10-Q

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2025

☐ 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: 001-39919

MONTAUK RENEWABLES, INC.

(Exact name of registrant as specified in its charter)


Delaware	85-3189583
(State or Other Jurisdiction of Incorporation or Organization)	(IRS Employer Identification No.)

5313 Campbells Run Road, Suite 200 Pittsburgh, Pennsylvania	15205
(Address of Principal Executive Offices)	(Zip Code)

(412) 747-8700

(Registrant’s Telephone Number, Including Area Code)

N/A

(Former name, former address and former fiscal year, if changed since last report)

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 Stock, par value $0.01 per share

     MNTK

     The Nasdaq Capital Market

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 ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐

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


Large accelerated filer	☐	Accelerated filer	☒

Non-accelerated filer	☐	Smaller reporting company	☐

		Emerging growth company	☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

The number of outstanding shares of the registrant’s common stock on May 2, 2025 was 142,434,501 shares.

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TABLE OF CONTENTS


		Page

PART I FINANCIAL INFORMATION		6

ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)	6

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	27

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	44

ITEM 4.	CONTROLS AND PROCEDURES	44

PART II OTHER INFORMATION		45

ITEM 1.	LEGAL PROCEEDINGS	45

ITEM 1A.	RISK FACTORS	45

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	45

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	45

ITEM 4.	MINE SAFETY DISCLOSURES	45

ITEM 5.	OTHER INFORMATION	45

ITEM 6.	EXHIBITS	46

SIGNATURES		47

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Glossary of Key Terms

This Quarterly Report on Form 10-Q uses several terms of art that are specific to our industry and business. For the convenience of the reader, a glossary of such terms is provided here. Unless we otherwise indicate, or unless the context requires otherwise, any references in this Quarterly Report on Form 10-Q to:

•

“ADG” refers to anaerobic digested gas.

•

“CARB” refers to the California Air Resource Board.

•

“CNG” refers to compressed natural gas.

•

“CI” refers to carbon intensity.

•

“D3” refers to cellulosic biofuel with a 60% GHG reduction requirement.

•

“EPA” refers to the U.S. Environmental Protection Agency.

•

“Environmental Attributes” refer to federal, state and local government incentives in the United States, provided in the form of RINs, RECs, LCFS credits, rebates, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects, that promote the use of renewable energy.

•

“FERC” refers to the U.S. Federal Energy Regulatory Commission.

•

“GHG” refers to greenhouse gases.

•

“JSE” refers to the Johannesburg Stock Exchange.

•

“LCFS” refers to Low Carbon Fuel Standard.

•

“LFG” refers to landfill gas.

•

“MMBtu” refers to Metric Million British Thermal Unit.

•

“PPAs” refers to power purchase agreements.

•

“RECs” refers to Renewable Energy Credits.

•

“Renewable Electricity” or "REG" refers to electricity generated from renewable sources.

•

“RFS” refers to the EPA’s Renewable Fuel Standard.

•

“RINs” refers to Renewable Identification Numbers.

•

“RNG” refers to renewable natural gas.

•

“RVOs” refers to renewable volume obligations.

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Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of U.S. federal securities laws that involve substantial risks and uncertainties. All statements other than statements of historical or current fact included in this report are forward-looking statements. Forward-looking statements refer to our current expectations and projections relating to our financial condition, results of operations, plans, objectives, strategies, future performance, and business. Forward-looking statements may include words such as “anticipate,” “assume,” “believe,” “can have,” “contemplate,” “continue,” “strive,” “aim,” “could,” “design,” “due,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “likely,” “may,” “might,” “objective,” “plan,” “predict,” “project,” “potential,” “seek,” “should,” “target,” “will,” “would,” and other words and terms of similar meaning in connection with any discussion of the timing or nature of future operational performance or other events. For example, all statements we make relating to our future results of operations, financial condition, expectations and plans, including those related to the Montauk Ag project in North Carolina, the Second Apex RNG Facility, the Blue Granite RNG Facility, the Bowerman RNG Facility, the delivery of biogenic carbon dioxide volumes to European Energy, the Emvolon collaboration and pilot project, the Tulsa facility project, the resolution of gas collection issues at the McCarty facility, the delays and cancellations of landfill host wellfield expansion projects, the mitigation of wellfield extraction environmental factors at the Rumpke and Apex facilities, how we may monetize RNG production and weather-related anomalies are forward-looking statements. All forward-looking statements are subject to risks and uncertainties that may cause actual results to differ materially from those that we expect and, therefore, you should not unduly rely on such statements. The risks and uncertainties that could cause those actual results to differ materially from those expressed or implied by these forward-looking statements include but are not limited to:

•

our ability to develop and operate new renewable energy projects, including with livestock farms, and related challenges associated with new projects, such as identifying suitable locations and potential delays in acquisition financing, construction, and development;

•

reduction or elimination of government economic incentives to the renewable energy market, whether as a result of the new presidential administration or otherwise;

•

the inability to complete strategic development opportunities;

•

widespread manmade, natural and other disasters (including severe weather events), health emergencies, dislocations, geopolitical instabilities or events, terrorist activities, international hostilities, government shutdowns, political elections, security breaches, cyberattacks or other extraordinary events that impact general economic conditions, financial markets and/or our business and operating results;

•

taxes, tariffs, duties or other assessments on equipment necessary to generate or deliver renewable energy or continued inflation could raise our operating costs or increase the construction costs of our existing or new projects;

•

rising interest rates could increase the borrowing costs of future indebtedness;

•

the failure to attract and retain qualified personnel or a possible increased reliance on third-party contractors as a result, and the potential unenforceability of non-compete clauses with our employees;

•

the length of development and optimization cycles for new projects, including the design and construction processes for our renewable energy projects;

•

dependence on third parties for the manufacture of products and services and our landfill operations;

•

the quantity, quality and consistency of our feedstock volumes from both landfill and livestock farm operations;

•

reliance on interconnections with and access to electric utility distribution and transmission facilities and gas transportation pipelines for our Renewable Natural Gas and Renewable Electricity Generation segments;

•

our ability to renew pathway provider sharing arrangements at historical counterparty share percentages;

•

our projects not producing expected levels of output;

•

potential benefits associated with the combustion-based oxygen removal condensate neutralization technology;

•

concentration of revenues from a small number of customers and projects;

•

our outstanding indebtedness and restrictions under our credit facility;

•

our ability to extend our fuel supply agreements prior to expiration;

•

our ability to meet milestone requirements under our PPAs;

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•

existing regulations and changes to regulations and policies that effect our operations, whether as a result of the new presidential administration or otherwise;

•

expected impacts of the Production Tax Credit and other tax credit benefits under the Inflation Reduction Act of 2022;

•

decline in public acceptance and support of renewable energy development and projects;

•

our expectations regarding Environmental Attribute volume requirements and prices and commodity prices;

•

our expectations regarding the period during which we qualify as an emerging growth company under the Jumpstart Our Business Startups Act (“JOBS Act”);

•

our expectations regarding future capital expenditures, including for the maintenance of facilities;

•

our expectations regarding the use of net operating losses before expiration;

•

our expectations regarding more attractive CI scores by regulatory agencies for our livestock farm projects;

•

market volatility and fluctuations in commodity prices and the market prices of Environmental Attributes and the impact of any related hedging activity;

•

regulatory changes in federal, state and international environmental attribute programs and the need to obtain and maintain regulatory permits, approvals, and consents;

•

profitability of our planned livestock farm projects;

•

sustained demand for renewable energy;

•

potential liabilities from contamination and environmental conditions;

•

potential exposure to costs and liabilities due to extensive environmental, health and safety laws;

•

impacts of climate change, extreme and changing weather patterns and conditions and natural disasters;

•

failure of our information technology and data security systems;

•

increased competition in our markets;

•

continuing to keep up with technology innovations;

•

concentrated stock ownership by a few stockholders and related control over the outcome of all matters subject to a stockholder vote; and

•

other risks and uncertainties detailed in the section titled “Risk Factors” in our latest Annual Report on Form 10-K and as otherwise disclosed in our filings with the SEC.

We make many of our forward-looking statements based on our operating budgets and forecasts, which are based upon detailed assumptions. While we believe that our assumptions are reasonable, we caution that it is very difficult to predict the impact of known factors, and it is impossible for us to anticipate all factors that could affect our actual results.

All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements as well as others made in our other Securities and Exchange Commission (“SEC”) filings and public communications. You should evaluate all forward-looking statements made by us in the context of these risks and uncertainties. See the “Risk Factors” section in our latest Annual Report on Form 10-K and our other filings with the SEC.

We caution you that the risks and uncertainties identified by us may not be all of the factors that are important to you. Furthermore, the forward-looking statements included in this report are made only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statement as a result of new information, future events, or otherwise, except as required by law.

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PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS


	Page
Montauk Renewables, Inc.
Unaudited condensed consolidated financial statements
Unaudited consolidated balance sheets	7
Unaudited consolidated statements of operations	8
Unaudited consolidated statements of stockholders’ equity	9
Unaudited consolidated statements of cash flows	10
Condensed notes to unaudited consolidated financial statements	12

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MONTAUK RENEWABLES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data):



	as of March 31,			as of December 31,
ASSETS	2025			2024
Current assets:
Cash and cash equivalents	$	40,111		$	45,621
Accounts and other receivables		8,491			8,172
Current restricted cash		8			8
Income tax receivable		344			41
Current portion of derivative instruments		401			471
Prepaid insurance and other current assets		2,824			2,911
Total current assets	$	52,179		$	57,224
Non-current restricted cash	$	375		$	375
Property, plant and equipment, net		259,678			252,288
Goodwill and intangible assets, net		17,881			18,113
Deferred tax assets		1,605			1,272
Non-current portion of derivative instruments		154			298
Operating lease right-of-use assets		7,095			7,064
Finance lease right-of-use assets		93			110
Other assets		15,166			12,271
Total assets	$	354,226		$	349,015

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	16,411		$	8,856
Accrued liabilities		10,232			10,069
Related party payable	—				625
Current portion of operating lease liability		2,378			2,049
Current portion of finance lease liability		76			76
Current portion of long-term debt		11,857			11,853
Total current liabilities	$	40,954		$	33,528
Long-term debt, less current portion	$	40,796		$	43,763
Non-current portion of operating lease liability		4,817			5,138
Non-current portion of finance lease liability		19			36
Asset retirement obligations		6,456			6,338
Other liabilities		2,997			2,795

Total liabilities	$	96,039		$	91,598

Commitments and contingencies (Note 20)

STOCKHOLDERS’ EQUITY

Common stock, $0.01 par value, authorized 690,000,000 shares; 143,792,811 shares issued at March 31, 2025 and December 31, 2024; 142,711,797 shares outstanding at March 31, 2025 and December 31, 2024	$	1,426		$	1,426
Treasury stock, at cost, 2,308,524 shares March 31, 2025 and December 31, 2024		(21,262	)		(21,262	)
Additional paid-in capital		223,139			221,905
Retained earnings		54,884			55,348
Total stockholders' equity	$	258,187		$	257,417
Total liabilities and stockholders' equity	$	354,226		$	349,015

The accompanying notes to the unaudited condensed consolidated financial statements are an integral part of these statements.

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MONTAUK RENEWABLES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except for share and per share data):


	Three Months Ended March 31,
	2025			2024
Total operating revenues	$	42,603		$	38,787

Operating expenses:
Operating and maintenance expenses		17,557			14,451
General and administrative expenses		8,754			9,427
Royalties, transportation, gathering and production fuel		7,571			6,518
Depreciation, depletion and amortization		6,264			5,434
Impairment loss		2,047			528
Transaction costs		—			61
Total operating expenses	$	42,193		$	36,419
Operating income	$	410		$	2,368

Other expenses (income):
Interest expense	$	1,243		$	1,165
Other income		(52	)		(1,060	)
Total other expenses	$	1,191		$	105
(Loss) income before income taxes	$	(781	)	$	2,263

Income tax (benefit) expense		(317	)		413
Net (loss) income	$	(464	)	$	1,850

(Loss) income per share:
Basic	$	(0.00	)	$	0.01
Diluted	$	(0.00	)	$	0.01

Weighted-average common shares outstanding:
Basic		142,711,797			141,986,189
Diluted		142,711,797			142,369,219

The accompanying notes to the unaudited condensed consolidated financial statements are an integral part of these statements.

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MONTAUK RENEWABLES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

(in thousands, except share data):


	Common stock				Treasury stock
	Shares		Amount		Shares		Amount			Additional paid-in capital			Retained earnings			Total equity
Balance at December 31, 2023		141,986,189	$	1,420		984,762	$	(11,173	)	$	214,378		$	45,614		$	250,239
Net income		—		—		—		—			—			1,850			1,850
Stock-based compensation		—		—		—		—			2,241			—			2,241
Balance at March 31, 2024		141,986,189	$	1,420		984,762	$	(11,173	)	$	216,619		$	47,464		$	254,330

Balance at December 31, 2024		142,711,797	$	1,426		2,308,524	$	(21,262	)	$	221,905		$	55,348		$	257,417
Consolidation of VIE		—		—		—		—			(40	)		—			(40	)
Net loss		—		—		—		—			—			(464	)		(464	)
Stock-based compensation		—		—		—		—			1,274			—			1,274
Balance at March 31, 2025		142,711,797	$	1,426		2,308,524	$	(21,262	)	$	223,139		$	54,884		$	258,187

The accompanying notes to the unaudited condensed consolidated financial statements are an integral part of these statements.

