yes x No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

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


Large accelerated filer	o	Accelerated filer	x
Non-accelerated filer	o	Smaller reporting company	o
		Emerging growth company	x

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 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

The registrant had 118,337,920 common units outstanding as of August 1, 2025.

Table of Contents

TABLE OF CONTENTS


			Page

Part I - Financial Information			1
Item 1. Financial Statements			1
Consolidated Balance Sheets			1
Consolidated Statements of Operations			2
Consolidated Statements of Partners’ Capital			3
Consolidated Statements of Cash Flows			4
Notes to Consolidated Financial Statements			5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
Item 3. Quantitative and Qualitative Disclosures About Market Risk			39
Item 4. Controls and Procedures			41
Part II - Other Information			42
Item 1. Legal Proceedings			42
Item 1A. Risk Factors			42
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			42
Item 3. Defaults Upon Senior Securities			42
Item 4. Mine Safety Disclosures			42
Item 5. Other Information			42
Item 6. Exhibits			42
Signatures			44

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DEFINITIONS

“Adjusted EBITDA.” Net income before (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized loss (gain) on derivative instruments, (4) loss on debt extinguishment (5) equity-based compensation expense and (6) (gain) loss on sale of assets, net.

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGL.

“Bbtu.” One billion Btu.

“BCE” or “Sponsor.” Investment funds managed by Bayou City Energy Management LLC and affiliates thereof.

“BCE-Mach.” BCE-Mach LLC, a Delaware limited liability company.

“BCE-Mach II.” BCE-Mach II LLC, a Delaware limited liability company.

“BCE-Mach III.” BCE-Mach III LLC, a Delaware limited liability company.

“BCE-Mach Aggregator.” BCE-Mach Aggregator LLC, a Delaware limited liability company.

“Boe.” One barrel of oil equivalent, converting natural gas to oil at the ratio of 6 Mcf of natural gas to one Bbl of oil.

“British Thermal Unit” or “Btu.” The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).

“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.

“Holdco.” Mach Natural Resources Holdco LLC, a Delaware limited liability company.

“Intermediate.” Mach Natural Resources Intermediate LLC, a Delaware limited liability company.

“Lease operating expense.” The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, ad valorem taxes, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

“Mach Resources.” Mach Resources LLC.

“MBbl.” One thousand barrels of crude oil, condensate or NGLs.

“MBoe.” One thousand Boe.

“MBoe/d.” One thousand Boe per day.

“Mcf.” One thousand cubic feet of natural gas.

“MMBtu.” One million Btu.

“MMcf.” One million cubic feet of natural gas.

“MMcf/d.” One million cubic feet of natural gas per day.

“Net wells.” The percentage of gross wells an owner has. An owner who has a 50% interest in 100 gross wells owns 50 net wells.

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“NGLs.” Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

“New Revolving Credit Facility.” Refers to the senior secured revolving credit agreement, dated as of February 27, 2025, among the Company, the lenders party thereto, and Truist Bank as administrative agent.

“NYMEX.” The New York Mercantile Exchange.

“OPEC +.” Organization of the Petroleum Exporting Countries.

“Partnership agreement.” The Amended and Restated Agreement of Limited Partnership of Mach Natural Resources LP.

“Proved reserves.” Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved crude oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

“Proved undeveloped reserves (“PUD”).” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years unless specific circumstances justify a longer time.

“PV-10.” When used with respect to oil and natural gas reserves, PV-10 represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows. Calculation of PV-10 does not give effect to derivatives transactions. Our PV-10 has historically been computed on the same basis as our Standardized Measure, the most comparable measure under GAAP. PV-10 is not a financial measure calculated or presented in accordance with GAAP and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of either well abandonment costs or income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

“Recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing reservoirs in an attempt to establish or increase existing production.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“Revolving Credit Agreement.” Refers to the senior secured revolving credit agreement, dated as of December 28, 2023, among the Company, the lenders party thereto, and MidFirst Bank as administrative agent.

“Standardized Measure.” Standardized Measure is our standardized measure of discounted future net cash flows, which is prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month average prices for oil and gas, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% rate. No provision is included for federal income taxes since our future net cash flows are not subject to taxation. However, our operations are subject to the Texas franchise tax. Estimated well abandonment costs, net of salvage values, are deducted from the standardized measure using year-end costs and discounted at the 10% rate. The standardized measure does not represent management’s estimate of our future cash flows or the value of proved oil and natural gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, prices used to determine the standardized measure are influenced by supply and demand as effected by recent economic conditions as well as other factors and may not be the most representative in estimating future revenues or reserve data.

“Term Loan Credit Agreement.” Refers to the senior secured term loan credit agreement, dated as of December 28, 2023, among the Company, the lenders party thereto, Texas Capital Bank, as agent, and Chambers Energy Management, LP, as the arranger.

iii

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“Wellbore.” The hole drilled by the bit that is equipped for oil and natural gas production on a completed well. Also called well or borehole.

“Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil and natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“Workover.” Operations on a producing well to restore or increase production.

“WTI.” West Texas Intermediate.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Quarterly Report on Form 10-Q contains or incorporates by reference information that includes or is based upon “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, words such as “may,” “assume,” “forecast,” “could,” “should,” “will,” “plan,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events at the time such statement was made. When considering forward-looking statements, you should keep in mind the risk factors included in Part I, Item 1A. “Risk Factors” and Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024 and elsewhere in this Quarterly Report. All forward-looking statements speak only as of the date of this Quarterly Report.

Forward-looking statements may include statements about:

•our business strategy;

•our estimated proved reserves;

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

•our drilling prospects, inventories, projects and programs;

•general economic conditions;

•actions taken by OPEC + as it pertains to the global supply and demand of, and prices for, oil, natural gas and NGLs;

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

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

•our pending legal or environmental matters;

•our realized oil and natural gas prices;

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

•our hedging strategy and results;

•our competition and government regulations;

•our ability to obtain permits and governmental approvals;

•our marketing of natural gas;

•our leasehold or business acquisitions;

•our costs of developing our properties;

•credit markets;

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

•uncertainty regarding our future operating results; and

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

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil, natural gas and NGL. We disclose important factors that could cause our actual results to differ materially from our expectations as described under “Risk Factors” included in Part I, Item 1A in our Annual Report for the year ended December 31, 2024. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

•the Company’s ability to successfully complete the Sabinal Acquisition and the IKAV Acquisition (each as defined below);

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•commodity price volatility;

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

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

•the concentration of our operations in the Anadarko Basin;

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

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

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

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

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

•access to capital and the timing of development expenditures;

•environmental, weather, drilling and other operating risks;

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

•competition in the oil and natural gas industry;

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

•our ability to service our indebtedness;

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

•cost inflation;

•the potential for significant new tariffs and their impact on global oil, natural gas and NGL markets;

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

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

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

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

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

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

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

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

MACH NATURAL RESOURCES LP

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(in thousands)


	June 30, 2025		December 31, 2024
ASSETS
Current assets:
Cash and cash equivalents	$	13,777	$	105,776
Accounts receivable – joint interest and other, net	37,836		38,606
Accounts receivable – oil, gas, and NGL sales	109,038		132,945
Short-term derivative assets	16,537		14,069
Inventories	25,842		24,301
Other current assets	6,148		6,399
Total current assets	209,178		322,096
Oil and natural gas properties, using the full cost method:
Proved oil and natural gas properties	2,621,011		2,419,998
Less: accumulated depreciation, depletion and amortization	(641,942)		(520,641)
Oil and natural gas properties, net	1,979,069		1,899,357
Other property, plant and equipment	125,461		115,475
Less: accumulated depreciation	(28,694)		(23,710)
Other property, plant and equipment, net	96,767		91,765
Long-term derivative assets	3,241		640
Other assets	30,363		9,487
Operating lease assets	15,547		14,869
Total assets	$	2,334,165	$	2,338,214
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	48,508	$	52,440
Accounts payable – related party	1,828		1,996
Accrued liabilities	64,094		53,500
Revenue payable	141,204		150,165
Short-term derivative liabilities	5,439		6,233
Current portion of long-term debt	—		82,500
Current portion of operating lease liabilities	5,268		5,587
Total current liabilities	266,341		352,421
Long-term debt	565,000		668,778
Asset retirement obligations	110,189		101,858
Long-term derivative liabilities	4,524		4,873
Long-term portion of operating leases	10,320		9,302
Other long-term liabilities	2,096		1,936
Total long-term liabilities	692,129		786,747
Commitments and contingencies (Note 10)
Partners’ capital:
Partners’ capital	1,375,695		1,199,046
Total liabilities and partners’ capital	$	2,334,165	$	2,338,214

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

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MACH NATURAL RESOURCES LP

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(in thousands, except per common unit data)


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Revenue
Oil, natural gas, and NGL sales	$	219,412	$	231,539	$	472,138	$	486,779
Gain (loss) on oil and natural gas derivatives	55,579		(4,635)		14,886		(33,903)
Midstream revenue	6,257		6,441		12,387		12,660
Product sales	7,269		6,649		15,874		13,613
Total revenues	288,517		239,994		515,285		479,149

Operating expenses
Gathering and processing	31,784		23,831		59,945		55,773
Lease operating expense	49,566		46,497		98,318		87,257
Production taxes	10,496		11,302		23,270		24,054
Midstream operating expense	3,200		2,616		6,170		5,175
Cost of product sales	6,274		5,786		14,261		11,886
Depreciation, depletion, amortization and accretion – oil and natural gas	64,340		65,819		125,525		131,191
Depreciation and amortization – other	2,758		2,242		5,158		4,340
General and administrative	6,952		9,568		15,969		18,046
General and administrative – related party	1,850		1,850		3,700		3,700
Total operating expenses	177,220		169,511		352,316		341,422
Income from operations	111,297		70,483		162,969		137,727