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MONTAUK RENEWABLES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands):



	Three Months Ended March 31,
	2025			2024
Cash flows from operating activities:
Net (loss) income	$	(464	)	$	1,850
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		6,264			5,434
(Benefit) provision for deferred income taxes		(333	)		249
Stock-based compensation		1,274			2,241
Derivative mark-to-market adjustments and settlements		214			(91	)
Net loss on sale of assets		15			22
Decrease in earn-out liability		(425	)		(849	)
Accretion of asset retirement obligations		118			108
Liabilities associated with properties sold		—			(225	)
Amortization of debt issuance costs		97			90
Impairment loss		2,047			528
Changes in operating assets and liabilities:
Accounts receivable		(319	)		3,083
Royalty offset long term receivable		(739	)		(1,600	)
Critical spare inventory		(215	)		209
Income tax payables		(303	)		(411	)
Accounts payable and Accrued liabilities		2,213			3,468
Other		(304	)		186
Net cash provided by operating activities	$	9,140		$	14,292
Cash flows from investing activities:
Capital expenditures	$	(11,632	)	$	(21,986	)
Asset acquisition		—			(820	)
Cash collateral deposits		—			20
Net cash used in investing activities	$	(11,632	)	$	(22,786	)
Cash flows from financing activities:
Repayments of long-term debt	$	(3,000	)	$	(2,000	)
Finance lease payments		(18	)		(20	)
Net cash used in financing activities	$	(3,018	)	$	(2,020	)
Net decrease in cash and cash equivalents and restricted cash	$	(5,510	)	$	(10,514	)
Cash and cash equivalents and restricted cash at beginning of period	$	46,004		$	74,242
Cash and cash equivalents and restricted cash at end of period	$	40,494		$	63,728
Reconciliation of cash, cash equivalents, and restricted cash at end of period:
Cash and cash equivalents	$	40,111		$	63,277
Restricted cash and cash equivalents - current		8			8
Restricted cash and cash equivalents - non-current		375			443
	$	40,494		$	63,728

The accompanying notes to the unaudited condensed consolidated financial statements are an integral part of these statements.

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	Three Months Ended March 31,
	2025		2024
Supplemental cash flow information:
Cash paid for interest	$	1,055	$	1,237
Cash paid for income taxes		319		574
Accrual for purchase of property, plant and equipment included in accounts payable and accrued liabilities		8,534		7,492

Cash and cash equivalents include highly liquid investments with maturity dates of three months or less from the date of purchase and are recorded at cost. The Company may hold cash in excess of federally insured limits. Restricted cash is classified as current or non-current based on the terms of the underlying agreements and represents cash held as deposits, cash held in escrow and cash collateral for financial letters of credit.

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MONTAUK RENEWABLES, INC.

CONDENSED NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands, except per-share amounts)

NOTE 1 – DESCRIPTION OF BUSINESS

Operations and organization

Montauk Renewables’ Business

Montauk Renewables, Inc. (the “Company” or “Montauk Renewables”) is a renewable energy company specializing in the management, recovery and conversion of biogas into Renewable Natural Gas (“RNG”). The Company captures methane, preventing it from being released into the atmosphere, and converts it into either RNG or electrical power for the electrical grid (“Renewable Electricity”). The Company, headquartered in Pittsburgh, Pennsylvania, has more than 30 years of experience in the development, operation and management of landfill methane-fueled renewable energy projects. The Company has current operations at 13 operating projects located in California, Idaho, Ohio, Oklahoma, Pennsylvania, North Carolina and Texas. The Company sells RNG and Renewable Electricity, taking advantage of Environmental Attribute premiums available under federal and state policies that incentivize their use.

Two of the Company’s key revenue drivers are sales of captured gas and sales of Renewable Identification Numbers (“RINs”) to fuel blenders. The Renewable Fuel Standard (“RFS”) is an Environmental Protection Agency (“EPA”) administered federal law that requires transportation fuel to contain a minimum volume of renewable fuel. RNG derived from landfill methane, agricultural digesters and wastewater treatment facilities used as a vehicle fuel qualifies as a D3 (cellulosic biofuel with a 60% greenhouse gas reduction requirement) RIN. The RINs are compliance units for fuel blenders that were created by the RFS program in order to reduce greenhouse gases and imported petroleum into the United States.

An additional program utilized by the Company is the Low Carbon Fuel Standard (“LCFS”). This is state specific and is designed to stimulate the use of low-carbon fuels. To the extent that RNG from the Company’s facilities is used as a transportation fuel in states that have adopted an LCFS program, it is eligible to receive an Environmental Attribute additional to the RIN value under the federal RFS.

Another key revenue driver is the sale of captured electricity and the associated environmental premiums related to renewable sales. The Company’s electric facilities are designed to conform to and monetize various state renewable portfolio standards requiring a percentage of the electricity produced in that state to come from a renewable resource. Such premiums are in the form of Renewable Energy Credits (“RECs”). The Company’s largest electric facility, located in California, receives revenue for the monetization of RECs as a part of a purchase power agreement.

Collectively, the Company benefits from federal and state government incentives in the United States, provided in the form of RINs, RECs, LCFS credits, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects, that promote the use of renewable energy, as Environmental Attributes

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions of the SEC on Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and disclosures required by GAAP for complete financial statements. In the opinion of management, the unaudited condensed consolidated financial statements include all adjustments necessary, which are of a normal and recurring nature, for the fair presentation of the Company’s financial position and of the results of operations and cash flows for the periods presented. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2024 included in the Company’s Annual Report on Form 10-K filed with the SEC on March 14, 2025 (the “2024 Annual Report”). The results of operations for the three months ended March 31, 2025 in this report are not necessarily indicative of the results that may be expected for any other interim period or for the full year. The balance sheet at December 31, 2024, has been derived from the audited financial statements as of that date. For further information, refer to the Company’s audited financial statements and notes thereto included for the year ended December 31, 2024 in the 2024 Annual Report.

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Principles of Consolidation

The historical consolidated financial information included reflects the historical results of operations and financial position of Montauk USA through January 4, 2021 when MNK sold the membership interest of Montauk USA. The consolidated financial statements of Montauk USA became the Company’s historical financial statements following the IPO. Certain historical financial information included relates to periods prior to the Reorganization Transactions. On December 31, 2024, the Company re-assessed its determination of the primary beneficiary of the Variable Interest Entity ("VIE") MNK under the guidance in ASC 810, Consolidation. Refer to Note 16 – Related Parties for further information. All intercompany balances and transactions have been eliminated in consolidation.

The Company utilizes the equity method of accounting for companies where its ownership is greater than 50% and significant but controlling interest does not exist.

Segment Reporting

The Company reports segment information in three segments: RNG, Renewable Electricity Generation and Corporate. This is consistent with the internal reporting provided to the chief operating decision maker who evaluates operating results and performance. The aforementioned business services and offerings described in Note 1 are grouped and defined by management as two distinct operating segments: RNG and Renewable Electricity Generation. Below is a description of the Company’s operating segments and other activities.

The RNG segment represents the sale of gas sold at fixed-price contracts, counterparty share RNG volumes and applicable Environmental Attributes. This business unit represents the majority of the revenues generated by the Company. The Renewable Electricity Generation segment represents the sale of captured electricity and applicable Environmental Attributes. Corporate & Other relates to additional discrete financial information for the corporate function. It is primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering and other operations functions not otherwise allocated to a segment. As such, the corporate entity is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation to the Company’s consolidated financial statements.

Use of Estimates

The preparation of financial statements, in conformity with accounting principles generally accepted in the United States (“GAAP”), requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Recently Adopted Accounting Standards

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segments. The amendments in 2023-07 aim to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. ASU 2023-07 is effective for the Company's Annual Report on Form 10-K for the year ended December 31, 2024, and subsequent interim periods, with early adoption permitted. The amendments should be applied retrospectively to all prior periods presented in the financial statements. The Company has adopted the standard and the enhanced expense disclosures can be found in Note 17.

Recently Issued Accounting Standards

In November 2024, the FASB issued ASU 2024-03, Income Statement — Reporting Comprehensive Income — Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. This ASU requires public business entities to disclose, on an annual and interim basis, disaggregated information about certain income statement expense line items. The ASU also requires disclosure of the total amount of selling expenses recognized in continuing operations on an annual and interim basis and disclosure of a public business entity’s definition of selling expenses on an annual basis (or in interim reporting periods if the definition is changed). Public business entities are required to apply the guidance prospectively but are permitted to apply it retrospectively. The ASU is effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments in 2023-09 aim to enhance the transparency and decision usefulness of income tax disclosures. ASU 2023-09 is effective for the Company's Annual Report on Form 10-K for the year ended December 31, 2025, with early adoption permitted. Other than enhanced disclosures, the Company does not expect a material impact from the adoption of this standard on its consolidated financial statements.

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NOTE 3 – ASSET IMPAIRMENT

The Company recorded an impairment loss of $2,047 and $528 for the three months ended March 31, 2025 and 2024, respectively. In 2025, $1,983 was impaired for costs related to a development project RNG interconnection for which the local utility is no longer accepting RNG into its distribution system. All associated costs related to the interconnection were impaired. The remaining 2025 impairments of $64 were for specifically identified assets deemed obsolete or non-operable. $54 were impaired within the RNG segment and the remaining $10 were impaired within the REG segment. 2024 impairments included a REG site in which the Company entered into a bill of sale, assignment and assumption agreement to sell its rights to the existing fuel supply agreement and property back to the site host in advance of the fuel supply agreement termination date and received $1,000 in proceeds. The effective date of the sale, assignment and assumption agreement was October 1, 2024. The Company elected to cease operations prior to the assignment date and consequently the remaining book value of long lived assets and intangibles were impaired for $312. The remaining $216 impairment was for various RNG equipment that was deemed obsolete or inoperable for current operations.

NOTE 4 – REVENUES FROM CONTRACTS WITH CUSTOMERS

The majority of the Company’s revenues are comprised of renewable energy and related Environmental Attribute sales provided under short, medium and long term contracts with its customers. All revenue is recognized when (or as) the Company satisfies its performance obligation(s) under the contract (either implicit or explicit) by transferring the promised product or service to its customer either when (or as) its customer obtains control of the product or service. A performance obligation is a promise in a contract to transfer a distinct product or service to a customer. A contract’s transaction price is allocated to each distinct performance obligation. The Company allocates the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract. The Company's typical invoicing terms are payment due within 30 days.

Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring its products or services. As such, revenue is recorded net of allowances and customer discounts as well as net of transportation and gathering costs incurred by the customer following the transfer of control of the commodities sold. To the extent applicable, sales, value add and other taxes collected from customers and remitted to governmental authorities are accounted for on a net (excluded from revenues) basis.

The Company’s performance obligations related to the sale of renewable energy (i.e. RNG and Renewable Electricity) are generally satisfied over time. Revenue related to the sale of renewable energy is generally recognized over time using an output based upon the product quantity delivered to the customer. This measure is used to best depict the Company’s performance to date under the terms of the contract. Revenue from products transferred to customers over time accounted for approximately 36% and 27% of revenue for the three months ended March 31, 2025 and 2024, respectively.

The nature of the Company’s long-term contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of the Company’s influence as the variable consideration is dictated by the market. Therefore, the variable consideration associated with the long-term contracts is considered fully constrained.

The Company’s performance obligations related to the sale of Environmental Attributes are generally satisfied at a point in time and were approximately 64%, and 73% of revenue for the three months ended March 31, 2025 and 2024, respectively. The Company recognizes Environmental Attribute revenue at the point in time in which the customer obtains control of the Environmental Attributes, which is generally when the title of the Environmental Attribute passes to the customer upon delivery. In limited cases, title does not transfer to the customer and revenue is not recognized until the customer has accepted the Environmental Attributes. The Company’s performance obligations under its counterparty sharing agreements are generally satisfied at a point in time when the earnings process is completed by the counterparty. Counterparty sharing arrangement revenues were approximately 1.2% and 0.1% of revenue for the three months ended March 31, 2025 and 2024, respectively.

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The following tables display the Company’s disaggregated revenue by major source based on product type and timing of transfer of goods and services for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31, 2025
	Goods transferred at a point in time		Goods transferred over time		Total
Major goods/Service line:
Natural gas commodity	$	498	$	12,749	$	13,247
Natural gas environmental attributes		24,991		—		24,991
Electric commodity		—		2,657		2,657
Electric environmental attributes		1,708		—		1,708
	$	27,197	$	15,406	$	42,603
Operating segment:
RNG	$	25,489	$	12,749	$	38,238
REG		1,708		2,657		4,365
	$	27,197	$	15,406	$	42,603


	Three Months Ended March 31, 2024
	Goods transferred at a point in time		Goods transferred over time		Total
Major goods/Service line:
Natural gas commodity	$	19	$	7,516	$	7,535
Natural gas environmental attributes		26,332		—		26,332
Electric commodity		—		3,031		3,031
Electric environmental attributes		1,889		—		1,889
	$	28,240	$	10,547	$	38,787
Operating segment:
RNG	$	26,351	$	7,516	$	33,867
REG		1,889		3,031		4,920
	$	28,240	$	10,547	$	38,787

Practical expedients and remaining performance obligations

The Company recognizes the sale of natural gas and electric commodities using the right to invoice practical expedient. The Company determined that the revenues recognized as of period end correspond directly with the value transferred to customers and the Company's satisfaction of the performance obligations to date. Furthermore, with the application of the right to invoice practical expedient and in consideration that contracts related to future environmental attributes sales do not exceed one year, there are no remaining unsatisfied or partially satisfied performance obligations as of March 31, 2025.