Other (expense) income
Interest expense	(12,140)		(27,046)		(30,034)		(53,331)
Loss on debt extinguishment	—		—		(18,540)		—
Other income (expense), net	(9,496)		(3,921)		(8,848)		(3,178)
Total other expense	(21,636)		(30,967)		(57,422)		(56,509)
Net income	$	89,661	$	39,516	$	105,547	$	81,218
Net income per common unit:
Basic	$	0.76	$	0.42	$	0.92	$	0.85
Diluted	$	0.76	$	0.42	$	0.92	$	0.85
Weighted average common units outstanding:
Basic	118,336		95,009		115,248		95,004
Diluted	118,389		95,187		115,313		95,129

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

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MACH NATURAL RESOURCES LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (UNAUDITED)

(in thousands)


	Common Units	Partners’ Capital
Balance at December 31, 2023	95,000	$	1,191,724
Net income	—	41,702
Distributions to unitholders	—	(90,924)
Equity compensation	—	1,182
Balance at March 31, 2024	95,000	$	1,143,684
Net income	—	$	39,516
Distributions to unitholders	—	(71,820)
Equity compensation	—	2,300
Vesting of phantom units, net of units withheld for withholding taxes	40	(570)
Balance at June 30, 2024	95,040	$	1,113,110

Balance at December 31, 2024	103,490	$	1,199,046
Net income	—	15,886
Distributions to unitholders	—	(59,729)
Equity compensation	—	2,112
Vesting of phantom units, net of units withheld for withholding taxes	6	(69)
Common units issued in the public offering, net of underwriting fees and offering expenses	14,839	221,115
Balance at March 31, 2025	118,335	$	1,378,361
Net income	—	$	89,661
Distributions to unitholders	—	(94,359)
Equity compensation	—	2,103
Vesting of phantom units, net of units withheld for withholding taxes	1	(15)
Common units issued in the public offering, net of underwriting fees and offering expenses	—	(56)
Balance at June 30, 2025	118,336	$	1,375,695

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

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MACH NATURAL RESOURCES LP

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(in thousands)


	Six Months Ended June 30,
	2025		2024
Cash flows from operating activities
Net income	$	105,547	$	81,218
Adjustments to reconcile net income to cash provided by operating activities
Depreciation, depletion, amortization and accretion	130,683		135,531
(Gain) loss on derivative instruments	(14,886)		33,903
Loss on debt extinguishment	18,540		—
Cash receipts on settlement of derivative contracts, net	9,821		3,384
Debt issuance costs amortization	2,363		3,494
Equity based compensation	4,215		3,482
Adjustments to expected credit losses	125		647
(Gain) on sale of assets	(167)		(309)
Settlement of asset retirement obligations	(287)		(418)
Changes in operating assets and liabilities (decreasing) increasing cash:
Accounts receivable	28,679		(24,381)
Revenue payable	(10,314)		21,592
Accounts payable and accrued liabilities	10,653		2,280
Other	(12,312)		361
Net cash provided by operating activities	272,660		260,784

Cash flows from investing activities
Capital expenditures for oil and natural gas properties	(110,118)		(116,441)
Capital expenditures for other property and equipment	(3,793)		(7,032)
Acquisition of assets	(101,375)		(1,258)
Proceeds from sales of oil and natural gas properties	2,678		38,975
Proceeds from sales of other property and equipment	217		495
Net cash used in investing activities	(212,391)		(85,261)

Cash flows from financing activities
Proceeds from offering, net of offering costs	221,060		—
Repayments of borrowings on term note	(763,125)		(20,625)
Payments of debt extinguishment costs	(7,741)		—
Proceeds from borrowings on credit facilities	693,000		—
Repayments of borrowings on credit facilities	(128,000)		—
Debt issuance costs	(14,695)		(882)
Distributions to unitholders	(152,683)		(161,617)
Withholding taxes paid on vesting of phantom units	(84)		(570)
Net cash used in financing activities	(152,268)		(183,694)
Net (decrease) in cash and cash equivalents	(91,999)		(8,171)
Cash and cash equivalents, beginning of period	105,776		152,792
Cash and cash equivalents, end of period	$	13,777	$	144,621

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

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MACH NATURAL RESOURCES LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1.Organization and Nature of Business

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

The Company is a holding partnership whose sole material asset consists of membership interests in Mach Natural Resources Intermediate LLC (“Intermediate”), which owns each of the Company’s operating subsidiaries.

The Company’s operations are governed by the provisions of its partnership agreement, executed by its general partner, Mach Natural Resources GP LLC (the “General Partner”) and the limited partners. The General Partner is managed and operated by the board of directors and executive officers of the General Partner. The members of the board of directors of the General Partner are appointed by the members of the General Partner, BCE-Mach Aggregator and Mach Resources in proportion to their respective limited partnership ownership in the Company.

Management has evaluated how the Company is organized and managed and identified a single reportable segment, which is the exploration and production of oil, natural gas and NGLs. Management considers the Company’s gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and its revenues are attributable to United States customers.

2.Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The unaudited consolidated financial statements included herein were prepared from records of the Company in accordance with generally accepted accounting principles in the United States (“US GAAP”) and include accounts of our wholly owned subsidiaries. Intercompany accounts and transactions have been eliminated upon consolidation. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2024, as included in the Company’s Annual Report on Form 10-K. Results for interim periods are not necessarily indicative of results to be expected for the full year ending December 31, 2025. In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair statement of the financial information, have been included.

Use of Estimates

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

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

Cash and Cash Equivalents

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

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MACH NATURAL RESOURCES LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Accounts Receivable

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

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

As of June 30, 2025, the Company had two customers that represented approximately 12.5% and 10.2% of our total joint interest receivables. As of December 31, 2024, the Company had one customer that represented approximately 22.6% of our total joint interest receivables.

The Company establishes its allowance for credit losses equal to the estimable portions of accounts receivable for which failure to collect is expected to occur primarily based on a historical loss rate analysis. The Company estimates uncollectible amounts based on a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s expected ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company considers forecasts of future economic conditions in its estimate of expected credit losses and adjusts its allowance for expected credit losses when necessary. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for credit losses. At June 30, 2025 and December 31, 2024, the allowance for credit losses related to joint interest receivables were $4.1 million and $3.9 million, respectively, and the credit losses related to sales of oil and natural gas were not material.

Derivative Instruments

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

Oil and Natural Gas Operations

The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, costs of both successful and unsuccessful exploration and development activities are capitalized as proved oil and natural gas properties. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities, which are expensed as incurred. Capitalized costs are depreciated using the unit-of production method. Under this method, depletion is computed at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by a net equivalent proved reserves at the beginning of the period. Depletion per barrel equivalent unit of production was $8.15 and $7.87 for the six months ended June 30, 2025 and 2024, respectively. The average depletion rate per barrel equivalent unit of production was $8.17 and $7.88 for the three months ended June 30, 2025 and 2024, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $121.3 million and $127.8 million for the six months ended June 30, 2025 and 2024, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $62.2 million and $64.1 million for the three months ended June 30, 2025 and 2024, respectively.

Under the full cost method, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization, may not exceed the full cost “ceiling” at the end of each reporting period. The ceiling is calculated based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10%. The estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and natural gas properties. Estimated future net cash flows are calculated using the preceding 12-months’ average price based on closing prices on the first day of each month. The net book value is compared to the ceiling

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limitation on a quarterly basis. The excess, if any, of the net book value above the ceiling limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. The ceiling limitation computation is determined without regard to income taxes due to the Internal Revenue Service (“IRS”) recognition of the Company as a flow-through entity. No impairments on proved oil and natural gas properties were recorded for the three and six months ended June 30, 2025 and 2024.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. As of June 30, 2025, and December 31, 2024, the Company had no properties excluded from the full cost pool. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

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

Other Property and Equipment, Net

Other property and equipment primarily consists of gathering systems, processing plants, and saltwater disposal systems. Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed as incurred. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from two to 39 years. Depreciation expense for other property and equipment was $5.2 million and $4.3 million for the six months ended June 30, 2025 and 2024, respectively. Depreciation expense for other property and equipment was $2.8 million and $2.2 million for the three months ended June 30, 2025 and 2024, respectively.

Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. No impairment of other property and equipment was recorded for the three and six months ended June 30, 2025 or 2024.

Inventories

Inventories are stated at the lower of cost or net realizable value and consist of production and midstream equipment not placed in service as of June 30, 2025 and December 31, 2024, and crude oil held in storage. The Company’s production equipment primarily consists of oil and natural gas drilling or repair items such as tubing, casing and pumping units, as well as pipe for midstream operations, and are valued primarily using a weighted average cost method applied to specific classes of inventory items. Crude oil inventories are valued using the first-in, first-out inventory method. The components of inventory consisted of the following as of June 30, 2025 and December 31, 2024:


	June 30, 2025		December 31, 2024
Production equipment	$	24,828	$	23,475
Crude oil in storage	1,014		826
Total	$	25,842	$	24,301

Debt Issuance Costs

The Company capitalized $14.7 million of new debt issuance costs related to the New Revolving Credit Facility (as defined in Note 6) in the first half of 2025. The remaining unamortized debt issuance costs of $0.5 million from the Revolving

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Credit Agreement were retained and added to the additional amount of debt issuance costs associated with the New Revolving Credit Facility and are being amortized over the New Revolving Credit Facility’s term.

Other assets include capitalized costs related to the New Revolving Credit Facility of $15.2 million, net of accumulated amortization of $1.3 million as of June 30, 2025. As of December 31, 2024, other assets include capitalized costs related to the Revolving Credit Agreement of $2.6 million, net of accumulated amortization of $2.0 million. These costs are being amortized over the terms of the related credit agreements and are reported as interest expense in the Company’s statement of operations.

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

Income Taxes

The Company is a limited partnership treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of the Company passed through to partners. As such, with the exception of the state of Texas, we are not a taxable entity, we do not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for our operations, except as described below.

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

The Company disallows the recognition of tax positions not deemed to meet a “more-likely-than not” threshold of being sustained by the applicable tax authority. The Company’s policy is to reflect interest and penalties related to uncertain tax positions in general and administrative expense, when and if they become applicable. The Company has not recognized any potential interest or penalties in its financial statements for the six months ended June 30, 2025. The Company’s tax years 2024, 2023, and 2022 remain open for examination by state authorities.

Asset Retirement Obligations

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

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

In general, the amount of ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an estimated credit adjusted rate. If the estimated ARO changes materially, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and

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changes in the estimated timing of abandonment. The following is a reconciliation of ARO for the six months ended June 30, 2025 and 2024 (in thousands):


	June 30, 2025		June 30, 2024
Asset retirement obligation at beginning of period	$	101,858	$	85,094
Liabilities assumed in acquisitions	4,210		—
Liabilities incurred	81		469
Liabilities settled	(184)		(234)
Accretion expense	4,224		3,433
Asset retirement obligation at end of period	$	110,189	$	88,762

Revenue Recognition

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

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

Oil Sales

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

Natural Gas and NGL Sales

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

Midstream Revenue and Product Sales

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

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Product sales are generated from the Company’s sale of natural gas, oil and NGL production purchased from third parties and subsequently gathered and processed through the Company’s owned midstream facilities. Product sales include activity from certain third-party percent-of-proceeds contracts where the Company keeps a contractually based percentage of proceeds from the sale of natural gas and NGL production, as payment for processing natural gas from the third parties. The Company retains control of the purchased natural gas and NGLs prior to delivery to the purchaser and satisfies its

performance obligations by transferring control of the product at the delivery point and recognizes revenue based on the

contract price received from the purchaser. The costs of buying natural gas, oil and NGL production from third party shippers are included as costs of product sales on the statement of operations.

Transaction Price Allocated to Remaining Performance Obligations

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

Prior-Period Performance Obligations

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

Concentrations

The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. The following purchasers each accounted for more than 10% of the Company’s revenues for the three and six months ended June 30, 2025 and 2024:


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Philips 66 Company	26.9	%	29.1	%	26.8	%	28.4	%
NextEra Energy Marketing LLC	24.1	%	*		25.0	%	*
CVR Supply & Trading, LLC	11.2	%	*		10.9	%	*
Shell Oil Company	*		17.7	%	*		16.8	%

__________

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

The Company’s receivables as of June 30, 2025 and 2024 from oil and gas sales are concentrated with the same counterparties noted above. The Company does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

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Contract Balances

Cash received relating to future performance obligations is deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered to be material as of June 30, 2025. The Company’s product sales and marketing contracts do not give rise to contract assets.

Revenue Disaggregation

The following table displays the revenue disaggregated and reconciles disaggregated revenue to the revenue reported for the three and six months ended June 30, 2025 and 2024 (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Revenues:
Oil	$	110,686	$	150,431	$	235,227	$	294,529
Natural gas	69,205		38,923		155,452		102,935
NGL	39,603		46,084		84,180		94,194
Gross oil, natural gas, and NGL sales	219,494		235,438		474,859		491,658
Transportation, gathering and marketing	(82)		(3,899)		(2,721)		(4,879)
Net oil, natural gas, and NGL sales	$	219,412	$	231,539	$	472,138	$	486,779

Earnings per Common Unit

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

Supplemental Cash Flow Information

Supplemental disclosures to the statements of cash flows are presented below for the six months ended June 30, 2025 and 2024 (in thousands):


	Six Months Ended June 30,
	2025		2024
Supplemental disclosure of cash flow information:
Cash paid for interest	$	27,165	$	50,220
Supplemental disclosure of non-cash transactions:
Change in accrued capital expenditures	$	1,360	$	(4,079)
Asset retirement cost capitalized	$	81	$	469
Right-of-use assets obtained in exchange for lease liabilities	$	4,092	$	2,178
Increase in accrued distributions	$	1,405	$	1,127

Recent Accounting Pronouncements

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

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3.Acquisitions and Divestitures

Acquisitions

XTO Acquisition

On March 25, 2025, the Company entered into an Equity Interest Purchase Agreement (“XTO EIPA”), pursuant to which the Company would acquire certain oil and gas assets located in Oklahoma, Kansas and Wyoming, for consideration of $60.0 million in cash, subject to certain customary purchase price adjustments (the “XTO Acquisition”). The Company plans to finalize all such adjustments and complete the purchase price allocation in 2025 based on terms of the XTO EIPA. The Company does not expect post-closing adjustments to be material and they would primarily affect the value of proved oil and gas properties.

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


	XTO Acquisition
Consideration transferred:
Cash consideration	$	77,893
Total acquisition consideration	$	77,893
Assets acquired:
Proved oil and natural gas properties	$	65,530
Accounts receivable – joint interest	2,344
Other property and equipment	6,417
Other assets	9,576
Total assets to be acquired	83,867
Liabilities assumed:
Revenue suspense	1,354
Accrued liabilities	444
Asset retirement obligations	4,176
Total liabilities assumed	5,974
Net assets acquired	$	77,893

Flycatcher Acquisition

On December 20, 2024, the Company entered into a Purchase and Sale Agreement (the “Flycatcher PSA”) to purchase certain oil and gas assets near our recently acquired oil and gas assets located in the Ardmore Basin of Oklahoma for consideration of $29.8 million in cash, subject to certain customary purchase price adjustments (the “Flycatcher Acquisition”). The Company plans to finalize all such adjustments and complete the purchase price allocation in 2025 based on terms of the Flycatcher PSA. The Company does not expect post-closing adjustments to be material and they would primarily affect the value of proved oil and gas properties.

The transaction closed on January 31, 2025 and the Company borrowed $23.0 million on the Revolving Credit Agreement to fund the Flycatcher Acquisition. This purchase was accounted for as an asset acquisition as substantially all of the fair value of acquired assets could be allocated to a single identified asset group of proved oil and natural gas properties. The table below reflects the preliminary fair value estimates of the assets acquired and liabilities assumed as of the acquisition

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


	Flycatcher Acquisition
Consideration transferred:
Cash consideration	$	24,141
Capitalized transaction costs	182
Less: purchase price adjustment receivable	—
Total acquisition consideration	$	24,323
Assets acquired:
Proved oil and natural gas properties	$	26,566
Other assets	8
Total assets to be acquired	26,574
Liabilities assumed:
Revenue suspense	2,217
Asset retirement obligations	34
Total liabilities assumed	2,251
Net assets acquired	$	24,323

Ardmore Basin Acquisition

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

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


	Initial					Final
	Ardmore Basin Acquisition		Adjustments			Ardmore Basin Acquisition
Consideration transferred:
Cash consideration	$	78,317	$	(2,966)	(a)	$	75,351
Capitalized transaction costs	1,295		49		(a)	1,344
Less: purchase price adjustment receivable	(2,735)		2,735		(a)	—
Total acquisition consideration	$	76,877	$	(182)		$	76,695
Assets acquired:
Proved oil and natural gas properties	$	85,663	$	(269)	(a)	$	85,394
Other assets	13		—			13
Total assets to be acquired	85,676		(269)			85,407
Liabilities assumed:
Revenue suspense	8,636		(87)		(a)	8,549
Asset retirement obligations	163		—			163
Total liabilities assumed	8,799		(87)			8,712
Net assets acquired	$	76,877	$	(182)		$	76,695

a.Adjustment reflects additional accounting data received and processed subsequent to the acquisition date. The initial purchase price allocation considered available data at the time of disclosure.

Western Kansas Acquisition

On August 9, 2024, the Company executed a purchase and sale agreement (the “Western Kansas PSA”) to purchase certain oil and gas properties in Kansas and Oklahoma for consideration of $38.0 million in cash, subject to certain customary purchase price adjustments (the “Western Kansas Acquisition”). The Company plans to finalize all such adjustments and complete the purchase price allocation in 2025 based on terms of the Western Kansas PSA. The Company does not expect post-closing adjustments to be material and they would primarily affect the value of proved oil and gas properties.

The transaction closed on September 25, 2024. This purchase was accounted for as an asset acquisition as substantially all of the fair value of acquired assets could be allocated to a single identified asset group of proved oil and natural gas properties. The table below reflects the preliminary fair value estimates of the assets acquired and liabilities assumed as of

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


	Initial					As of June 30, 2025
	Western Kansas Acquisition		Adjustments			Western Kansas Acquisition
Consideration transferred:
Cash consideration	$	36,657	$	860	(a)	$	37,517
Capitalized transaction costs	—		301		(a)	301
Less: purchase price adjustment receivable	—		(549)		(a)	(549)
Total acquisition consideration	$	36,657	$	612		$	37,269
Assets acquired:
Proved oil and natural gas properties	$	45,582	$	698	(a)	$	46,280
Other property and equipment	400		—			400
Other assets	123		97		(a)	220
Total assets to be acquired	46,105		795			46,900
Liabilities assumed:
Revenue suspense	333		74		(a)	407
Asset retirement obligations	9,115		109		(a)	9,224
Total liabilities assumed	9,448		183			9,631
Net assets acquired	$	36,657	$	612		$	37,269

a.Adjustment reflects additional accounting data received and processed subsequent to the acquisition date. The initial purchase price allocation considered available data at the time of disclosure.

Divestitures

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

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4. Property and Equipment

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


	June 30, 2025		December 31, 2024
Oil and natural gas properties
Proved properties	$	2,621,011	$	2,419,998
Accumulated depreciation, depletion and amortization	(641,942)		(520,641)
Oil and natural gas properties, net	1,979,069		1,899,357
Other property and equipment
Gas gathering system	40,051		35,241
Gas processing plants	36,040		35,949
Water disposal assets	30,061		28,977
Other assets	19,309		15,308
Total other property and equipment	125,461		115,475
Accumulated depreciation, depletion and amortization	(28,694)		(23,710)
Total other property and equipment, net	$	96,767	$	91,765

5. Accrued Liabilities

Accrued liabilities consist of the following (in thousands):


	June 30, 2025		December 31, 2024
Operating expenses	$	13,682	$	12,489
Capital expenditures	16,062		24,027
Payroll costs	8,551		7,842
Derivative settlements	135		149
Severance and other tax	11,052		5,202
Midstream shipper payable	1,470		1,160
General, administrative, and other	13,142		2,631
Total accrued liabilities	$	64,094	$	53,500

6. Long-Term Debt

New Revolving Credit Facility

On February 27, 2025, the Company entered into a senior secured reserve-based revolving credit facility (the “New Revolving Credit Facility”), among the Company, the lenders and issuing banks party thereto from time to time and Truist Bank, as the administrative agent and collateral agent.