NOTE 5 – ACCOUNTS AND OTHER RECEIVABLES

The Company extends credit based upon an evaluation of the customer’s financial condition and, while collateral is not required, the Company periodically receives surety bonds that guarantee payment. Credit terms are consistent with industry standards and practices. Reserves for uncollectible accounts, if any, are recorded as part of general and administrative expenses in the consolidated statements of operations. No reserve expense was recorded for the three months ended March 31, 2025 and 2024.

Accounts and other receivables consist of the following as of March 31, 2025, December 31, 2024 and 2023:


	March 31, 2025		December 31, 2024		December 31, 2023
Accounts receivables	$	8,048	$	7,869	$	12,557
Other receivables		438		294		148
Reimbursable expenses		5		9		47
Accounts and other receivables, net	$	8,491	$	8,172	$	12,752

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NOTE 6 – PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant and equipment consist of the following as of March 31, 2025 and December 31, 2024:


	March 31, 2025			December 31, 2024
Land	$	1,568		$	1,568
Buildings and improvements		36,427			36,434
Machinery and equipment		277,828			275,692
Gas mineral rights		35,526			35,526
Construction work in progress		106,442			95,551
Total	$	457,791		$	444,771
Less: Accumulated depreciation and amortization		(198,113	)		(192,483	)
Property, plant & equipment, net	$	259,678		$	252,288

Depreciation expense for Property, plant and equipment was $5,908 and $5,081 for the three months ended March 31, 2025 and 2024, respectively. Depletion expense for gas mineral rights was $90 and $91 for the three months ended March 31, 2025 and 2024, respectively.

Construction work in progress consists of RNG and REG capital expenditures on developmental projects and improvements to existing sites. Projects, on average, last between 18 to 36 months, and when completed for their intended use, costs are placed in service and begin depreciating

NOTE 7 – GOODWILL AND INTANGIBLE ASSETS, NET

Goodwill and intangible assets consist of the following as of March 31, 2025 and December 31, 2024:


	March 31, 2025		December 31, 2024
Goodwill	$	60	$	60
Intangible assets with indefinite lives:
Land use rights		230		230
Total intangible assets with indefinite lives:	$	230	$	230
Intangible assets with finite lives:
Interconnection, net of accumulated amortization of $4,782 and $4,593	$	14,443	$	14,614
Customer contracts, net of accumulated amortization of $17,536 and $17,476		3,148		3,209
Total intangible assets with finite lives:	$	17,591	$	17,823
Total Goodwill and Intangible assets	$	17,881	$	18,113

As of March 31, 2025, the weighted average remaining useful lives for both customer contracts and interconnections were 13 years. Amortization expense was $248 and $243 for the three months ended March 31, 2025 and 2024, respectively.

NOTE 8 – ASSET RETIREMENT OBLIGATIONS

The Company accounts for asset retirement obligations by recording the fair value of the liability in the period in which it is incurred. The Company estimates the fair value of asset retirement obligations by calculating the estimated present value of the cost to retire the asset. Factors that are considered when determining the present value of the cost to retire the asset include future inflation and discount rates, along with estimates date(s) of retiring the asset. Additionally, changes in legal, regulatory, environmental, and political environments can affect the fair value of the obligations. As such, asset retirement obligations are considered a level 3 financial instrument.

The $218 change in estimates for the year ended December 31, 2024 was due to RNG fuel supply agreement extensions and an RNG project that necessitated reassessment. The $225 reduction in the liability was due to an REG site sale as described in Note 3.

The following table summarizes the activity associated with asset retirement obligations of the Company as of March 31, 2025 and December 31, 2024:

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	Three Months Ended March 31,		Year Ended December 31,
	2025		2024
Asset retirement obligations—beginning of period	$	6,338	$	5,900
Accretion expense		118		445
Changes in estimate	—			218
Liabilities associated with properties sold	—			(225	)
Asset retirement obligations—end of period	$	6,456	$	6,338

NOTE 9 – DERIVATIVE INSTRUMENTS

To mitigate market risk associated with fluctuations in interest rates, the Company utilizes swap contracts under a board-approved program. The Company does not apply hedge accounting to any of its derivative instruments, and all realized and unrealized gains and losses from changes in derivative values are recognized in earnings each period. As a result of the economic hedging strategies employed, the Company had the following cash gains/losses and non-cash gains/losses in the Consolidated Statements of Operations the three months ended March 31, 2025 and 2024:


		Three Months Ended March 31,
Derivative Instrument	Location	2025			2024
Interest rate swaps	Interest expense		(214	)		91
Net (loss) gain		$	(214	)	$	91

NOTE 10 – FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company’s assets and liabilities that are measured at fair value on a recurring basis include the following as of March 31, 2025 and December 31, 2024, set forth by level, within the fair value hierarchy:


	March 31, 2025
	Level 1		Level 2		Level 3			Total
Interest rate swap derivative asset	$	—	$	555	$	—		$	555
Asset retirement obligations		—		—		(6,456	)		(6,456	)
Pico earn-out liability		—		—		(2,981	)		(2,981	)
	$	—	$	555	$	(9,437	)	$	(8,882	)


	December 31, 2024
	Level 1		Level 2		Level 3			Total
Interest rate swap derivative asset	$	—	$	769	$	—		$	769
Asset retirement obligations		—		—		(6,338	)		(6,338	)
Pico earn-out liability		—		—		(3,406	)		(3,406	)
	$	—	$	769	$	(9,744	)	$	(8,975	)

The three levels of the fair value hierarchy under authoritative guidance are described as follows:

Level 1: Observable inputs that reflect unadjusted quoted market prices in active markets for identical assets or liabilities.

Level 2: Inputs are market data, other than Level 1, that are observable either directly or indirectly. Level 2 inputs include quoted market prices for similar assets or liabilities, quoted market prices for similar assets or liabilities in inactive markets and other observable information that can be corroborated by market data.

Level 3: Unobservable inputs that are not corroborated by market data, but significant to the fair value measurement.

A summary of changes in the fair value of the Company’s Level 3 instrument, attributable to asset retirement obligations, for the three months ended March 31, 2025 and the year ended December 31, 2024 is included in Note 8. The Company’s earn-out fair value liability at its Idaho agricultural digester site is determined by calculating the estimated present value of the future obligation. The present value is assessed quarterly and is based on macro-economic factors such as inflation and risk free US Treasury rates. Company specific estimates utilized include current and future interest rates, digester inlet gas flow and projected EBITDA. A weighted average probability approach is utilized for the variables discussed above. The undiscounted maximum payout of the earn-out ranges between 5% and 20% of EBITDA based on average inlet gas production ranging from 641 standard cubic feet per minute ("scfm") to greater

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than 944 scfm for each semiannual period in the remaining term, as defined in the underlying agreement. The contractual term ends in 2038. The earn-out is classified as a Level 3 financial instrument and changes in the balance are recorded in Accrued liabilities and Other liabilities within the Consolidated Balance Sheets and in Royalties, transportation, gathering and production fuel within the Consolidated Statements of Operations. Interest rate swap derivatives are classified as Level 2 financial instruments and are valued utilizing Secured Overnight Financing Rates. In addition, certain assets are measured at fair value on a non-recurring basis when an indicator of impairment is identified and the assets’ fair values are determined to be less than its carrying value. See Note 3 for additional information.

There were no transfer of assets or liabilities between Levels 1, 2 or 3 of the fair value hierarchy as of March 31, 2025 and December 31, 2024.

NOTE 11 – ACCRUED LIABILITIES

The Company’s accrued liabilities consist of the following as of March 31, 2025 and December 31, 2024:


	March 31, 2025		December 31, 2024
Accrued expenses	$	3,719	$	2,701
Payroll and related benefits		2,260		3,401
Royalty		1,316		1,266
Utility		1,993		1,655
Accrued interest		840		962
Other		104		84
Accrued liabilities	$	10,232	$	10,069

NOTE 12 – DEBT

The Company’s debt consists of the following as of March 31, 2025 and December 31, 2024:


	March 31, 2025			December 31, 2024
Term loans	$	53,000		$	56,000
Less: current principal maturities		(12,000	)		(12,000	)
Less: debt issuance costs (on long-term debt)		(204	)		(237	)
Long-term debt	$	40,796		$	43,763
Current portion of long-term debt		11,857			11,853
Total debt	$	52,653		$	55,616

Amended Credit Agreement

On December 12, 2018, Montauk Energy Holdings LLC (“MEH”) entered into the Second Amended and Restated Revolving Credit and Term Loan Agreement (as amended, “Credit Agreement”), by and among MEH, the financial institutions from time to time party thereto as lenders and Comerica Bank, as the administrative agent, sole lead arranger and sole bookrunner (“Comerica”). The Credit Agreement (i) amended and restated in its entirety MEH’s prior revolving credit and term loan facility, dated as of August 4, 2017, as amended, with Comerica and certain other financial institutions and (ii) replaced in its entirety the prior credit agreement, dated as of August 4, 2017, as amended, between Comerica and Bowerman Power LFG, LLC, a wholly-owned subsidiary of MEH.

On March 21, 2019, MEH entered into the first amendment to the Credit Agreement (the “First Amendment”), which clarified a variety of terms, definitions and calculations in the Credit Agreement. The Credit Agreement requires the Company to maintain customary affirmative and negative covenants, including certain financial covenants, which are measured at the end of each fiscal quarter.

On September 12, 2019, the Company entered into the second amendment to the Credit Agreement (the "Second Amendment"). Among other matters, the Second Amendment redefined the Fixed Charge Coverage Ratio (as defined in the Credit Agreement), reduced the commitments under the revolving credit facility to $80,000, redefined the Total Leverage Ratio (as defined in the Credit Agreement) and eliminated the RIN Floor (as defined in the Second Amendment) as an Event of Default. In connection with the Second Amendment, the Company paid down the outstanding term loan by $38,250 and the resulting quarterly principal installments were reduced to $2,500.

On January 4, 2021, the Company, Montauk Holdings Limited (“MNK”) and Montauk Holdings USA, LLC (a direct wholly-owned subsidiary of MNK at the time, “Montauk USA”) entered into a series of transactions, including an equity exchange and a distribution collectively referred to as the “Reorganization Transactions,” that resulted in the Company owning all of the assets and

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entities (other than Montauk USA) previously owned by Montauk USA. In connection with the completion of the Reorganization Transactions and the IPO, the Company entered into the third amendment to the Credit Agreement (the “Third Amendment”). This amendment permitted the change of control provisions, as defined in the underlying agreement, to permit the Reorganization Transactions and the IPO to be completed.

On December 21, 2021, MEH entered into the Fourth Amendment to the Second Amended and Restated Revolving Credit and Term Loan Agreement. The current credit agreement, which is secured by a lien on substantially all assets of the Company and certain of its subsidiaries, provides for a $80,000 term loan and a $120,000 revolving credit facility. The term loan amortizes in quarterly installments of $2,000 through 2024, then increases to $3,000 from 2025 to 2026 with a final payment of $32,000 in late 2026.

The Company accounted for the Fourth amendment as both a debt modification and debt extinguishment in accordance with ASC 470, Debt (“ASC 470”). In connection with the Credit Agreement, the Company paid $2,027 in fees. Of this amount, $326 was expensed and $1,701 was capitalized and will be amortized over the life of the Credit Agreement. Amortized debt issuance expense in the amount of $97 and $90 for the three months ended March 31, 2025 and 2024, respectively, was recorded in interest expense in the Consolidated Statement of Operations. Unamortized debt issuance cost on the revolver was $419 and $479 as of March 31, 2025 and December 31, 2024, respectively.

As of March 31, 2025, $53,000 was outstanding under the term loan. In addition, the Company had $2,185 of outstanding letters of credit as of March 31, 2025. Amounts available under the revolving credit facility are reduced by any amounts outstanding under letters of credit. As of March 31, 2025, the Company’s capacity available for borrowing under the revolving credit facility was $117,815. Borrowings of the term loan and revolving credit facility bear interest at the Secured Overnight Financing Rate plus an applicable margin. Interest rates as of March 31, 2025 and December 31, 2024 were 5.54% and 6.01%, respectively.

As of March 31, 2025, the Company was in compliance with all applicable financial covenants under the Credit Agreement.

NOTE 13 – INCOME TAXES

The Company’s provision for income taxes in interim periods is typically computed by applying the estimated annual effective tax rates to income or loss before income taxes for the period. In addition, non-recurring or discrete items are recorded during the period in which they occur. For the three months ended March 31, 2025, the Company utilized an estimated effective tax rate.


	Three Months Ended March 31,
	2025			2024
(Benefit) expense provision for income taxes	$	(317	)	$	413
Effective tax rate		41	%		18	%

The effective tax rate of 41% for the three months ended March 31, 2025, differed from the rate for the three months ended March 31, 2024, of 18% primarily due to pre-tax loss for the three months ended March 31, 2025, and a reported pre-tax income for the three months ended March 31, 2024.

Income tax expense for the three months ended March 31, 2025, was calculated using an estimated effective tax rate, which differs from the U.S. federal statutory rate of 21% primarily due to adjustment for production tax credits.

NOTE 14 – SHARE-BASED COMPENSATION

The board of directors of Montauk Renewables adopted the Montauk Renewables, Inc. Equity and Incentive Compensation Plan (“MRI EICP”) in January 2021. Following the closing of the IPO, the board of directors of Montauk Renewables approved the grant of non-qualified stock options, restricted stock units and restricted share awards to the employees of Montauk Renewables and its subsidiaries in January 2021. In connection with the restricted share awards, the officers of the Company made elections under Section 83(b) of the Code. Pursuant to such elections, the Company withheld 950,214 shares of common stock from such awards at a price of $11.38 per share from such awards. The Company records and reports restricted shares and restricted stock units when vested and in the case of options, when such awards are settled in the Company’s common stock. Stock compensation expense related to these awards was $197 and $357 for the three months ended March 31, 2025 and 2024, respectively.