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

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

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The Company used borrowings from the New Revolving Credit Facility, together with cash on hand and proceeds from the February 2025 Offering (as defined below), to repay the Term Loan Credit Agreement and the Revolving Credit Agreement (as defined below) in full. As of June 30, 2025, there were $565.0 million of outstanding borrowings under the New Revolving Credit Facility with $5.0 million in outstanding letters of credit, and the remaining availability under the New Revolving Credit Facility was $180.0 million. The effective interest rate as of June 30, 2025 was 8.2%.

Term Loan Credit Agreement and Revolving Credit Agreement

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

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

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

Loans advanced to the Company under the Revolving Credit Agreement were secured by a super-priority security interest on substantially all of our assets. The Revolving Credit Agreement has (i) a maximum available principal amount of $75.0 million, with maximum commitments currently equal to $75.0 million, (ii) a maturity date of December 28, 2026 and (iii) an interest rate equal to the one, three, or six-month SOFR, at the Company’s election, plus a credit spread adjustment equal to 0.10%, 0.15%, or 0.25%, respectively, in each case, plus 3.00%, provided that the applicable tenor SOFR will not be less than 3.50%. The Revolving Credit Agreement included customary covenants, mandatory repayments and events of default of financings of this type. The Company was also required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Revolving Credit Agreement. The Company used borrowings from the Term Loan Credit Agreement, together with cash on hand, to repay the November 2023 Credit Facility. As of December 31, 2024, the Revolving Credit Agreement was undrawn, and there was $5.0 million in outstanding letters of credit.

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

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

The Company has not guaranteed the debt or obligations of any other party, nor does the Company have any other arrangements or relationships with other entities that could potentially result in consolidated debt or losses.

7. Derivative Contracts

The Company uses derivative contracts to reduce exposure to fluctuations in commodity prices. These transactions are in the form of fixed price swaps. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. The Company does not intend to hold or issue derivative

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financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.

Under fixed price swap contracts, the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. Crude oil derivative contracts are indexed and settled

based on NYMEX West Texas Intermediate (“WTI”) pricing and natural gas derivative contracts are indexed and settled

based on NYMEX Henry Hub pricing.

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

The following table summarizes the open financial derivative positions as of June 30, 2025, related to oil production:


Period	Volume (Mbbl)	Weighted Average Fixed Price
Q3 2025	705	$	68.41
Q4 2025	646	68.09
Q1 2026	600	67.35
Q2 2026	563	69.50
Q3 2026	266	66.20
Q4 2026	253	65.37
Q1 2027	241	65.00
Q2 2027	230	66.16

The following table summarizes the open financial derivative positions as of June 30, 2025, related to natural gas production:


Period	Volume (Bbtu)	Weighted Average Fixed Price
Q3 2025	10,782	$	3.58
Q4 2025	10,308	4.03
Q1 2026	9,896	4.03
Q2 2026	9,532	3.68
Q3 2026	4,602	3.53
Q4 2026	4,453	3.77
Q1 2027	4,316	4.35
Q2 2027	4,190	3.83

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

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


	June 30, 2025		December 31, 2024
Derivative contracts – current, gross	$	20,117	$	14,696
Netting arrangements	(3,580)		(627)
Derivative contracts – current, net	$	16,537	$	14,069

Derivative contracts – long-term, gross	$	5,412	$	2,182
Netting arrangements	(2,171)		(1,542)
Derivative contracts – long-term, net	$	3,241	$	640

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


	June 30, 2025		December 31, 2024
Derivative contracts – current, gross	$	(9,019)	$	(6,860)
Netting arrangements	3,580		627
Derivative contracts – current, net	$	(5,439)	$	(6,233)

Derivative contracts – long-term, gross	$	(6,695)	$	(6,415)
Netting arrangements	2,171		1,542
Derivative contracts – long-term, net	$	(4,524)	$	(4,873)

Gains and Losses. The following table presents the settlement and mark-to-market (“MTM”) gains and losses presented as a loss or gain on derivatives in the statement of operations for the three and six months ended June 30, 2025 and 2024 (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Settlements of oil derivatives	$	6,640	$	(7,124)	$	7,548	$	(5,213)
Settlements of natural gas derivatives	388		2,365		1,127		4,409
MTM gains (losses) on oil derivatives, net	15,401		6,788		16,196		(31,392)
MTM gains (losses) on natural gas derivatives, net	33,150		(6,664)		(9,985)		(1,707)
Total gains (losses) on derivative contracts	$	55,579	$	(4,635)	$	14,886	$	(33,903)

8. Fair Value Measurements

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

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

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

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

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

Fair Value on a Recurring Basis

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

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2025 and December 31, 2024 (in thousands):


	Level 1		Level 2		Level 3		Fair Value
As of June 30, 2025
Assets:
Commodity derivative instruments	$	—	$	19,778	$	—	$	19,778
Liabilities:
Commodity derivative instruments	$	—	$	(9,963)	$	—	$	(9,963)
As of December 31, 2024
Assets:
Commodity derivative instruments	$	—	$	14,709	$	—	$	14,709
Liabilities:
Commodity derivative instruments	$	—	$	(11,106)	$	—	$	(11,106)

Fair Value on a Non-Recurring Basis

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

Business Combinations

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

Fair Value of Other Financial Instruments

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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

9. Equity Compensation and Deferred Compensation Plan

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

On October 27, 2023, the Company adopted a new long-term incentive plan (the “Long-Term Incentive Plan”) for employees, consultants and directors in connection with the Offering. The Company issues phantom units (“Time-Based Phantom Units”) to certain employees of Mach Resources LLC (“Mach Resources”) and directors of the Company as compensation for services rendered to the Company. The Time-Based Phantom Unit awards for all employees of Mach Resources vest ratably on the first three anniversaries of the date of the grant, subject to the employee’s continued employment. Within 60 days of the vesting of a Time-Based Phantom Unit, the employee will receive a common unit of the Company. Each Time-Based Phantom Unit was granted with a corresponding distribution equivalent right (“DER”), which entitles the employee to receive a payment equal to the total distributions paid by the Company in respect of a common unit of the Company during the time the applicable phantom unit is outstanding. Payment of a DER occurs when its corresponding phantom unit vests, and in the event such phantom unit is forfeited, the corresponding DER is also forfeited.


	Time-Based Phantom Units	Weighted Average Grant Date Fair Value		Performance Phantom Units	Weighted Average Grant Date Fair Value
Unvested at December 31, 2023	709,545	$	18.80	—	$	—
Granted	6,412	$	17.59	—	$	—
Vested	—	$	—	—	$	—
Forfeited	(6,951)	$	18.80	—	$	—
Unvested at March 31,2024	709,006	$	18.79	—	$	—
Granted	9,260	$	19.30	46,348	$	26.80
Vested	(68,755)	$	18.80	—	$	—
Forfeited	(2,074)	$	18.80	—	$	—
Unvested at June 30, 2024	647,437	$	18.80	46,348	$	26.80


	Time-Based Phantom Units	Weighted Average Grant Date Fair Value		Performance Phantom Units		Weighted Average Grant Date Fair Value
Unvested at December 31, 2024	1,023,320	$	17.36	38,622		$	24.88
Granted	13,609	$	17.18	72,759	1	$	19.61
Vested	(1,998)	$	17.59	—		$	—
Forfeited	(4,467)	$	17.99	—		$	—
Unvested at March 31,2025	1,030,464	$	17.35	111,381		$	21.44
Granted	17,721	$	15.77	—		$	—
Vested	(2,775)	$	19.30	—		$	—
Forfeited	(15,530)	$	17.29	—		$	—
Unvested at June 30, 2025	1,029,880	$	17.32	111,381		$	21.44

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Total non-cash compensation cost related to the Time-Based Phantom Units was $3.7 million and $3.3 million for the six months ended June 30, 2025 and 2024, respectively. Total non-cash compensation cost related to the Time-Based Phantom Units was $1.8 million and $2.2 million for the three months ended June 30, 2025 and 2024, respectively. As of June 30, 2025, there was $12.8 million of unrecognized compensation cost related to Time-Based Phantom Units that is expected to be recognized over a weighted average period of approximately 1.9 years.

The aggregate fair value of share based awards that vested during the three and six months ended June 30, 2025 was approximately $43.8 thousand and $75.6 thousand, respectively, based on the unit price at the time of vesting.

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

The table below summarizes the assumptions used in the Monte Carlo simulation to determine the grant date fair value of units granted during the year ended December 31, 2024, and the six months ended June 30, 2025.


Grant date	May 3, 2024	January 1, 2025
Period for volatility, correlations, and risk-free rate	2.66 years	3.00 years
Risk-free interest rate	4.61%	4.23%
Implied equity volatility	57.25%	50.57%
Unit price on date of grant	$20.44	$17.18

Total non-cash compensation cost related to the Performance Phantom Units was $0.5 million and $0.1 million for the six months ended June 30, 2025 and 2024, respectively. Total non-cash compensation cost related to the Performance Phantom Units was $0.3 million and $0.1 million for the three months ended June 30, 2025 and 2024, respectively. As of June 30, 2025, there was $1.6 million of unrecognized compensation cost related to Performance Phantom Units that is expected to be recognized over a weighted average period of approximately 1.9 years.

10. Commitments and Contingencies

Legal Matters. In the ordinary course of business, the Company may at times be subject to claims and legal actions including, but not limited to, title disputes, royalty disputes, contract claims, personal injury claims and employment claims. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters. Nevertheless, actual outcomes may differ significantly from the Company’s assessment. As of June 30, 2025, the Company has accrued approximately $11.1 million in accrued liabilities pertaining to these matters, of which $8.2 million is presented in other income (expense), net in the statement of operations for the three and six months ended June 30, 2025. As of December 31, 2024, the Company has accrued approximately $1.5 million in accrued liabilities pertaining to these matters. Management does not expect that the impact of such matters will have a materially adverse effect on the Company’s financial position, results of operations or cash flows.

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

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MACH NATURAL RESOURCES LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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

NGL Sales and Gas Transportation Commitments. The Company is party to a NGL sales contract, which includes certain NGL volume commitments in the event the Company elects not to reduce its committed quantity, at its option. To the extent the Company does not deliver NGL volumes in sufficient quantities to meet the commitment and does not elect to reduce its committed quantity, it would be required to pay a deficiency fee. The Company is currently delivering at least the minimum volumes. Additionally, the Company has natural gas firm transportation agreements terminating in 2025. For the six months ended June 30, 2025 and 2024, the Company incurred approximately $0.2 million and $2.1 million, respectively, of transportation charges under these agreements. For the three months ended June 30, 2025 and 2024, the Company incurred approximately $0.1 million and $0.9 million, respectively, of transportation charges under these agreements. As of June 30, 2025, the Company has no material amounts remaining under these agreements.

Contributions to 401(k) Plan. The Company sponsors a 401(k) plan under which eligible employees may contribute a portion of their total compensation up to the maximum pre-tax threshold through salary deferrals. The plan provides a company match on 100% of salary deferrals that do not exceed 10% of compensation. The Company contributed $2.2 million and $2.0 million for the six months ended June 30, 2025 and 2024, respectively. The Company contributed $1.1 million and $0.9 million for the three months ended June 30, 2025 and 2024, respectively.

11. Leases

Nature of Leases

The Company has operating leases on office spaces, various vehicles and compressors with remaining lease durations in excess of one year. These leases have various expiration dates through 2029. The vehicles are used for field operations and leased from third parties. The Company recognizes right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year. Short-term leases that have an initial term of one year or less are not capitalized.

Discount Rate

As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. The Company’s incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow an amount equal to the lease payments on a collateralized basis over a similar term and in a similar economic environment.

Future amounts due under operating lease liabilities as of June 30, 2025, were as follows (in thousands):


Remaining 2025	$	3,323
2026	5,324
2027	4,274
2028	3,038
2029	1,725
Total lease payments	$	17,684
Less: imputed interest	(2,096)
Total	$	15,588

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MACH NATURAL RESOURCES LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

The following table summarizes our total lease costs before amounts are recovered from our joint interest partners, where applicable, for the three and six months ended June 30, 2025 and 2024 (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Operating lease cost	$	1,875	$	2,864	$	3,963	$	6,937
Short-term lease cost	10,818		5,990		18,320		11,862
Total lease cost	$	12,693	$	8,854	$	22,283	$	18,799

The weighted-average remaining lease term as of June 30, 2025 was 3.33 years. The weighted-average discount rate used to determine the operating lease liability as of June 30, 2025 was 7.5%.


	Six Months Ended June 30,
	2025		2024
Operating cash flows from operating leases	$	3,877	$	6,954

12. Partners’ Capital

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

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

As of June 30, 2025 and December 31, 2024, the Company had 118.3 million and 103.5 million common units outstanding, respectively.

The Company distributed $0.79 per unit for total cash distributions of $93.5 million for the three months ended June 30, 2025. The Company distributed $1.29 per unit for total cash distributions of $152.7 million for the six months ended June 30, 2025.

13. Earnings Per Common Unit

The Company has a single class of common units representing limited partnership interests. The Company has potentially dilutive securities as of June 30, 2025, which consist of phantom units issued under the Company’s long-term incentive plan. There were 0.1 million phantom units that were considered dilutive for the three and six months ended June 30, 2025. The treasury stock method is used to determine the dilutive impact of the Company’s phantom units. As of June 30, 2025 there were 17.7 thousand phantom units that were considered antidilutive and thus excluded from the calculation of diluted earnings per common unit. As of June 30, 2024, there were no units that were considered antidilutive.

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MACH NATURAL RESOURCES LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

The following represents the computation of basic and diluted earnings per common unit for the three and six months ended June 30, 2025 (in thousands, except per unit data):


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Net income - basic and diluted	$	89,661	$	39,516	$	105,547	$	81,218
Weighted-average common units outstanding - basic	118,336		95,009		115,248		95,004
Effect of dilutive securities	53		178		65		125
Weighted-average common units outstanding - diluted	118,389		95,187		115,313		95,129
Earnings per common unit - basic	$	0.76	$	0.42	$	0.92	$	0.85
Earnings per common unit - diluted	$	0.76	$	0.42	$	0.92	$	0.85

14. Related Party Transactions

Management Services Agreement.

On October 27, 2023, the Company entered into a management services agreement (the “MSA”) with Mach Resources. Under the MSA, Mach Resources manages and performs all aspects of oil and gas operations and other general and administrative functions for the Company and the Company (i) will pay Mach Resources an annual management fee of approximately $7.4 million and (ii) reimburse Mach Resources for the costs and expenses of the services provided. On a monthly basis, the Company distributes funding to Mach Resources for performance under the MSA. During the six months ended June 30, 2025 and 2024, the Company paid Mach Resources $57.2 million (inclusive of $3.7 million in management fees presented as general and administrative expense - related party in the statement of operations) and $56.9 million (inclusive of $3.7 million as management fees presented in general and administrative expense - related party in the statement of operations), respectively. During the three months ended June 30, 2025 and 2024, the Company paid Mach Resources $25.9 million (inclusive of $1.9 million in management fees presented as general and administrative expense - related party in the statement of operations) and $26.5 million (inclusive of $1.9 million as management fees presented in general and administrative expense - related party in the statement of operations), respectively. As of June 30, 2025 and December 31, 2024, the Company owed $1.8 million and $2.0 million, respectively, to Mach Resources, presented as accounts payable - related party.

Common units purchased by BCE-Mach Aggregator

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

15. Segment Information

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

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

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

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MACH NATURAL RESOURCES LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

The following table summarizes total revenues, significant expenses, net income and capital expenditures related to the E&P Segment for the three and six months ended June 30, 2025 and 2024 (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Total revenues	$	288,517	$	239,994	$	515,285	$	479,149

Gathering and processing	31,784		23,831		59,945		55,773
Lease operating expense	49,566		46,497		98,318		87,257
Production taxes	10,496		11,302		23,270		24,054
Total significant expenses	91,846		81,630		181,533		167,084
Midstream operating expense	3,200		2,616		6,170		5,175
Cost of product sales	6,274		5,786		14,261		11,886
Depreciation, depletion, amortization and accretion – oil and natural gas	64,340		65,819		125,525		131,191
Depreciation and amortization – other	2,758		2,242		5,158		4,340
General and administrative	6,952		9,568		15,969		18,046
General and administrative – related party	1,850		1,850		3,700		3,700
Interest expense	12,140		27,046		30,034		53,331
Loss on debt extinguishment	—		—		18,540		—
Other expense, net	9,496		3,921		8,848		3,178
Total expenses	198,856		200,478		409,738		397,931

Net income	$	89,661	$	39,516	$	105,547	$	81,218

Capital expenditures, including acquisitions	125,452		45,669		206,810		127,245

The following table summarizes total assets to the E&P Segment as of June 30, 2025 and December 31, 2024 (in thousands):


	June 30, 2025		December 31, 2024
Total assets	$	2,334,165	$	2,338,214

16. Subsequent Events

Sabinal Acquisition

On July 9, 2025, the Company entered into a Purchase and Sale Agreement with Sabinal Energy Operating, LLC, Sabinal Resources, LLC and Sabinal CBP, LLC (collectively, the “Sabinal Sellers”), pursuant to which the Company would acquire certain oil and gas assets located in certain designated lands in the Permian Basin, for consideration of approximately $500.0 million comprised of (i) $200.0 million in cash and (ii) 20.6 million common units (the “Sabinal Unit Consideration”), subject to certain customary purchase price adjustments (the “Sabinal Acquisition”). The Sabinal Unit Consideration has a value of approximately $300.0 million based on the volume weighted average price of the common units for the 10-day period prior to the announcement of the Sabinal Acquisition. The transaction is expected to

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MACH NATURAL RESOURCES LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

close during the third quarter of 2025. Subsequent to June 30, 2025, the Company paid a deposit of $37.5 million with an escrow agent to ensure the Company’s and the Sabinal Sellers’ performance of their respective obligations.

IKAV Acquisition

On July 9, 2025, the Company entered into a membership interest purchase agreement with VEPU Inc. and Simlog Inc. (collectively, the “IKAV Sellers”), pursuant to which the Company would acquire one hundred percent (100%) of the IKAV Sellers’ membership interests in certain rights, titles and interests in oil and gas properties, rights and related assets located in certain designated lands in the San Juan Basin of New Mexico and Colorado, for consideration of approximately $787.2 million comprised of (i) $325.0 million in cash and (ii) 31.7 million common units (the “IKAV Unit Consideration”), subject to certain customary purchase price adjustments (the “IKAV Acquisition”). The IKAV Unit Consideration has a value of approximately $462.2 million based on the volume weighted average price of the common units for the 10-day period prior to the announcement of the IKAV Acquisition. The transaction is expected to close during the third quarter of 2025. Subsequent to June 30, 2025, the Company paid a deposit of $38.8 million with an escrow agent to ensure the Company’s and the IKAV Sellers’ performance of their respective obligations.

Revolving Credit Facility Consent

On July 8, 2025, the Company entered into a Letter Agreement (the “Letter Agreement”) among the Company, the lenders party thereto and Truist Bank, as administrative agent and collateral agent, relating to the New Revolving Credit Facility. Pursuant to the Letter Agreement, the lenders under the New Revolving Credit Facility waived certain restrictions to permitted payments with respect to certain financial covenants.

Distribution Declaration

On August 7, 2025, the Company declared its quarterly distribution for the second quarter of 2025 of $0.38 per common unit, which will be paid on September 4, 2025.