In connection with a May 2021 asset acquisition, 1,250,000 restricted share awards (“RS Awards”) were granted to two employees that were hired by the Company in connection with such acquisition. The RS Awards were to vest over a five-year period and subject to the achievement of time and performance-based vesting criteria over such period. In May 2022, the RS Awards were amended to remove the performance-based vesting criteria and will only be subject to time-based vesting requirements over a five-year period. The awards were revalued at $15,500. Stock compensation expense related to these awards was $420 and $1,227 for the three months ended March 31, 2025 and 2024, respectively.

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In 2023, the board of directors of the Company approved the grant of non-qualified stock options to the executive officers of the Company, which vest ratably over a period of three to five years. Stock compensation expense related to these awards was $657 for both the three months ended March 31, 2025 and 2024.

The restricted shares, restricted stock units and option awards are subject to vesting schedules and are subject to the terms and conditions of the MRI EICP and related award agreements including, in the case of the restricted share awards, each officer having made an election under Section 83(b) of the Code.

Options granted under the MRI EICP allow the recipient to receive the Company’s common stock equal to the appreciation in the fair market value of the Company’s common stock between the grant date and the exercise and settlement of options into shares as of the exercise dates. The fair value of the MRI EICP options was estimated using the Black-Scholes option pricing model. Three blocks of options have been awarded since inception of the plan with the following weighted-average assumptions (no dividends were expected):


	September 2023 Awards
Options awarded		225,000
Risk-free interest rate	4.44%-4.65%
Expected volatility	71%-73%
Expected option life (in years)	3.5-5.5
Grant-date fair value	$	5.72

	April 2023 Awards
Options awarded		2,100,000
Risk-free interest rate	3.71%-3.97%
Expected volatility	78%-80%
Expected option life (in years)	3.5-5.5
Grant-date fair value	$	4.25

	January 2021 Awards
Options awarded		950,214
Risk-free interest rate		0.5	%
Expected volatility		32	%
Expected option life (in years)		5.5
Grant-date fair value	$	3.44

The following table summarizes the restricted shares, restricted stock units and options outstanding under the MRI EICP as of March 31, 2025 and 2024, respectively:



	Restricted Shares				Restricted Stock Units				Options
	Number of shares		Weighted Average Grant Date Fair Value		Number of shares		Weighted Average Grant Date Fair Value		Number of shares		Weighted Average Exercise Price
End of period - December 31, 2024		626,108	$	11.93		170,000	$	7.63		2,325,000	$	7.04
Beginning of period - January 1, 2025		626,108	$	11.93		170,000	$	7.63		2,325,000	$	7.04
Granted		—		—		—		—		—		—
Vested		—		—		—		—		—		—
Forfeited		—		—		—		-		—		—
End of period - Balance at March 31, 2025		626,108	$	11.93		170,000	$	7.63		2,325,000	$	7.04

End of period - December 31, 2023		1,638,678	$	11.91		150,000	$	10.09		2,325,000	$	7.04
Beginning of period - January 1, 2024		1,638,678	$	11.91		150,000	$	10.09		2,325,000	$	7.04
Granted		—	—			10,000		6.48		—		—
Vested		—		—		—		—		—		—
Forfeited		—		—		—		—		—		—
End of period - March 31, 2024		1,638,678	$	11.91		160,000	$	9.87		2,325,000	$	7.04

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As of March 31, 2025 no vested options have been exercised. Unrecognized MRI EICP compensation expense for awards the Company expects to vest as of March 31, 2025 was $7,269 and will be recognized over approximately 3.5 years.

NOTE 15 – DEFINED CONTRIBUTION PLAN

The Company maintains a 401(k) defined contribution plan for eligible employees. The Company matches 50% of an employee’s deferrals up to 4%. The Company also contributes 3% of eligible employee’s compensation expense as a safe harbor contribution. The matching contributions vest ratably over four years of service, while the safe harbor contributions vest immediately. Incurred expense related to the 401(k) plan was $244 and $221 for the three months ended March 31, 2025 and 2024, respectively.

NOTE 16 – RELATED PARTY TRANSACTIONS

Related Party Loan

On January 26, 2021, The Company entered into a Loan Agreement and Secured Promissory Note (the “Initial Promissory Note”) with Montauk Holdings Limited (“MNK”). MNK is our affiliate and certain of our directors are also directors of MNK. Pursuant to the Initial Promissory Note, the Company advanced a cash loan of $5,000 to MNK for MNK to pay its dividend's tax liability arising from the Reorganization Transactions under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended. As a result of several amendments, the current principal balance of the loan is $10,690, the due date is December 31, 2033 and the security interest is 976,623 shares of our common stock held by MNK (as amended the “Fifth Amended Promissory Note”).

In December 2021, Rivetprops 47 Proprietary Limited (“RP47”) entered into an agreement to loan MNK up to 10,000 South African Rand (the “RP47 Loan”). The principal balance and accrued interest was 11,713 Rand or approximately $650 US Dollars as of December 31, 2024. There was no collateral pledged for this loan. This loan became due on December 31, 2024 (“Maturity Date”) when MNK and RP47 did not extend the maturity of the loan agreement. Associated with a modification on December 31, 2024 of the TIA between us and MNK, we became obligated to repay the RP47 Loan on MNK’s behalf as MNK did not have sufficient funds to repay the RP47 Loan. On February 2, 2025, our Board of Directors approved the repayment of the RP47 Loan under the TIA. On March 5, 2025 and in connection with the Fifth Amended and Restated Loan Agreement and Secured Promissory Note, the Company repaid the RP47 loan as required under the TIA.

Variable Interest Entity

Under ASC 810-10-25-38A and 38B, a reporting entity is deemed to have a controlling financial interest in a VIE if it possesses both of the following characteristics: the power to direct the activities of the VIE that most significantly impact its economic performance, and the obligation to absorb losses of the VIE that could potentially be significant or the right to receive benefits from the VIE that could potentially be significant.

Under ASC 810, the Company determined that MNK is a variable interest entity. The Company does not hold any equity interest in MNK but has entered into the Fifth Amended and Restated Loan Agreement and Secured Promissory Note between the Company and MNK.

Prior to the RP47 Loan repayment, we concluded that RP47, a related party of us through RP47’s ownership of MNK, was the primary beneficiary of MNK under the variable interest entity model. In connection with the modification under the TIA, RP47 retained its power over MNK but no longer held significant benefits in MNK. Substantially all of MNK’s activities are conducted on our behalf as MNK’s only asset is the 976,623 shares of our common stock held as security for the Fifth Amended and Restated Loan Agreement and Secured Promissory Note. MNK’s only obligation is its loan to us and thus, we became the primary beneficiary of MNK on December 31, 2024. In accordance with ASC 810, we consolidated MNK on December 31, 2024. We consolidated MNK’s current assets ($85), current liabilities ($632) and long-term liabilities ($16). The Fifth Amended Promissory Note became an intercompany loan and was eliminated in consolidation. MNK’s investment of $10,178 in the Company was also eliminated in consolidation. There is no gain or loss on the initial consolidation of MNK as the transaction is a common control transaction. We also recorded a noncash acquisition of Treasury Stock ($8,309) related to the consolidation of the 976,623 shares of our common stock collateralizing the Fifth Amended Promissory Note.

As of March 31, 2025, we consolidated MNK’s current assets ($74) and long-term liabilities ($16).

Employment Transactions

The Company signed a long-term immaterial lease in December 2023 with a landowner in North Carolina. This lease enabled the Company to construct a feedstock collection system on the property which is owned by the Company. In September 2024, the

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Company hired the landowner as an employee to assist in the procuring of additional long-term leases on farms for additional collection system installations related to feedstock in North Carolina.

NOTE 17 – SEGMENT INFORMATION

The Company’s reportable operating segments for the three months March 31, 2025 and 2024 are Renewable Natural Gas and Renewable Electricity Generation. Renewable Natural Gas includes the production of RNG. Renewable Electricity Generation includes generation of electricity at biogas-to-electricity plants. The Corporate entity is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation of the Company’s consolidated financial statements, and though not denoted as an operating segment, significant expenses are noted within the segment. The following tables are consistent with the manner in which the Chief Executive Officer, who is the Company's chief operating decision maker ("CODM"), evaluates the performance of each segment and allocates the Company's resources. The CODM evaluates the performance of the segments based on segment operating income (loss). The Company maintains discrete financial information for its operating sites, which meet the definition of an operating segment, but are aggregated into reportable segments based on the type of commodity produced. Total Assets and Capital expenditures by segment are also provided within the tables below. “RNG” refers to Renewable Natural Gas and “REG” refer to Renewable Electricity Generation.


	Three Months Ended March 31, 2025
	RNG		REG			Corporate			Total
Total operating revenue	$	38,451	$	4,152		$	—		$	42,603

Less (1)
Payroll and related expenses		2,410		683			5,158			8,251
Wellfield operating and maintenance		1,655		717		—				2,372
Plant expense		619		326		—				945
Waste disposal		570		14		—				584
Preventative maintenance		3,550		609		—				4,159
Breakdown expenses		445		448		—				893
Utility expense		3,926		113		—				4,039
Insurance	—		—				1,330			1,330
Professional and IT fees	—		—				1,360			1,360
Royalties, transportation, gathering and production fuel		7,114		457		—				7,571
Depreciation, depletion and amortization		4,900		1,310			54			6,264
Impairment		1,993		54		—				2,047
Other operating expenses (2), (3)		900		442			1,036			2,378
Total operating expenses	$	28,082	$	5,173		$	8,938		$	42,193

Operating income (loss)	$	10,369	$	(1,021	)	$	(8,938	)	$	410
Interest expense	—		—				1,243			1,243
Other expense (income)		8		9			(69	)		(52	)
Income (loss) before income taxes	$	10,361	$	(1,030	)	$	(10,112	)	$	(781	)

Total assets	$	188,732	$	115,729		$	49,765		$	354,226
Capital expenditures		7,568		3,983			81			11,632

(1) Significant expenses regularly provided to the CODM.

(2) The majority of other operating expenses for RNG and REG are consumables, rent, environmental compliance and general and administrative expenses.

(3) The majority of other operating expenses for Corporate are office expenses, board of director and corporate filing fees.

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	Three Months Ended March 31, 2024
	RNG		REG			Corporate			Total
Total operating revenue	$	33,988	$	4,799		$	—		$	38,787

Less (1)
Payroll and related expenses		2,168		602			5,873			8,643
Wellfield operating and maintenance		1,048		571		—				1,619
Plant expense		494		307		—				801
Waste disposal		428		13		—				441
Preventative maintenance		2,728		456		—				3,184
Breakdown expenses		295		81		—				376
Utility expense		3,942		61		—				4,003
Insurance	—		—				1,532			1,532
Professional and IT fees	—		—				1,282			1,282
Royalties, transportation, gathering and production fuel		5,997		521		—				6,518
Depreciation, depletion and amortization		4,076		1,297			61			5,434
Impairment		216		312		—				528
Other operating expenses (2), (3)		1,016		200			842			2,058
Total operating expenses	$	22,408	$	4,421		$	9,590		$	36,419

Operating income (loss)	$	11,580	$	378		$	(9,590	)	$	2,368
Interest expense	—			1			1,164			1,165
Other expense (income)		22		(1,011	)		(71	)		(1,060	)
Income (loss) before income taxes	$	11,558	$	1,388		$	(10,683	)	$	2,263

Total assets	$	181,150	$	87,071		$	86,468		$	354,689
Capital expenditures		9,041		12,826			119			21,986

(1) Significant expenses regularly provided to the CODM.

(2) The majority of other operating expenses for RNG and REG are consumables, rent, environmental compliance and general and administrative expenses.

(3) The majority of other operating expenses for Corporate are office expenses, board of director and corporate filing fees.

For the three months ended March 31, 2025 and 2024, three and four customers, respectively, made up greater than 10% of total revenues.


	Three Months Ended March 31, 2025
	RNG			REG		Corporate		Total

Customer A		19.1	%		—		—		19.1	%
Customer B		13.4	%		—		—		13.4	%
Customer C		10.9	%		—		—		10.9	%


	Three Months Ended March 31, 2024
	RNG			REG			Corporate		Total
Customer A		40.6	%		—			—		40.6	%
Customer B		12.8	%		—			—		12.8	%
Customer C		12.8	%		—			—		12.8	%
Customer D		—			10.9	%		—		10.9	%

NOTE 18 – LEASES

The Company leases office space and other office equipment under operating lease arrangements (with initial terms greater than twelve months), expiring in various years through 2033. These leases have been entered into to better enable the Company to conduct business operations. Office space is leased to provide adequate workspace for all employees in Pittsburgh, Pennsylvania and Houston,

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Texas. Landfill site operating leases include gas monitoring devices that serve to improve production efficiencies and alert technicians to issues and safety concerns occurring at the well head. Office space, office equipment and gas monitoring equipment agreements that exceed 12 months are accounted for as operating leases in accordance with ASC 842, Leases.

The Company also leases safety equipment for the various operational sites in the United States. The term of certain equipment exceeds twelve months and is accordingly classified as a finance lease under ASC 842. The finance leases expire in 2026 and were entered into in order to provide a safe work environment for operational employees.

The Company determines if an arrangement is, or contains, a lease at inception based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of time. For all operating and finance lease arrangements, the Company presents at the commencement date: a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.