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

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company’s operating results. The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and related notes included in Part I, Item I of this Quarterly Report and also with “Risk Factors” included in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2024. The following information updates the discussion of our financial condition provided in our previous filings and analyzes the changes in the results of operations for the three and six months ended June 30, 2025 and 2024.

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance, which may affect our future operating results and financial position. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Actual results and the timing of the events could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic, inflationary and competitive conditions, drilling results, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Quarterly Report, particularly under “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

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

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

Market Outlook

Our financial results depend on many factors, particularly commodity prices and our ability to find, develop and market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand. The oil and natural gas industry is cyclical and commodity prices are highly volatile and we expect continued and increased pricing volatility in the crude oil and natural gas markets. Regional and worldwide economic activity, including any economic downturn or recession that has occurred or may occur in the future, extreme weather conditions and other substantially variable factors, influence market conditions for these products. Between January 1, 2024 and June 30, 2025, NYMEX WTI prices for crude oil ranged from $57.13 to $86.91 per Bbl, and the NYMEX Henry Hub price of natural gas ranged from $1.58 to $4.49 per MMBtu. The war in Ukraine and conflict in the Middle East, uncertainty regarding interest rates, global supply chain disruptions, the potential for significant new tariffs, OPEC+’s decision to increase production in May and July 2025, concerns about a potential economic downturn or recession, and instability in the financial sector have contributed to recent economic and pricing volatility and may continue to impact pricing throughout 2025.

Between 2022 and 2024, the Federal Reserve raised the target range for the federal funds rate in an effort to curb inflation. In September 2024 and November 2024, the Federal Reserve lowered the target range for the federal funds rate to its current range of 4.25% to 4.50% in light of the reduced inflation. In June 2025, inflation, as measured by the consumer price index, was 2.7%. We cannot predict the future inflation rate but to the extent we experience high inflation, we may see cost increases in our operations, including costs for drill rigs, workover rigs, tubulars and other well equipment, as well as increased labor costs. We continue to evaluate actions to mitigate supply chain and inflationary pressures and work closely with other suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical supplies which are critical to many of our operations. However, these mitigation efforts may not succeed or may be insufficient. Further, if we are unable to recover higher costs through higher commodity prices, our current revenue stream,

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estimates of future reserves, borrowing base calculations, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions would all be significantly impacted.

How We Evaluate Our Operations

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

•net production volumes;

•realized prices on the sale of oil, natural gas and NGLs;

•lease operating expense;

•Adjusted EBITDA; and

•cash available for distribution.

Factors Affecting the Comparability of Our Future Results of Operations to Our Historical Results of Operations

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

Acquisitions

We have completed four acquisitions since the beginning of 2024. These acquisitions are reflected in our results of operations as of and after the date of completion for each such acquisition. As a result, periods prior to each such acquisition will not contain the results of such acquired assets which will affect the comparability of our results of operations for certain historical periods. We may continue to grow our operations through acquisitions when economical, including by funding such acquisitions under our New Revolving Credit Facility.

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Results of Operations

Three Months Ended June 30, 2025 Compared to the Three Months Ended June 30, 2024

Revenue

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


	Three Months Ended June 30,				Change
($ in thousands)	2025		2024		Amount		Percent
Revenues:
Oil	$	111,053	$	150,889	$	(39,836)	(26	%)
Natural gas	68,420		34,237		34,183		100	%
Natural gas liquids	39,939		46,413		(6,474)		(14	%)
Total oil, natural gas, and NGL sales	219,412		231,539		(12,127)		(5	%)
Gain (loss) on oil and natural gas derivatives, net	55,579		(4,635)		60,214		NM(1)
Midstream revenue	6,257		6,441		(184)		(3	%)
Product sales	7,269		6,649		620		9	%
Total revenues	$	288,517	$	239,994	$	48,523	20	%
Average Sales Price:
Oil ($/Bbl)	$	63.10	$	79.27	$	(16.17)	(20	%)
Natural gas ($/Mcf)	$	2.81	$	1.33	$	1.48	111	%
NGL ($/Bbl)	$	22.41	$	23.83	$	(1.42)	(6	%)
Total ($/Boe) – before effects of realized derivatives	$	28.85	$	28.48	$	0.37	1	%
Total ($/Boe) – after effects of realized derivatives	$	29.77	$	27.89	$	1.88	7	%
Net Production Volumes:
Oil (MBbl)	1,760		1,903		(143)		(8	%)
Natural gas (MMcf)	24,383		25,675		(1,292)		(5	%)
NGL (MBbl)	1,783		1,947		(164)		(8	%)
Total (MBoe)	7,606		8,130		(524)		(6	%)
Average daily total volumes (MBoe/d)	83.59		89.34		(5.75)		(6	%)

(1)Not Meaningful

Revenue and Other Operating Income

Oil, natural gas and NGL sales

Revenues from oil, natural gas and NGL sales decreased $12.1 million, or 5% for the three-month period ended June 30, 2025, as compared to the three-month period ended June 30, 2024. This decrease was primarily related to a 6% production decrease, which resulted in decreased oil, natural gas and NGL sales of $16.4 million. These decreases were offset with an overall increase in the average selling price of our products, which resulted in an increase in oil, natural gas, and NGL sales of $4.2 million.

Oil, natural gas and NGL production

Production decreased 524 MBoe, or 6% for the three-month period ended June 30, 2025, as compared to the three-month period ended June 30, 2024. The decrease was primarily a result of natural well declines on our producing wells, partially offset with new production on wells completed subsequent to June 30, 2024.

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Oil and natural gas derivatives

For the three-month period ended June 30, 2025, we had realized gains on derivative instruments of $7.0 million and unrealized gains of $48.6 million for total gains of $55.6 million. For the three-month period ended June 30, 2024, we had realized losses on derivative instruments of $4.8 million and unrealized gains of $0.1 million for total losses of $4.6 million. The increase in both realized and unrealized gains is primarily from a decrease in oil prices throughout the second quarter.

Midstream revenue

Midstream revenue decreased $0.2 million, or 3% for the three-month period ended June 30, 2025, as compared to the three-month period ended June 30, 2024, primarily due to lower third-party volumes flowing through our midstream facilities for the three-month period ended June 30, 2025, as compared to the three-month period ended June 30, 2024.

Product sales

Product sales increased $0.6 million, or 9% for the three-month period ended June 30, 2025, as compared to the three-month period ended June 30, 2024. This increase was primarily a result of increases in the average selling price of natural gas. These increases corresponded with the increase in our cost of product sales noted below.

Operating Expenses

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


	Three Months Ended June 30,						Change
($ in thousands)	2025			2024			Amount			Percent
Operating Expenses:
Gathering and processing expense	$	31,784		$	23,831		$	7,953		33	%
Lease operating expense	$	49,566		$	46,497		$	3,069		7	%
Production taxes	$	10,496		$	11,302		$	(806)		(7	%)
Midstream operating expense	$	3,200		$	2,616		$	584		22	%
Cost of product sales	$	6,274		$	5,786		$	488		8	%
Depreciation, depletion, amortization and accretion expense – oil and natural gas	$	64,340		$	65,819		$	(1,479)		(2	%)
Depreciation and amortization expense – other	$	2,758		$	2,242		$	516		23	%
General and administrative	$	8,802		$	11,418		$	(2,616)		(23	%)
Total operating expenses	$	177,220		$	169,511		$	7,709		5	%
Operating Expenses ($/Boe):
Gathering and processing expense	$	4.18		$	2.93		$	1.25		43	%
Lease operating expense	$	6.52		$	5.72		$	0.80		14	%
Production taxes (% of oil, natural gas and NGL sales)	4.8		%	4.9		%	(0.1)		%	(2	%)
Depreciation, depletion, amortization and accretion expense – oil and natural gas	$	8.46		$	8.10		$	0.36		4	%
Depreciation and amortization expense – other	$	0.36		$	0.28		$	0.08		29	%
General and administrative	$	1.16		$	1.40		$	(0.24)		(17	%)

Gathering and processing expense

Gathering and processing expense increased $8.0 million, or 33%, and $1.25 per Boe, or 43%, for the three-month period ended June 30, 2025, as compared to the three-month period ended June 30, 2024, primarily as a result of higher fuel costs due to higher natural gas prices. Additionally, due to changes in certain purchaser contracts in the second quarter of 2025, certain post-production costs that were previously presented as a reduction to gas revenue are now presented as gathering and processing expense.

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Lease operating expense

Lease operating expense increased $3.1 million, or 7% for the three-month period ended June 30, 2025, as compared to the three-month period ended June 30, 2024, primarily as a result of an increase in company labor and contract services of $2.5 million. Lease operating expenses per Boe increased by $0.80 primarily related to the above noted increases, combined with lower production for the three-month period ended June 30, 2025, as compared to the three-month period ended June 30, 2024.

Production taxes

Production taxes decreased $0.8 million, or 7% for the three-month period ended June 30, 2025, as compared to the three-month period ended June 30, 2024. This decrease was in line with the decrease in oil, natural gas and NGL sales.

Midstream operating expense

Midstream operating expense increased $0.6 million, or 22% for the three-month period ended June 30, 2025, as compared to the three-month period ended June 30, 2024, primarily as a result of higher gathering operating expense of $0.4 million.

Cost of product sales

Cost of product sales increased $0.5 million, or 8% for the three-month period ended June 30, 2025, as compared to the three-month period ended June 30, 2024. This increase was primarily a result of the increase in the average selling price of natural gas. These increases were consistent with the increase in product sales noted above.

Depreciation, depletion, amortization and accretion expense - oil and natural gas

Depreciation, depletion, amortization and accretion expense for oil and natural gas properties decreased by $1.5 million, or 2% for the three-month period ended June 30, 2025, as compared to the three-month period ended June 30, 2024. The decrease is primarily the result of a decrease in production used to calculate depletion.

General and administrative costs

General and administrative costs decreased $2.6 million, or 23% for the three-month period ended June 30, 2025, as compared to the three-month period ended June 30, 2024. The decrease is primarily a result of additional cost recovery per the terms of joint operating agreements from acquired wells subsequent to June 30, 2024.

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Six Months Ended June 30, 2025 Compared to the Six Months Ended June 30, 2024

Revenue


	Six Months Ended June 30,				Change
($ in thousands)	2025		2024		Amount		Percent
Revenues:
Oil	$	236,064	$	295,410	$	(59,346)	(20	%)
Natural gas	151,141		96,518		54,623		57	%
Natural gas liquids	84,933		94,851		(9,918)		(10	%)
Total oil, natural gas, and NGL sales	472,138		486,779		(14,641)		(3	%)
Gain (loss) on oil and natural gas derivatives, net	14,886		(33,903)		48,789		NM(1)
Midstream revenue	12,387		12,660		(273)		(2	%)
Product sales	15,874		13,613		2,261		17	%
Total revenues	$	515,285	$	479,149	$	36,136	8	%
Average Sales Price:
Oil ($/Bbl)	$	66.93	$	78.23	$	(11.30)	(14	%)
Natural gas ($/Mcf)	$	3.17	$	1.85	$	1.32	71	%
NGL ($/Bbl)	$	24.77	$	25.32	$	(0.55)	(2	%)
Total ($/Boe) – before effects of realized derivatives	$	31.71	$	30.00	$	1.71	6	%
Total ($/Boe) – after effects of realized derivatives	$	32.29	$	29.95	$	2.34	8	%
Net Production Volumes:
Oil (MBbl)	3,527		3,776		(249)		(7	%)
Natural gas (MMcf)	47,604		52,232		(4,628)		(9	%)
NGL (MBbl)	3,429		3,747		(318)		(8	%)
Total (MBoe)	14,890		16,228		(1,338)		(8	%)
Average daily total volumes (MBoe/d)	82.26		89.17		(6.91)		(8	%)

(1)Not Meaningful

Revenue and Other Operating Income

Oil, natural gas and NGL sales

Revenues from oil, natural gas and NGL sales decreased $14.6 million, or 3% for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024. This decrease was primarily related to the 8% production decrease, which resulted in decreased oil, natural gas and NGL sales of $39.2 million. These decreases were offset with an overall increase in the average selling price of our products, which resulted in an increase in oil, natural gas, and NGL sales of $24.6 million.

Oil, natural gas and NGL production

Production decreased 1,338 MBoe, or 8% for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024. The decrease was primarily a result of natural well declines on our producing wells, partially offset with new production on wells completed subsequent to June 30, 2024.

Oil and natural gas derivatives

For the six-month period ended June 30, 2025, we had realized gains on derivative instruments of $8.7 million and unrealized gains of $6.2 million for total gains of $14.9 million. For the six-month period ended June 30, 2024, we had

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realized losses on derivative instruments of $0.8 million and unrealized losses of $33.1 million for total losses of $33.9 million. The increase in both realized and unrealized gains is primarily from a decrease in oil prices throughout the second quarter of 2025.

Midstream revenue

Midstream revenue decreased $0.3 million, or 2% for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024, primarily due to lower third-party volumes flowing through our midstream facilities for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024.

Product sales

Product sales increased $2.3 million, or 17% for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024. This increase was primarily a result of the increase in the average selling price of natural gas. These increases corresponded with the increase in our cost of product sales noted below.

Operating Expenses


	Six Months Ended June 30,						Change
($ in thousands)	2025			2024			Amount			Percent
Operating Expenses:
Gathering and processing expense	$	59,945		$	55,773		$	4,172		7	%
Lease operating expense	$	98,318		$	87,257		$	11,061		13	%
Production taxes	$	23,270		$	24,054		$	(784)		(3	%)
Midstream operating expense	$	6,170		$	5,175		$	995		19	%
Cost of product sales	$	14,261		$	11,886		$	2,375		20	%
Depreciation, depletion, amortization and accretion expense – oil and natural gas	$	125,525		$	131,191		$	(5,666)		(4	%)
Depreciation and amortization expense – other	$	5,158		$	4,340		$	818		19	%
General and administrative	$	19,669		$	21,746		$	(2,077)		(10	%)
Total operating expenses	$	352,316		$	341,422		$	10,894		3	%
Operating Expenses ($/Boe):
Gathering and processing expense	$	4.03		$	3.44		$	0.59		17	%
Lease operating expense	$	6.60		$	5.38		$	1.22		23	%
Production taxes (% of oil, natural gas and NGL sales)	4.9		%	4.9		%	—		%	—	%
Depreciation, depletion, amortization and accretion expense – oil and natural gas	$	8.43		$	8.08		$	0.35		4	%
Depreciation and amortization expense – other	$	0.35		$	0.27		$	0.08		30	%
General and administrative	$	1.32		$	1.34		$	(0.02)		(1	%)

Gathering and processing expense

Gathering and processing expense increased $4.2 million, or 7%, and $0.59 per Boe, or 17%, for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024, primarily as a result of higher fuel costs due to higher natural gas prices. Additionally, due to changes in certain purchaser contracts in the second quarter of 2025, certain post production-costs that were previously presented as a reduction to natural gas revenue are now presented as gathering and processing expense.

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Lease operating expense

Lease operating expense increased $11.1 million, or 13% for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024, primarily as a result of an increase in company labor and contract services of $4.9 million, higher saltwater disposal related expenses of $3.8 million, and higher compression expenses of $1.3 million. Lease operating expenses per Boe increased by $1.22 primarily related to the above noted increases, combined with lower production for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024.

Production taxes

Production taxes decreased $0.8 million, or 3% for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024. This decrease was in line with the decrease in oil, natural gas and NGL sales.

Midstream operating expense

Midstream operating expense increased $1.0 million, or 19% for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024, primarily as a result of an increase of $0.4 million in both gathering operating expense and plant operating expense.

Cost of product sales

Cost of product sales increased $2.4 million, or 20% for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024. This increase was primarily a result of the increase in the average selling price of natural gas. These increases were consistent with the increase in product sales noted above.

Depreciation, depletion, amortization and accretion expense - oil and natural gas

Depreciation, depletion, amortization and accretion expense for oil and natural gas properties decreased by $5.7 million, or 4% for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024. The decrease is primarily the result of a decrease in production used to calculate depletion.

General and administrative costs

General and administrative costs decreased $2.1 million, or 10% for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024. The decrease is primarily a result of additional cost recovery per the terms of joint operating agreements from acquired wells subsequent to June 30, 2024.

Liquidity and Capital Resources

Our primary sources of liquidity and capital are cash flows generated by operating activities, borrowings under the New Revolving Credit Facility, and proceeds from the issuance of equity and debt. At June 30, 2025, outstanding borrowings under the New Revolving Credit Facility were $565.0 million with $5.0 million in letters of credit outstanding, and the remaining availability under the New Revolving Credit Facility was $180.0 million at June 30, 2025.

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

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

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Historically, our business plan has focused on acquiring and then exploiting the development and production of our assets. We spent approximately $115.5 million during the six-month period ended June 30, 2025 on development costs and our budget for 2025 is between $260.0 million and $280.0 million. For purposes of calculating our cash available for distribution, we define development costs as all of our capital expenditures, other than acquisitions. Our development efforts and capital for 2025 is anticipated to focus on a mix of drilling Oswego, Woodford, Red Fork and Mississippian wells.

During the six-month period ended June 30, 2025, we spent approximately $96.7 million on drilling and completion activities and related equipment and spud 16.1 net wells while bringing online 18.6 net wells, $15.1 million on remedial workovers and other capital projects, $3.7 million on midstream and other property and equipment capital projects and $91.3 million on acquisitions of oil and natural gas properties and other property and equipment.

Our 2025 capital expenditures program is largely discretionary and within our control. We could choose to defer a portion of these planned 2025 capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, including acid to be used for our acid stimulation completion, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows and reduce our cash available for distribution to unitholders.

On July 9, 2025, we entered into agreements governing the Sabinal Acquisition and the IKAV Acquisition, pursuant to which we agreed to issue an aggregate of 52,348,901 common units as consideration to the Sabinal Sellers and the IKAV Sellers. In connection with the Sabinal Acquisition and the IKAV Acquisition, we may also evaluate additional capital markets transactions; however, there is no guarantee that we will execute a capital markets transaction on favorable terms or at all. Whether or not the Sabinal Acquisition and the IKAV Acquisition close, based on our current oil and natural gas price expectations, we believe our cash flows provided by operating activities and availability under our New Revolving Credit Facility will provide us with the financial flexibility necessary to meet our cash requirements, including normal operating needs, and to pursue our currently planned 2025 development activities. Further, we believe that existing cash and cash equivalents, any positive cash flows from operations and available borrowings under our New Revolving Credit Facility will be sufficient to support working capital, capital expenditures and other cash requirements for at least the next 12 months and, based on our current expectations, for the foreseeable future thereafter.

Cash Flows

The following table summarizes our cash flows for the periods indicated:


	Six Months Ended June 30,
(in thousands)	2025		2024
Net cash provided by operating activities	$	272,660	$	260,784
Net cash used in investing activities	$	(212,391)	$	(85,261)
Net cash used in financing activities	$	(152,268)	$	(183,694)

Net cash provided by operating activities

Net cash provided by operating activities increased $11.9 million for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024. The increase in net cash provided by operating activities is primarily a result of an increase in the average selling price of natural gas, offset with a decrease in production. Additionally, we had an increase in realized gains on derivative instruments of $9.5 million for the six-month period ended June 30, 2025 primarily from a decrease in oil prices throughout the second quarter of 2025.

Net cash used in investing activities

Net cash used in investing activities increased $127.1 million for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024. The increase in net cash used in investing activities is primarily a result of increases in cash used to acquire assets of $100.1 million in the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024. This was slightly offset by decreases in capital expenditures on our oil and gas properties and on our other property and equipment of $6.3 million and $3.2 million, respectively, due to decreased drilling

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and completion activities in the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024.