The Company has elected, as a practical expedient, not to separate non-lease components from lease components, and instead account for each separate component as a single lease component for all lease arrangements, as lessee. In addition, the Company has elected, as a practical expedient, not to apply lease recognition requirements to short-term lease arrangements, generally those with a lease term of less than twelve months for all classes of underlying assets. In determination of the lease term, the Company considers the likelihood of lease renewal options and lease termination provisions.

The Company uses its incremental borrowing rate, as the basis to calculate the present value of future lease payments, at lease commencement. The incremental borrowing rate represents the rate of interest a lessee would have to pay to borrow an amount equal to the total lease payments on a collateralized basis over a similar term in a similar economic environment.

Supplemental information related to operating lease arrangements was as follows:



	Three Months Ended March 31,
	2025		2024
Cash paid for amounts included in the measurement of operating lease liabilities	$	671	$	178
Weighted average remaining lease term (in years)		3.53		5.21
Weighted average discount rate	5.00%-6.00%			5.00	%

Future minimum operating lease payments are as follows:


Year Ending
2025	$	1,945
2026		2,405
2027		583
2028		594
2029		606
Thereafter		2,107
Imputed interest		(1,045	)
Total	$	7,195

Supplemental information related to finance lease arrangements was as follows:



	Three Months Ended March 31,
	2025			2024
Cash paid for amounts included in the measurement of financing lease liabilities	$	21		$	20
Weighted average remaining lease term (in years)		2.21			6.09
Weighted average discount rate		5.00	%		5.00	%

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Future minimum finance lease payments are as follows:


Year Ending
2025	$	57
2026		32
2027		1
2028		1
2029		1
Thereafter		9
Imputed interest		(6	)
Total	$	95

NOTE 19 – (LOSS) INCOME PER SHARE

Basic and diluted (loss) income per share was computed using the following common share data for the three months ended March 31, 2025 and 2024, respectively:


	Three Months Ended March 31,
	2025			2024
Net (loss) income	$	(464	)	$	1,850
Basic weighted-average shares outstanding		142,711,797			141,986,189
Dilutive effect of share-based awards		—			383,030
Diluted weighted-average shares outstanding		142,711,797			142,369,219
Basic income per share	$	(0.00	)	$	0.01
Diluted income per share	$	(0.00	)	$	0.01

As a result of incurring a net loss for the three months ended March 31, 2025, potential common shares of 154,865 were excluded from diluted loss per share because the effect would have been antidilutive.

NOTE 20 – COMMITMENTS AND CONTINGENCIES

Environmental

The Company is subject to a variety of environmental laws and regulations governing discharges to the air and water, as well as the handling, storage and disposing of hazardous or waste materials. The Company believes its operations currently comply in all material respects with all environmental laws and regulations applicable to its business. However, there can be no assurance that environmental requirements will not change in the future or that the Company will not incur significant costs to comply with such requirements.

Litigation Contingencies

The Company, from time to time, may be involved in litigation. At March 31, 2025, Management does not believe there are any matters outstanding that would have a material adverse effect on the Company’s financial position or results of operations.

Other Contingencies

In March 2025, the Company completed an early stage joint venture. The investees in the joint venture are Pesta Energy, LLC, a wholly owned subsidiary of the Company, with an ownership percentage of 51% and Pioneer Renewable Energy Marketing, LLC, with an ownership percentage of 49%. Subject to various and certain requirements as defined in the underlying agreements, the Company could be required to make additional capital contributions up to $2,500, though the timing of which remains uncertain. The Company will use the equity method of accounting related to this joint venture. Refer to Note 2 – Summary of Significant Accounting Policies.

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NOTE 21 – SUBSEQUENT EVENTS

The Company evaluated its March 31, 2025 condensed consolidated financial statements through the date the financial statements were issued. The Company is not aware of any subsequent events which would require recognition or disclosure in the consolidated financial statements, except for the matter discussed below.

In April 2025, the Company accelerated the vesting of certain restricted share awards which were unvested as of March 31, 2025, as a result of the termination of an employee. The Company recognized $1,550 of non-cash stock compensation expense within General and administration expense.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this Quarterly Report on Form 10-Q. Throughout this section, dollar amounts and production volumes are expressed in thousands, except for per share amounts and RIN pricing amounts and unless otherwise indicated.

In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Cautionary Note Regarding Forward-Looking Statements,” “Item 1A.–Risk Factors” of our 2024 Annual Report, and elsewhere in this report.

Overview

Montauk Renewables is a renewable energy company specializing in the recovery and processing of biogas from landfills and other non-fossil fuel sources for beneficial use as a replacement to fossil fuels. We develop, own, and operate RNG projects, using proven technologies that supply RNG into the transportation industry and use RNG to produce Renewable Electricity. We are one of the largest U.S. producers of RNG, having participated in the industry for over 30 years. We established our operating portfolio of 11 RNG and two Renewable Electricity projects through self-development, partnerships, and acquisitions that span seven states.

Biogas is produced by microbes as they break down organic matter in the absence of oxygen (during a process called anaerobic digestion). Our two current sources of commercial scale biogas are LFG or ADG. We typically secure our biogas feedstock through long-term fuel supply agreements and property lease agreements with biogas site hosts. Once we secure long-term fuel supply rights, we design, build, own, and operate facilities that convert the biogas into RNG or use the processed biogas to produce Renewable Electricity. We sell the RNG and Renewable Electricity through a variety of term length agreements. Because we are capturing waste methane and making use of a renewable source of energy, our RNG and Renewable Electricity generate valuable Environmental Attributes, which we are able to monetize under federal and state renewable initiatives.

Our current operating projects produce either RNG or Renewable Electricity by processing biogas from landfill sites or agricultural waste from livestock farms. We view agricultural waste from livestock farms as a significant opportunity for us to expand our RNG business, and we continue to evaluate other agricultural feedstock opportunities. We believe that our business model and technology are highly scalable given availability of biogas from agriculturally derived sources, which will allow us to continue to grow through prudent development and complimentary acquisitions.

Recent Developments

RINs Generated but Unsold

Our profitability is highly dependent on the market price of Environmental Attributes, including the market price for RINs. As we self-market a significant portion of our RINs, a decision not to commit to transfer available RINs during a period will impact our revenue and operating profit. We sold all 9,885 D3 RINs generated and available for sale from 2024 RNG production in the first quarter of 2025. The impact of EPA actions associated with implementation of BRRR K2 separation and the extension of the 2024 RIN compliance period has temporarily impacted the commitment timing of the Company. As a result, we have approximately 3,916 RINs in inventory from 2025 RNG production as March 31, 2025. We have subsequently entered into commitments to transfer the majority of our RINs in inventory as of March 31, 2025 at prices approximating to the D3 RIN index. The average D3 RIN index price for the first quarter of 2025 was approximately $2.43. The following table summarizes select historical data related to RINs generated, RINs sold, and RINs generated but unsold. As we self-market a significant portion of our RINs and as the RFS is based on annual compliance, any strategic decision to not monetize available RINs in a quarter could impact the timing of operating revenues recognized during a fiscal year. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The timing of RIN transfers can vary year over year and by period within a year and is contingent on various factors including, but not limited to: (a) the Company’s expectations on RIN index price, (b) operational needs of the Company, (c) obligated parties purchase needs, or (d) the type of customer among other matters.

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Calendar Quarter	RINs Available for Sale	RINs Sold	RINs sold as % of RINs Available	RINs Available but Unsold	RINs Unsold as % of RINs Available
2023 Second Quarter	20,407	17,441	85.5%	2,966	14.5%
2023 Third Quarter	14,514	13,750	94.7%	764	5.3%
2023 Fourth Quarter	10,904	10,796	99.0%	108	1.0%
2024 First Quarter	11,240	7,889	70.2%	3,351	29.8%
2024 Second Quarter	14,707	10,000	68.0%	4,707	32.0%
2024 Third Quarter	15,895	15,750	99.1%	145	0.9%
2024 Fourth Quarter	9,822	3,000	30.5%	6,822	69.5%
2025 First Quarter	13,801	9,885	71.6%	3,916	28.4%

Capital Development Summary

The following summarizes our ongoing development growth plans expected capacity contribution, anticipated commencement of operations, and capital expenditure estimate, respectively excluding the Montauk Ag Renewables Development Project:


Development Opportunity	Estimated Capacity Contribution (MMBtu/day)	Anticipated Commencement Date	Estimated Capital Expenditure
Second Apex RNG Facility	2,100	2025 second quarter	$30,000-$40,000
Blue Granite RNG Facility	900	Delayed	TBD
Bowerman RNG Facility	3,600	2027	$85,000-$95,000
European Energy Facilities	N/A	2027	$65,000-$75,000
Tulsa RNG Facility	1,500	2027	$25,000-$35,000

Second Apex RNG Facility

In 2022, we announced the planned construction of a second RNG processing facility at the Apex landfill. The construction of a second facility under our existing fuel supply agreement was triggered by biogas feedstock volumes exceeding production capabilities discussions with the landfill host, and the host's waste intake forecasted projections. As the landfill host increases waste intake, we believe the additional 2,100 MMBtu per day of production capacity will enable us to process the forecasted increase in biogas feedstock volumes. We continue to expect there will be a period where we have excess availability capacity after the second facility is commissioned while the landfill host increases their waste intake. We are in commissioning stage which we expect to be complete in the second quarter of 2025.

Blue Granite RNG Project

In the first quarter of 2025, we received notice from the utility that it will no longer accept RNG into its distribution system, which was in opposition of the letter of intent that was issued when we were awarded the gas rights to the site. As a result, we impaired the capital associated with the early design of RNG equipment. We continue to review various alternatives related to interconnection opportunities as part of our considerations for offtake options with the understanding those alternatives may differ from initial development project assumptions, including physical and virtual and fixed interconnections. We are also reviewing alternatives for this site around producing energy other than RNG. We have paused further capital expenditures related to this site while we consider all alternatives.

Bowerman RNG Project

In 2023, we announced a planned development of a renewable natural gas landfill project in Irvine, CA at the Frank R. Bowerman Landfill to process the large and growing volumes of biogas in excess of the existing capacity of the REG facility. We expect facility commissioning in 2027 and expect the capital investment to range between $85,000 - $95,000. As part of the agreement to develop the RNG plant, we agreed to work with the landfill host on the landfill's management of its wellfield and flare facility permit requirements. We continue to work with the landfill host on the landfill’s management of its wellfield and flare facility permit requirements so that we continue to assess what, if any, impacts these changes could have on receipt of required regional regulatory construction permits. The project is anticipated to have production nameplate capacity of approximately 3,600 MMBtu per day,

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assuming currently forecasted biogas feedstock volumes projected to be available from the host landfill at the time of commissioning. We continue to incur capital expenditures for this project.

Carbon Dioxide Beneficial Use Opportunity

In 2024, we signed a contract for the delivery of 140 thousand tons per year of biogenic carbon dioxide (“CO2”). We intend to capture, clean and liquefy CO2 at select Texas facilities, at which point it will be transported to EE North America (“EENA”), a Texas-based e-methanol facility. The delivery term is expected to last at least 15 years with first delivery expected to begin in 2027. We have completed the initial site surveys related to location of the CO2 processing equipment, evaluated equipment suppliers, and started engineering design. We continue to target a commissioning start in 2027 and expect the capital investment to begin in the second quarter of 2025 for long lead equipment and design engineering.

Tulsa REG Conversion to RNG

In 2025, we announced the conversion of our Tulsa, Oklahoma Renewable Electric Generation facility to RNG project. The project will offer a variable inlet capacity providing production capacity of approximately 1,500 MMBtu per day and designed to beneficially process all of the available inlet gas feedstock from its landfill host. We expect to target a commissioning start in 2027 and expect to begin incurring capital expenditures for long lead items in the second quarter of 2025.

Montauk Ag Renewables Acquisition

In 2021, through a wholly-owned subsidiary Montauk Ag Renewables, we completed an asset purchase related to developing technology and a centralized processing location to recover residual natural resources from the waste streams of modern agriculture and to refine and recycle such waste products through proprietary and other processes in order to produce high quality renewable natural gas and recapture nitrogen, and micronutrient organic fertilizer alternatives (the “Montauk Ag Renewables Acquisition”).

With the change in REC generation passed by the state of North Carolina in 2024, we are in various other negotiations with other utility users to provide swine RECs from our expected first phase production of MWh. We continue to negotiate with potential power purchase agreement providers related to the resulting power generation derived from swine waste. We continue to test the most efficient methods of both collecting and transporting the swine feedstock from the collection farms to the centralized process location, including the removal of low energy content liquid waste. These methods include the pelletization of collected waste.

Including the original equipment acquired in the Montauk Ag Renewables Acquisition, the Turkey, North Carolina asset acquisition, and the relocation of the Magnolia, NC site reactor to Turkey, NC, we currently expect the first phase capital investment to range between $140,000 and $160,000.

We continue to develop the opportunities with Montauk Ag Renewables and can give no assurances that our plans related to this acquisition will meet our expectations. Utility interconnection, both inbound to and outbound from our centralized Turkey, NC processing facility is dependent on factors outside of our control. Regulatory development and offtake negotiations could delay our ability to fully optimize or meet the timing expectations related to revenue producing activities. Our current construction timeline and costs are subject to delays or costs increases, respectively. We continue to design and plan for the development of the Turkey, NC facility to be used for commercial production. We expect the Magnolia, NC location to be used for various feedstock processing needs. Based on our current development timeline expectations, we expect to commence significant revenue generating activities in 2026. We intend to contract with additional farms to secure feedstock sources for future production processes.