Net cash used in financing activities

Net cash used in financing activities decreased $31.4 million for the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024. The decrease in net cash used in investing activities is primarily due to an increase in cash provided by borrowings on our credit facilities, net of repayments of $565.0 million, and an increase in cash provided from proceeds from follow-on offerings of $221.1 million. These were partially offset by increases in cash used for repayments of our term loan of $742.5 million, prepayment penalties of $7.7 million and new debt issuance costs of $13.8 million. Additionally, there was a decrease in cash used for distributions to unitholders of $8.9 million in the six-month period ended June 30, 2025, as compared to the six-month period ended June 30, 2024.

Debt Agreements

New Revolving Credit Facility

On February 27, 2025, the Company entered into the New Revolving Credit Facility, among the Company, the lenders and issuing banks party thereto from time to time and Truist Bank, as the administrative agent and collateral agent.

The New Revolving Credit Facility’s borrowing base is redetermined semi-annually, in April and October. The New Revolving Credit Facility requires the Company to maintain as of the last day of each fiscal quarter (i) a consolidated total net leverage ratio of less than or equal to 3.00 to 1.00, and (ii) a current ratio of no less than 1.00 to 1.00. In July 2025, the

Company entered into the Letter Agreement pursuant to which the lenders under the New Revolving Credit Facility waived

certain restrictions to permitted payments with respect to certain financial covenants.

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

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

Contractual Obligations and Commitments

We are a party to firm transportation contracts for the transport of natural gas. We paid approximately $0.1 million and $0.2 million in firm transportation contracts for the three and six month periods ended June 30, 2025, respectively. As of June 30, 2025, the Company has no material amounts remaining under these agreements. For further information on firm transportation contracts, see Note 10 of our consolidated financial statements.

Operating lease obligations

Our operating lease obligations include long-term lease payments for office space, vehicles, equipment related to exploration, development and production activities. We paid approximately $4.0 million and $1.9 million in operating lease payments for the three and six month periods ended June 30, 2025, respectively, and expect to pay approximately $17.7 million in operating lease payments through 2029. For further information on our operating lease obligations, see Note 11 of our consolidated financial statements.

Non-GAAP Financial Measures

Adjusted EBITDA

We include in this Quarterly Report the supplemental non-GAAP financial performance measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income, our most directly

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comparable financial measure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income before (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized loss (gain) on derivative instruments, (4) loss on debt extinguishment, (5) equity-based compensation expense and (6) (gain) loss on sale of assets, net.

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

Cash Available for Distribution

Cash available for distribution is not a measure of net income or net cash flow provided by or used in operating activities as determined by GAAP. Cash available for distribution is a supplemental non-GAAP financial performance measure used by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as net income adjusted for (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized loss (gain) on derivative instruments, (4) loss on debt extinguishment, (5) equity-based compensation expense, (6) (gain) loss on sale of assets, net, (7) cash interest expense, net, (8) development costs and (9) 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 measure most directly comparable to cash available for distribution is net income. Cash available for distribution should not be considered as an alternative to, or more meaningful than, net income.

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


	Three Months Ended June 30,				Six Months Ended June 30,
($ in thousands)	2025		2024		2025		2024
Net Income Reconciliation to Adjusted EBITDA:
Net income	$	89,661	$	39,516	$	105,547	$	81,218
Interest expense, net	12,097		25,880		29,514		50,952
Depreciation, depletion, amortization and accretion	67,098		68,061		130,683		135,531
Unrealized (gain) loss on derivative instruments	(48,551)		(124)		(6,211)		33,099
Loss on debt extinguishment	—		—		18,540		—
Equity-based compensation expense	2,103		2,300		4,215		3,482
Gain on sale of assets	(138)		(298)		(167)		(309)
Adjusted EBITDA	$	122,270	$	135,335	$	282,121	$	303,973
Net Income Reconciliation to Cash Available for Distribution:
Net income	$	89,661	$	39,516	$	105,547	$	81,218
Interest expense, net	12,097		25,880		29,514		50,952
Depreciation, depletion, amortization and accretion	67,098		68,061		130,683		135,531
Unrealized (gain) loss on derivative instruments	(48,551)		(124)		(6,211)		33,099
Loss on debt extinguishment	—		—		18,540		—
Equity-based compensation expense	2,103		2,300		4,215		3,482
Gain on sale of assets	(138)		(298)		(167)		(309)
Cash interest expense, net	(11,151)		(23,654)		(27,151)		(47,458)
Development costs	(63,503)		(45,562)		(115,558)		(125,987)
Change in accrued realized derivative settlements	(1,634)		1,586		1,146		4,188
Cash available for distribution	$	45,982	$	67,705	$	140,558	$	134,716

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are disclosed in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates” in our Annual Report for the year ended December 31, 2024. No modifications have been made during the six months ended June 30, 2025.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

Oil and gas revenue

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

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

Commodity derivative activities

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

Our hedging activities are intended to support oil and natural gas prices at targeted levels and manage our exposure to natural gas price volatility. Under swap contracts, the counterparty is required to make a payment to us for the difference between the swap price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the swap price. We are required to make a payment to the counterparty for the difference between the swap price and the settlement price if the swap price is below the settlement price. See Note 7 of our consolidated financial statements for further information on our open derivative positions and valuation as of June 30, 2025.

Counterparty and Customer Credit Risk

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of a contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. As of June 30, 2025, we had derivative instruments in place with five different counterparties. We believe our counterparties currently represent acceptable credit risks. We are not required to provide credit support or collateral to our counterparties under current contracts, nor are they required to provide credit support or collateral to us.

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

Interest Rate Risk

Variable rate debt

At June 30, 2025, we had $565.0 million of debt outstanding under the New Revolving Credit Facility. Borrowings outstanding under the New Revolving Credit Facility bore an interest rate of 8.1% as of June 30, 2025. Assuming no change in the amount outstanding, the impact on interest expense of a 1% (or 100 basis points) increase or decrease in the assumed weighted average interest rate on our variable interest debt would be approximately $5.7 million per year based on our borrowings outstanding at June 30, 2025.

Interest rate derivative activities

As of June 30, 2025, we did not have any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness, but we may enter into such derivative arrangements in the future. To the extent we enter into any such interest rate derivative arrangement, we would be subject to risk for financial loss.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2025. Based on such evaluation, such officers have concluded that, as of June 30, 2025, the Company’s disclosure controls and procedures are designed and effective to ensure that information required to be included in the Company’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that information required to be disclosed in the Company’s reports filed or submitted under the Exchange Act is accumulated and communicated to the Company’s management including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating the Company’s disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company’s controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the six-month period ended June 30, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The Company may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business including, but not limited to, title disputes, royalty disputes, contract claims, personal injury claims and employment claims. See Note 10 of the notes to our consolidated financial statements included in Item 1 of Part I of this report for information regarding our estimation and provision for potential losses related to litigation and regulatory proceedings.

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

The Company is not aware of any environmental claims existing as of June 30, 2025. There can be no assurance, however, that current regulatory requirements will not change or will not be interpreted or enforced differently, or past non-compliance with environmental laws and regulations or other issues will not be discovered on the Company’s oil and gas properties.

Item 1A. Risk Factors

There have been no material changes to the Company’s “Risk Factors” previously disclosed in Part I, Item 1A of our Annual Report for the year ended December 31, 2024. For a detailed discussion of the risks that affect our business, please refer to Part I, Item 1A “Risk Factors” in our Annual Report for the year ended December 31, 2024.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Unregistered Sale of Equity Securities

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

During the six months ended June 30, 2025, none of our directors or “officers” (as such term is defined in Rule 16(a)-1(f) under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading agreement” or “non-Rule 10b5-1 trading arrangement” (each as defined in Item 408(a) and (c) of Regulation S-K).

Item 6. Exhibits


Exhibit Number						Description
2.1^						Purchase and Sale Agreement, dated as of July 9, 2025 by and among Sabinal Energy Operating, LLC, Sabinal Resources, LLC and Sabinal CBP, LLC, as sellers, and Mach Natural Resources LP, as buyer (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on July 10, 2025).
2.2^						Membership Interest Purchase Agreement, dated as of July 9, 2025 by and among VEPU Inc. and Simlog Inc., as sellers, and Mach Natural Resources LP, as buyer (incorporated by reference to Exhibit 2.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on July 10, 2025).

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3.1						Certificate of Limited Partnership of Mach Natural Resources LP, effective as of May 26, 2023 (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 (File No. 333-274662) filed with the SEC on September 22, 2023)
3.2						Amended and Restated Agreement of Limited Partnership of Mach Natural Resources LP, dated as of October 27, 2023 (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on October 27, 2023)
3.3						Amended and Restated Limited Liability Company Agreement of Mach Natural Resources GP, LLC, dated as of October 27, 2023 (incorporated by reference to Exhibit 3.3 of the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on December 7, 2023)
3.4						Amendment No. 1 to the Amended and Restated Agreement of Limited Partnership of Mach Natural Resources LP, dated as of June 13, 2024 (incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed with the SEC on June 13, 2024)
10.1						Letter Agreement, dated as of July 8, 2025, by and among Mach Natural Resources LP, the lenders party thereto and Truist Bank, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on July 10, 2025).
31.1*						Certification of Chief Executive Officer pursuant to Exchange Act Rule 13a-14(a) and Rule 15d-14(a)
31.2*						Certification of Chief Financial Officer pursuant to Exchange Act Rule 13a-14(a) and Rule 15d-14(a)
32.1**						Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code
32.2**						Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code
101.INS*						Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because XBRL tags are embedded within the Inline XBRL document
101.SCH*						Inline XBRL Taxonomy Extension Schema Document
101.CAL*						Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*						Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*						Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*						Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*						Cover Page Interactive Data File (embedded within the Inline XBRL document)

____________

* Filed herewith.

** Furnished herewith.

^ Certain of the schedules and exhibits to the agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any

omitted schedule or exhibit will be furnished to the Securities and Exchange Commission upon request.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	Mach Natural Resources LP

	By:	Mach Natural Resources GP LLC, its general partner

Date: August 7, 2025	By:	/s/ Kevin R. White
	Name:	Kevin R. White
	Title:	Chief Financial Officer

MACH NATURAL RESOURCES LP 10-Q