Waste-stream Biogas Recovery

In October 2024, we announced a collaboration with Emvolon to transform methane emissions from waste stream biogas into high-value carbon negative fuel. Leveraging Emvolon's patented technology, the initial pilot is a small-scale demonstration of recovering and converting biogas into green methanol. The pilot project at our Atascocita facility in Houston, TX continues with Emvolon having installed their patented containerized processing technology. We do not expect short term financial benefits from this demonstration nor a disruption to our operations.

Key Trends

Market Trends Affecting the Renewable Fuel Market

We believe rising demand for RNG is attributable to a variety of factors, including growing public support for renewable energy, U.S. governmental actions to increase energy independence, environmental concerns increasing demand for natural gas-powered vehicles, job creation, and increasing investment in the renewable energy sector.

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Key drivers for the long-term growth of RNG include the following factors:

•

Regulatory or policy initiatives, including the federal RFS program and state-level low-carbon fuel programs in states such as California and Oregon, that drive demand for RNG and its derivative Environmental Attributes (as further described below).

•

Efficiency, mobility and capital cost flexibility in RNG operations enable it to compete successfully in multiple markets. Our operating model is nimble, as we commonly use modular equipment; our RNG processing equipment is more efficient than its fossil-fuel equivalents.

•

Demand for compressed natural gas (“CNG”) from natural gas-fueled vehicles. The RNG we create is pipeline-quality and can be used for transportation fuel when converted to CNG. CNG is commonly used by medium-duty fleets that are close to fueling stations, such as city fleets, local delivery trucks and waste haulers.

•

Regulatory requirements, market pressure and public relations challenges increase the time, cost and difficulty of permitting new fossil fuel-fired facilities.

Factors Affecting Our Future Operating Results:

Conversion of Electricity Projects to RNG Projects:

We continue to evaluate opportunities to convert existing facilities from Renewable Electricity to RNG production. These opportunities tend to be most attractive for any merchant electricity facilities given the favorable economics for the sale of RNG plus RINs relative to the sale of market rate electricity plus RECs. This strategy has been an increasingly attractive avenue for growth since 2014 when RNG from landfills became eligible for D3 RINs. However, during the conversion of a project, there is a gap in production while the electricity project is offline until it commences operation as an RNG facility, which can adversely affect us. This timing effect may adversely affect our operating results as a result of our potential conversion of Renewable Electricity projects. Upon completion of a conversion, we expect that the increase in revenue upon commencement of RNG production will more than offset the loss of revenue from Renewable Electricity production. Historically, we have taken advantage of these opportunities on a gradual basis at our merchant electricity facilities, such as Atascocita and Coastal Plains.

Acquisition and Development Pipeline

The timing and extent of our development pipeline affects our operating results due to:

•

Impact of Higher Selling, General and Administrative Expenses Prior to the Commencement of a Project’s Operation: We incur significant expenses in the development of new RNG projects. Under the Biogas Regulatory Reform Rule, effective July 1, 2024, theoretical storage of RNG for future RIN generation prior to receiving EPA registration is no longer permitted and the receipt of RINs will no longer be delayed after injecting into a pipeline. We expect the elimination of theoretical storage, when combined with more timely EPA registration, to not materially impact the commencement of RIN revenue generation after pipeline injection.

•

Shifts in Revenue Composition for Projects from New Fuel Sources: As we expand into livestock farm projects, our revenue composition from Environmental Attributes will change. We believe that livestock farms offer us a lucrative opportunity, as the value of LCFS credits for dairy farm projects, for example, are a multiple of those realized from landfill projects due to the significantly more attractive CI score of livestock farms.

•

Incurrence of Expenses Associated with Pursuing Prospective Projects That Do Not Come to Fruition: We incur expenses to pursue prospective projects with the goal of a site host accepting our proposal or being awarded a project in a competitive bidding process. Historically, we have evaluated opportunities which we decided not to pursue further due to the prospective project not meeting our internal investment thresholds or a lack of success in a competitive bidding process. To the extent we seek to pursue a greater number of projects or bidding for projects becomes more competitive, our expenses may increase.

Regulatory, Environmental and Social Trends

Regulatory, environmental and social factors are key drivers that incentivize the development of RNG and Renewable Electricity projects and influence the economics of these projects. We are subject to the possibility of legislative and regulatory changes to certain incentives, such as RINs, RECs and GHG initiatives. On July 12, 2023, the EPA issued final rules in the Federal Register for the RFS volume requirements for 2023-2025. Final volumes for cellulosic biofuel were set at 838, 1,090 and 1,376 million RINs for the three years 2023, 2024 and 2025, respectively. The final rule also included significant changes to the existing RFS program, referred to as BRRR, that will require the RNG industry to modify how all RINs are generated. On January 1, 2025, all RFS participants must comply with BRRR provisions. We have registered all of our facilities under the BRRR provisions and have

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obtained Q-RIN status for RIN generation starting January 1, 2025. Under the BRRR provisions, the EPA finalized a limitation that biogas from one facility has a single use under the RFS as proposed (i.e., biointermediate, RNG or CNG/LNG via biogas closed distribution system). The EPA clarified that this does not preclude non-RFS uses at same facility.

The EPA did not meet the statutorily required deadline of November 2024 to finalize 2026 obligations under the RFS. The EPA is expected to target May 2025 to propose RFS obligations for 2026 and 2027. On December 12, 2024, the EPA proposed a partial waiver of 2024 Cellulosic Biofuel Volume Requirements due to the projected shortfall of D3 RINs available to meet the 2024 RVO. This proposal is still pending, and it is unknown when this proposed rule will be finalized (if at all) in 2025.

In December 2023, CARB released the formal proposal for new LCFS rules. The proposed rules will increase the stringency of CI reduction targets from 20% to 30% in 2030 and create a 2045 target of 90%. This reduction would have the potential impact of reducing the number of net credits in the program. CARB approved these new rules in November 2024, however in February 2025, the California Office of Administrative Law disapproved the changes because the regulations were not written in a way that persons directly affected by them could easily understand. CARB believes this disapproval to be routine and indicated its intention to resubmit the rules, which it has until June 2025 to do. CARB submitted a third notice of proposed regulations for amendments on April 11, 2025. Any substantive changes would be subject to a public comment period. The industry may see pricing volatility including potential decreases to LCFS credit prices whereas the amendments as originally approved were expected to increase LCFS credit prices. Also in the rules is a phase out of avoided methane crediting for dairy and swine manure pathways by 2040 for CNG usage and through 2045 for RNG used to produce hydrogen. The RNG deliverability/book and claim provisions for out-of-region projects will be eliminated for all projects that break ground after 2030. These projects will be required to demonstrate physical deliverability requirements beginning in 2041. Changes to the LCFS program require annual verification of the CI score assigned to a project. Annual verification could significantly affect the profitability of a project, particularly in the case of a livestock farm project.

Factors Affecting Revenue

Our total operating revenues include renewable energy and related sales of Environmental Attributes. Renewable energy sales primarily consist of the sale of biogas, including LFG and ADG, which is either sold or converted to Renewable Electricity. Environmental Attributes are generated and monetized from the renewable energy.

The BRRR requires that all unseparated K3 RINs generated by the RNG producer on RNG volumes injected into the commercial pipeline distribution system only become valid for sale once they are separated with the support of dispensing statements by a registered dispenser or RIN separator. This process could result in delays to the RNG producer's receipt of the separated K2 RINs from the dispenser. This rule change could also result in a RNG producer's failure to generate K3 RINs for a given gas flow month if the registered biogas producer negligently fails to generate the necessary biogas tokens before the end of the subsequent gas flow month. We expect this initial year impact of the EPA BRRR rule will increase our RINs unsold at the end of 2025.

We report revenues from two operating segments: Renewable Natural Gas and Renewable Electricity Generation. Corporate relates to additional discrete financial information for the corporate function; primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering, and other operations functions not otherwise allocated to a segment. As such, the Corporate segment is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation to the Company’s consolidated financial statements.

•

Renewable Natural Gas Revenues: We record revenues from the production and sale of RNG and the generation and sale of the Environmental Attributes derived from RNG, such as RINs and LCFS credits. Our RNG revenues from Environmental Attributes are recorded net of a portion of Environmental Attributes shared with off-take counterparties as consideration for such counterparties using the RNG as a transportation fuel. We had certain pathway provider sharing arrangements expiring throughout 2024 and in 2025. While we have not yet experienced a significant increase in Environmental Attributes shared with pathway providers in our renewals, our most recent pathway renewals have been at higher percentages than our historical percentages and the currently proposed pathway renewals are for percentages significantly higher than our historical arrangements. Historically, we have monetized less than 25% of our RNG volumes under these fixed-price agreements. We are considering entry into multiple short-term contracts throughout 2025, some potentially increasing our historical percentage of volumes monetized under fixed-price arrangements, to provide time for mitigation of these recent market trends.

•

Renewable Electricity Generation Revenues: We record revenues from the production and sale of Renewable Electricity and the generation and sale of the Environmental Attributes, such as RECs, derived from Renewable Electricity. All of our Renewable Electricity production is monetized under fixed-price PPAs from our existing operating projects.

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•

Corporate Revenues: Corporate reports realized and unrealized gains or losses under our gas hedge programs. The Company does not have any active gas hedge programs. Corporate also relates to additional discrete financial information for the corporate function; primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering and other operations functions not otherwise allocated to a segment.

Our operating revenues are priced based on published index prices which can be influenced by factors outside our control, such as market impacts on commodity pricing and regulatory developments. With our royalty payments structured as a percentage of revenue, royalty payments fluctuate with changes in revenues. We place a primary focus on managing production volumes and operating and maintenance expenses as these factors are more controllable by us.

RNG Production

Our RNG production levels are subject to fluctuations based on numerous factors, including:

Disruptions to Production: Disruptions to waste placement operations at our active landfill sites, severe weather events, or failure or degradation of our or a landfill operator’s equipment or interconnection or transmission problems could result in a reduction of our RNG production. We strive to proactively address any issues that may arise through preventative maintenance, process improvement and flexible redeployment of equipment to maximize production and useful life.

•

In the third quarter of 2024, we began to experience trends with several of our landfill hosts delaying their installation of or delaying our ability to install wellfield collection infrastructure in active waste placement areas, a practice historically common and critical to our projections of feedstock gas and, therefore, production. These landfill-driven delays impact the timing of collection system enhancement installations and the resulting timing of our production increases. We expect these trends to continue through 2025.

•

Despite collaboration with the landfill host at our Rumpke facility on our gas collection efforts, wellfield extraction environmental factors continue to impact gas extraction at the site. While the landfill continues to expand its waste intake and we continue to expand wellfield collection, our volumes were impacted during 2024. Mitigation efforts related to wellfield environmental factors continue in 2025 as the benefits from 2024 efforts did not achieve anticipated results.

•

Related to our gas rights agreement with our landfill host at our Rumpke RNG location, in 2025, we began the process of the relocation of our existing Rumpke RNG facility. The timing of this project and requirement to relocate the facility coincides with the landfills filling practices to move into the existing area of our now current Rumpke RNG facility and is contractually obligated. We expect to begin capital expenditures for long lead time equipment in the second quarter of 2025 and expect to target a commissioning in 2028. Depending on the timing of capital expenditure and potential other production capabilities in addition to RNG production related to the full design, we estimate capital expenditures to range between $80,000 - $110,000. This project is included within our 2025 development capital expenditures.

•

Similar wellfield extraction environmental factors continue to impact gas extraction at our Apex site. We are collaborating with the landfill to mitigate these impacts and expect these mitigation efforts to continue in 2025.

•

Changes made by the landfill host to the wellfield collection system at the McCarty facility have contributed to elevated nitrogen in the feedstock received by our facility. Additionally, the landfill host modified the wellfield bifurcation approach which has reduced the quantity of feedstock received at our facility. We are working with the landfill host but continue to have lower volumes of feedstock available to be processed at the McCarty facility.

•

Quality of Biogas: We are reliant upon the quality and availability of biogas from our site partners. The quality of the waste at our landfill project sites is subject to change based on the volume and type of waste accepted. Variations in the quality of the biogas could affect our RNG production levels. At three of our projects, we operate the wellfield collection system, which allows greater control over the quality and consistency of the collected biogas. At two of our projects, McCarty and Galveston, we have operating and management agreements by which we earn revenue for managing the wellfield collection systems. Additionally, our dairy farm project benefits from the consistency of feedstock and controlled environment of collection of waste to improve biogas quality.

•

RNG Production from Our Growth Projects: We anticipate increased production at certain of our existing projects as open landfills continue to take in additional waste and the amount of gas available for collection

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increases. Delays in commencement of production or extended commissioning issues at a new project or a conversion project, such as those we are currently experiencing at Blue Granite as described above, would delay any realization of production from that project.

Pricing

Our Renewable Natural Gas and Renewable Electricity Generation segments’ revenues are primarily driven by the prices under our off-take agreements and PPAs and the amount of RNG and Renewable Electricity that we produce. We sell the RNG produced from our projects under a variety of short-term and medium-term agreements to counterparties, with contract terms varying from three years to five years. Our contracts with counterparties are typically structured to be based on varying natural gas price indices for the RNG produced. All of the Renewable Electricity produced at our biogas-to-electricity projects is sold under long-term contracts to creditworthy counterparties, typically under a fixed price arrangement with escalators.

The pricing of Environmental Attributes, which accounts for a substantial portion of our revenues, is subject to volatility based on a variety of factors, including regulatory and administrative actions and commodity pricing.

The sale of RINs, which is subject to market price fluctuations, accounts for a substantial portion of our revenues. We manage against the risk of these fluctuations through forward sales of RINs, although currently we only sell RINs in the calendar year they are generated. We have subsequently entered into commitments to transfer the majority of our RINs in inventory as of March 31, 2025. We believe the impacts of the EPA BRRR reform and the 2024 proposed partial waiver of the 2024 RVO have temporarily impacted 2025 RIN purchase activity of RFS obligated parties. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.

Factors Affecting Operating Expenses

Our operating expenses include royalties, transportation, gathering and production fuel expenses, project operating and maintenance expenses, general and administrative expenses, depreciation and amortization, net loss (gain) on sale of assets, impairment loss and transaction costs. Our operating expenses can be subject to inflationary cost increases that are largely out of our control.

•

Project Operating and Maintenance Expenses: Operating and maintenance expenses primarily consist of expenses related to the collection and processing of biogas, including biogas collection system operating and maintenance expenses, biogas processing, operating and maintenance expenses, and related labor and overhead expenses. At the project level, this includes all labor and benefit costs, ongoing corrective and proactive maintenance, project level utility charges, rent, health and safety, employee communication, and other general project level expenses. Unanticipated feedstock processing or gas conditioning equipment failures occurring outside our planned preventative maintenance program can increase project operating and maintenance expenses and reduce production volumes. The timing of gas conditioning and process equipment preventative maintenance intervals could impact the timing and amount of our operating and maintenance expenses within a given quarter.

•

Royalties, Transportation, Gathering and Production Fuel Expenses: Royalties represent payments made to our facility hosts, typically structured as a percentage of revenue. Transportation and gathering expenses include capacity and metering expenses representing the costs of delivering our RNG and Renewable Electricity production to our customers. These expenses include payments to pipeline operators and other agencies that allow for the transmission of our gas and electricity commodities to end users. Production fuel expenses generally represent alternative royalty payments based on quantity usage of biogas feedstock.

•

General and Administrative Expenses: General and administrative expenses primarily consist of corporate expenses and unallocated support functions for our operating facilities, including personnel costs for executive, finance, accounting, investor relations, legal, human resources, operations, engineering, environmental registration and reporting, health and safety, IT and other administrative personnel and professional fees and general corporate expenses. From time to time, we may be parties to legal proceedings arising in the normal course of business which could increase our legal expenses. We continue to expect increased general and administrative expenses associated with our ongoing development of Montauk Ag Renewables in 2025. We account for share-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. In April 2025, we accelerated the vesting of certain restricted share awards to non-executives which were unvested as of March 31, 2025 as a result of the termination of an employee. We recognized $1,550 of non-cash stock compensation expense within general and administration expenses which will not be recurring in April 2025. For more information, see Note 14 to our unaudited condensed consolidated financial statements related to share-based compensation.

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•

Depreciation and Amortization: Expenses related to the recognition of the useful lives of our intangible and fixed assets. We spend significant capital to build and own our facilities. In addition to development capital, we annually reinvest to maintain these facilities.

•

Impairment Loss: Expenses related to reductions in the carrying value(s) of fixed and/or intangible assets based on periodic evaluations whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

•

Transaction Costs: Transaction costs primarily consist of expenses incurred for due diligence and other activities related to potential acquisitions and other strategic transactions.

Key Operating Metrics

Total operating revenues reflect both sales of renewable energy and sales of related Environmental Attributes. As a result, our revenues are primarily affected by unit production of RNG and Renewable Electricity, production of Environmental Attributes, and the prices at which we monetize such production. Set forth below is an overview of these key metrics:

•

Production volumes: We review performance by site based on unit of production calculations for RNG and Renewable Electricity, measured in terms of MMBtu and MWh, respectively. While unit of production measurements can be influenced by facility maintenance schedules, the metric is used to measure the efficiency of operations and the impact of optimization improvement initiatives. We monetize a majority of our RNG commodity production under variable-price agreements, based on indices. A portion of our Renewable Natural Gas segment commodity production is monetized under fixed-priced contracts. Our Renewable Electricity Generation segment commodity production is primarily monetized under fixed-priced PPAs.

•

Production of Environmental Attributes: We monetize Environmental Attributes derived from our production of RNG and Renewable Electricity. We carry-over a portion of the RINs generated from RNG production to the following year and monetize the carried over RINs in such following calendar year. A majority of our Renewable Natural Gas segment Environmental Attributes are self-monetized. A majority of our Renewable Electricity Generation segment Environmental Attributes are monetized as a component of our fixed-price PPAs.

•

Average realized price per unit of production: Our profitability is highly dependent on the commodity prices for natural gas and electricity, and the Environmental Attribute prices for RINs, LCFS credits, and RECs. Realized prices for Environmental Attributes monetized in a year may not correspond directly with that year’s production as attributes may be carried over and subsequently monetized. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.

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Comparison of Three Months Ended March 31, 2025 and 2024

The following table summarizes the key operating metrics described above, which are metrics we use to measure performance.


	For the three months ended March 31,									Change
	2025			2024			Change			%
(in thousands, unless otherwise indicated)
Revenues
Renewable Natural Gas Total Revenues	$	38,451		$	33,988		$	4,463			13.1	%
Renewable Electricity Generation Total Revenues	$	4,152		$	4,799		$	(647	)		(13.5	%)

RNG Metrics
CY RNG production volumes (MMBtu)		1,389			1,411			(22	)		(1.6	%)
Less: Current period RNG volumes under fixed/floor- price contracts		(496	)		(330	)		(166	)		50.3	%
Plus: Prior period RNG volumes dispensed in current period		291			358			(67	)		(18.7	%)
Less: Current period RNG production volumes not dispensed		(336	)		(384	)		48			(12.5	%)
Total RNG volumes available for RIN generation (1)		848			1,055			(207	)		(19.6	%)

RIN Metrics
Current RIN generation ( x 11.6935) (2)		9,932			12,373			(2,441	)		(19.7	%)
Less: Counterparty share (RINs)		(1,471	)		(1,241	)		(230	)		18.5	%
Plus: Prior period RINs carried into current period		6,822			108			6,714			6216.7	%
Less: RINs generated but unseparated		(1,482	)		—			(1,482	)		0.0	%
Less: CY RINs carried into next CY		—			—			—			0.0	%
Total RINs available for sale (3)		13,801			11,240			2,561			22.8	%
Less: RINs sold		(9,885	)		(7,889	)		(1,996	)		25.3	%
RIN Inventory		3,916			3,351			565			16.9	%
RNG Inventory (volumes not dispensed for RINs) (4)		336			384			(48	)		(12.5	%)
Average Realized RIN price	$	2.46		$	3.25		$	(0.79	)		(24.3	%)

Operating Expenses
Renewable Natural Gas Operating Expenses	$	21,204		$	18,138		$	3,066			16.9	%
Operating Expenses per MMBtu (actual)	$	15.26		$	12.85		$	2.41			18.8	%

REG Operating Expenses	$	3,808		$	2,813		$	995			35.4	%
$/MWh (actual)	$	82.78		$	52.11		$	30.67			58.9	%

Other Metrics
Renewable Electricity Generation Volumes Produced (MWh)		46			54			(8	)		(14.8	%)
Average Realized Price $/MWh (actual)	$	90.26		$	88.87		$	1.39			1.6	%

(1)

RINs are generated in the month that the gas is dispensed to generate RINs, which occurs the month after the gas is produced. Volumes under fixed/floor-price arrangements generate RINs which we do not self-market. K3 RIN separation occurs after the gas is dispensed (RINs generated but unseparated).

(2)

One MMBtu of RNG has the same energy content as 11.6935 gallons of ethanol, and thus may generate 11.6935 RINs under the RFS program.

(3)

Represents RINs available to be self-marketed by us during the reporting period.

(4)

Represents gas production which has not been dispensed to generate RINs.

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The following table summarizes our revenues, expenses and net income for the periods set forth below:


	For the three months ended March 31,								Change
	2025			2024		Change			%
Total operating revenues	$	42,603		$	38,787	$	3,816			9.8	%
Operating expenses:
Operating and maintenance expenses		17,557			14,451		3,106			21.5	%
General and administrative expenses		8,754			9,427		(673	)		(7.1	)%
Royalties, transportation, gathering and production fuel		7,571			6,518		1,053			16.2	%
Depreciation, depletion and amortization		6,264			5,434		830			15.3	%
Impairment loss		2,047			528		1,519			287.7	%
Transaction Costs		-			61		(61	)		(100.0	)%
Total operating expenses		42,193			36,419		5,774			15.9	%
Operating income	$	410		$	2,368	$	(1,958	)		(82.7	)%
Other expenses:		1,191			105		1,086			1,034.3	%
Net (loss) income before income taxes:		(781	)		2,263		(3,044	)		(134.5	)%
Income tax (benefit) expense		(317	)		413		(730	)		(176.8	)%
Net (loss) income	$	(464	)	$	1,850	$	(2,314	)		(125.1	)%

Revenues for the Three Months Ended March 31, 2025 and 2024

Total revenues in the first quarter of 2025 were $42,603, an increase of $3,816 (9.8%) compared to $38,787 in the first quarter of 2024. The increase is primarily related the monetization of prior period RINs of approximately 6,822 that were carried into 2025. As a result, we sold 25.3% more RINs during the first quarter of 2025 compared to the first quarter of 2024. Partially offsetting this impact was a decrease in realized RIN pricing of approximately 24.3% during the first quarter of 2025 compared to the first quarter of 2024.

Renewable Natural Gas Revenues

We produced 1,389 MMBtu of RNG during the first quarter of 2025, a decrease of 22 MMBtu (1.6%) compared to 1,411 MMBtu produced in the first quarter of 2024. Our Rumpke facility produced 39 MMBtu more in the first quarter of 2025 compared to the first quarter of 2024 as a result of a previously disclosed plant processing equipment failure that occurred in the first quarter of 2024. Offsetting this increase was our Apex facility that produced 57 fewer MMBtu in the first quarter of 2025 compared to the first quarter of 2024 as a result of cold weather conditions impacting gas feedstock availability, wellfield extraction environmental factors, as well as plant processing equipment failures.

Revenues from the Renewable Natural Gas segment in the first quarter of 2025 were $38,451, an increase of $4,463 (13.1%) compared to $33,988 in the first quarter of 2024. Average commodity pricing for natural gas for the first quarter of 2025 was $3.65 per MMBtu, 62.9% higher than the first quarter of 2024. During the first quarter of 2025, we self-monetized 9,885 RINs, representing a 1,996 increase (25.3%) compared to 7,889 in the first quarter of 2024. Average pricing realized on RIN sales during the first quarter of 2025 was $2.46 as compared to $3.25 in the first quarter of 2024, a decrease of 24.3%. This compares to the average D3 RIN index price for the first quarter of 2025 of $2.43 as compared to $3.12 in the first quarter of 2024, a decrease of approximately 22.1%. At March 31, 2025, we had approximately 336 MMBtu available for RIN generation, 1,482 RINs generated and unseparated, and 3,916 RINs generated and unsold. At March 31, 2024, we had approximately 384 MMBtu available for RIN generation and 3,351 RINs generated and unsold.

Renewable Electricity Generation Revenues

We produced approximately 46 MWh in Renewable Electricity in the first quarter of 2025, a decrease of 8 MWh (14.8%) from 54 MWh in the first quarter of 2024. Our Security facility produced approximately 6 MWh less in the first quarter of 2025 compared to the first quarter of 2024 as a result us ceasing operations in connection with the first quarter of 2024 sale of the gas rights back to the landfill host.

Revenues from Renewable Electricity facilities in the first quarter of 2025 were $4,152, a decrease of $647 (13.5%) compared to $4,799 in the first quarter of 2024. The decrease was primarily driven by the cessation of operations at our Security facility.

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In the first quarter of 2025, 100.0% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices associated with underlying PPAs, as compared to 100.0% in the first quarter of 2024. This provides us with certainty of price resulting from our Renewable Electricity sites.

Expenses for the Three Months Ended March 31, 2025 and 2024

General and Administrative Expenses

Total general and administrative expenses in the first quarter of 2025 were $8,754, a decrease of $673 (7.1%) compared to $9,427 for the first quarter of 2024. Employee related costs, including stock-based compensation costs were $5,011 in the first quarter of 2025, a decrease of $713 (12.5%) compared to $5,724 in the first quarter of 2024.

Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in the first quarter of 2025 were $14,090, an increase of $1,949 (16.1%) as compared to $12,141 in the first quarter of 2024. Our Apex facility operating and maintenance expenses increased approximately $663 primarily related timing of gas processing preventative maintenance schedule and plant process equipment failure repairs. Our McCarty facility operating and maintenance expenses increased approximately $308 primarily related to the timing of preventative maintenance media changes as well as wellfield operational enhancements. Our Rumpke facility operating and maintenance expenses increased approximately $221 primarily related to wellfield operational enhancements. Our Coastal facility operating and maintenance expenses increased approximately $221 primarily related to the timing of preventative maintenance media changes.

Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the first quarter of 2025 were $7,114, an increase of $1,117 (18.6%) compared to $5,997 in the first quarter of 2024. We recorded a decrease to our Pico facility earnout of approximately 12.5% during the first quarter of 2025. Royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues to 18.5% for the first quarter of 2025 from 17.6% in the first quarter of 2024.

Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in the first quarter of 2025 were $3,351, an increase of $1,059 (46.2%) compared to $2,292 in the first quarter of 2024. The increase was primarily driven by an increase in non-capitalizable costs at our Montauk Ag Renewables projects. Our Tulsa facility operating and maintenance expenses increased approximately $332 primarily related to plant process equipment maintenance.

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the first quarter of 2025 were $457, a decrease of $64 (12.3%) compared to $521 in the first quarter of 2024. Royalties, transportation, gathering and production fuel expenses increased as a percentage of Renewable Electricity revenues to 11.0% for the first quarter of 2025 from 10.9% in the first quarter of 2024.

Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in the first quarter of 2025 were $7,571, an increase of $1,053 (16.2%) compared to $6,518 in the first quarter of 2024. We make royalty payments to our fuel supply site partners on the commodities we produce and the associated Environmental Attributes. These royalty payments are typically structured as a percentage of revenue subject to a cap, with fixed minimum payments when Environmental Attribute prices fall below a defined threshold. To the extent commodity and Environmental Attributes’ prices fluctuate, our royalty payments may fluctuate upon renewal or extension of a fuel supply agreement or in connection with new projects. Our fuel supply agreements are typically structured as 20-year contracts, providing long-term visibility into the margin impact of future royalty payments.

Depreciation

Depreciation and amortization in the first quarter of 2025 was $6,264, an increase of $830 (15.3%) compared to $5,434 in the first quarter of 2024. The increase was primarily driven by the timing of wellfield capital investments placed into service and our Pico Digestion Capacity Increase project being placed into service.

Impairment loss

We calculated and recorded impairment losses of $2,047 in the first quarter of 2025, an increase of $1,519 (287.7%) compared to $528 in the first quarter of 2024. The increase primarily relates to the impairment of an RNG interconnection at our Blue Granite RNG project. The local gas utility informed us that no new connections would be accepted within their distribution pricing.

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Other Expenses

Other expenses in the first quarter of 2025 was $1,191, an increase of $1,086 (1034.3%) compared to $105 in the first quarter of 2024. The increase was primarily related to proceeds received from the sale of gas rights ahead of the fuel supply expiration at our Security facility in the first quarter of 2024.

Income Tax (Benefit) Expense

Income tax benefit for the three months ended March 31, 2025 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21.0% primarily related to the adjustment of Production Tax Credits.

The effective tax rate of 40.6% for the three months ended March 31, 2025 was higher than the rate for the three months ended March 31, 2024 of 18.2% primarily due to pre-tax loss for the three months ended March 31, 2025, and a reported pre-tax income for the three months ended March 31, 2024.

Operating Income (Loss) for the Three Months Ended March 31, 2025 and 2024

Operating income in the first quarter of 2025 was $410, a decrease of $1,958 (82.7%) compared to $2,368 in the first quarter of 2024. RNG operating income for the first quarter of 2025 was $10,369, a decrease of 1,211 (10.5%) compared to $11,580 in the first quarter of 2024. Renewable Electricity Generation operating loss for the first quarter of 2025 was $1,021, a decrease of $1,397 (371.5%) compared to operating income of $376 for the first quarter of 2024.

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Non-GAAP Financial Measures:

The following table presents EBITDA and Adjusted EBITDA, non-GAAP financial measures, for each of the periods presented below. We present EBITDA and Adjusted EBITDA because we believe the measures assist investors in analyzing our performance across reporting periods on a consistent basis by excluding items that we do not believe are indicative of our core operating performance. In addition, EBITDA and Adjusted EBITDA are financial measurements of performance that management and the board of directors use in their financial and operational decision-making and in the determination of certain compensation programs. EBITDA and Adjusted EBITDA are supplemental performance measures that are not required by or presented in accordance with GAAP. EBITDA and Adjusted EBITDA should not be considered alternatives to net (loss) income or any other performance measure derived in accordance with GAAP, or as an alternative to cash flows from operating activities or a measure of our liquidity or profitability.

The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net (loss) income, which is the most directly comparable GAAP measure, for the three months ended March 31, 2025 and 2024:


	For the three months ended March 31,
	2025			2024
Net (loss) income	$	(464	)	$	1,850
Depreciation, depletion and amortization		6,264			5,434
Interest expense		1,243			1,165
Income tax (benefit) expense		(317	)		413
Consolidated EBITDA		6,726			8,862

Impairment loss (1)		2,047			528
Net loss of sale of assets		15			22
Transaction costs		—			61
Adjusted EBITDA	$	8,788		$	9,473

(1)

We recorded impairment losses of $2,047 and $528 for the three months ended March 31, 2025 and 2024, respectively. The impairment losses in the first three months of 2025 primarily relate the impairment of an RNG interconnection at our Blue Granite RNG project. The first three months of 2024 impairment relates to an REG site in which we entered into a bill of sale, assignment and assumption agreement to sell its rights to the existing fuel supply agreement and property back to the site host in advance of the fuel supply agreement termination date and received $1,000 in proceeds.

Liquidity and Capital Resources

Sources of Liquidity

At March 31, 2025 and March 31, 2024, our cash and cash equivalents, net of restricted cash, was $40,111 and $63,277, respectively. We intend to fund development projects using cash flows from operations and borrowings under our revolving credit facility. We believe that we will have sufficient cash flows from operations and borrowing availability under our credit facility to meet our debt service obligations and anticipated required capital expenditures (including for projects under development) for the next 12 to 24 months. However, we are subject to business and operational risks that could adversely affect our cash flows and liquidity.

At March 31, 2025, we had debt before debt issuance costs of $53,000, compared to debt before debt issuance costs of $56,000 at December 31, 2024.

Our debt before issuance costs (in thousands) are as follows:


	March 31, 2025		December 31, 2024
Term loan	$	53,000		56,000
Revolving credit facility		—		—
Debt before debt issuance costs	$	53,000	$	56,000

Amended Credit Agreement

On December 21, 2021, the Company entered into the Fourth Amendment with Comerica and certain other financial institutions. The current credit agreement, which is secured by a lien on substantially all of our assets and assets of certain of our

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subsidiaries, provides for a five-year $80,000 term loan, a five-year $120,000 revolving credit facility, and a $75,000 accordion feature.

As of March 31, 2025, $53,000 was outstanding under the term loan and we had no outstanding borrowings under the revolving credit facility. The term loan amortizes in quarterly installments of $3,000 through 2026, with a final payment of $32,000 in late 2026 with an interest rate of 5.54% and 6.01% at March 31, 2025 and December 31, 2024, respectively.

The Amended Credit Agreement contains customary covenants applicable to us and certain of our subsidiaries, including financial covenants. The Amended Credit Agreement is subject to customary events of default, and contemplates that we would be in default if, for any fiscal quarter (x) the average monthly D3 RIN price (as determined in accordance with the Amended Credit Agreement) is less than $0.80 per RIN and (y) the consolidated EBITDA for such quarter is less than $6,000. Consolidated EBITDA is defined under the Amended Credit Agreement as net income plus (a) income tax expense, (b) interest expense, (c) depreciation, depletion, and amortization expense, (d) non-cash unrealized derivative expense and (e) any other extraordinary, unusual, or non-recurring adjustments to certain components of net income, as agreed upon by Comerica in certain circumstances.

Under the Amended Credit Agreement, we are required to maintain the following ratios:

•

a Total Leverage Ratio (as defined in the Amended Credit Agreement) of not more than 3.00 to 1.00 as of the end of any fiscal quarter from June 30, 2024 and thereafter; and

•

as of the end of each fiscal quarter, a Fixed Charge Coverage Ratio (as defined in the Amended Credit Agreement) of not less than 1.2 to 1.0.

As of March 31, 2025, we were in compliance with all applicable financial covenants under the Amended Credit Agreement.

For additional information regarding the Amended Credit Agreement, see Note 12— Debt to our unaudited condensed consolidated financial statements.

Capital Expenditures

We have historically funded our growth and capital expenditures with our working capital, cash flow from operations and debt financing. We expect our non-development 2025 capital expenditures to range between $14,000 and $17,000. Our 2025 non-development capital plans include annual preventative maintenance expenditures, annual wellfield expansion projects, and other specific facility improvements. Additionally, we estimate that our existing 2025 development capital expenditures will range between $100,000 and $150,000. The majority of our 2025 development capital expenditures are related to our ongoing development of Montauk Ag Renewables, the second Apex facility, the Bowerman RNG project, the EENA CO2 project, Tulsa RNG project and our Rumpke RNG relocation project. Our Amended Credit Agreement provides us with a $120,000 revolving credit facility, with a $75,000 accordion option, providing us with access to additional capital to implement our acquisition and development strategy. As we continue to explore strategic growth opportunities, we have not entered into nonbinding letters of intent for any opportunity, we provide no assurances that our plans related to any or all of these strategic opportunities will progress to definitive agreements. We believe that our existing cash and cash equivalents, cash generated from operations, and credit availability under our Amended Credit Agreement would allow us to pursue and close on our identified strategic growth opportunities in addition to the previously discussed non-development and development capital expenditures.

Cash Flow

The following table presents information regarding our cash flows and cash equivalents for the three months ended March 31, 2025 and 2024:


	For the three months ended March 31,
	2025			2024
Net cash provided by (used in):
Operating activities	$	9,140		$	14,292
Investing activities		(11,632	)		(22,786	)
Financing activities		(3,018	)		(2,020	)
Net decrease in cash and cash equivalents		(5,510	)		(10,514	)
Restricted cash, end of the period		383			451
Cash and cash equivalents, end of period		40,494			63,728

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For the first three months of 2025, we generated $9,140 of cash provided by operating activities compared to $14,292 in the first three months of 2024. For the first three months of 2025, income and adjustments to income from operating activities provided $8,807 compared to income and adjustments to income provided $9,357 in first three months of 2024. Working capital and other assets and liabilities provided $333 in the first three months of 2025 compared to working capital and other assets and liabilities providing $4,935 in the first three months of 2024.

Our net cash flows used in investing activities has historically focused on project development and facility maintenance. Our capital expenditures for the first three months of 2025 were $11,632, of which $6,076, $5,855, and $1,397 were related to the Montauk Ag Renewables in North Carolina, second Apex RNG facility, and Bowerman RNG project, respectively.

Our net cash flows used in financing activities of $3,018 for the first three months of 2025 increased by $998 compared to cash used in financing activities in the first three months of 2024 of $2,020.

Contractual Obligations and Commitments

Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under GAAP. Our off-balance sheet arrangements are limited to the outstanding letters of credit described below. Although these arrangements serve a variety of our business purposes, we are not dependent on them to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.

We have contractual obligations involving asset retirement obligations. See Note 8 in the unaudited condensed consolidated financial statements for further information regarding the asset retirement obligations.

We have contractual obligations under our debt agreement, including interest payments and principal repayments. See Note 12 in the unaudited condensed consolidated financial statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. During the first three months of 2025, we had approximately $2,185 of off-balance sheet arrangements of outstanding letters of credit. These letters of credit reduce the borrowing capacity of our revolving credit facility under our Amended Credit Agreement. Certain of our contracts require these letters of credit to be issued to provide additional performance assurances. There have been no draw downs on these outstanding letters of credit. During the first three months of 2024, we did not have off-balance sheet arrangements other than outstanding letters of credit of approximately $2,505.

We have contractual obligations involving operating leases. We lease office space and other office equipment under operating lease arrangements, expiring in various years through 2033. See Note 18 in the unaudited condensed consolidated financial statements for further information related to the lease obligations.

We have other contractual obligations associated with our fuel supply agreements. The expiration of these agreements range between 2-18 years. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,695.

In April 2025, the Board of Directors of Montauk Renewables Inc. authorized a share repurchase program (the “Share Repurchase Program”), pursuant to which we may, from time to time, purchase currently outstanding shares of its common stock for an aggregate repurchase price not to exceed $5,000. The timing, number and purchase price of shares repurchased under the program, if any, will be determined by a Repurchase Committee, comprised of Board members and management. The Share Repurchase Program does not have an expiration date and there are no assurances that purchases will take place under the program.

Critical Accounting Policies and Estimates

Our unaudited condensed consolidated financial statements are prepared in conformity with GAAP and require our management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, costs and expenses and related disclosures. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and such estimates may change if the underlying conditions or assumptions change.

Revenue Recognition

Our revenues are comprised of renewable energy and the related Environmental Attribute sales provided under a variety of short-term and medium-term agreements with our customers. All revenue is recognized when we satisfy our performance obligation(s) under the contract (either implicit or explicit) by transferring the promised product to the customer either when (or as) the customer obtains control of the product. A performance obligation is a promise in a contract to transfer a distinct product or service to a

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customer. A contract’s transaction price is allocated to each distinct performance obligation. We allocate the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract.

Revenue is measured as the amount of consideration we expect to receive in exchange for transferring our products. As such, revenue is recorded net of allowances and customer discounts as well as net of transportation and gathering costs incurred. To the extent applicable, sales, value add, and other taxes collected from customers and remitted to governmental authorities are accounted for on a net (excluded from revenues) basis.

The nature of the Company’s contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of the Company’s influence as the variable consideration is dictated by the market. Therefore, the variable consideration associated with the long-term contracts is considered fully constrained.

RINs

We generate D3 RINs through our production and sale of RNG used for transportation purposes as prescribed under the RFS program. Our operating costs are associated with the production of RNG. The RINs are government incentives that are generated through our renewable operating projects and not a result of physical attributes of our RNG production. The RINs that we generate are able to be separated and sold as credits independently from the energy produced. Therefore, no cost is allocated to the RIN when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred. We enter into forward commitments to transfer RINs. These forward commitments are based on D3 RIN index prices at the time of the commitment. Realized prices for RINs monetized in a year may not correspond directly to index prices due to the forward selling of commitments.

RECs

We generate RECs through our production and conversion of landfill methane into Renewable Electricity in various states, including California, Oklahoma, and Texas. These states have various laws requiring utilities to purchase a portion of their energy from renewable resources. Our operating costs are associated with the production of Renewable Electricity. The RECs are generated as an output of our renewable operating projects. The RECs that we generate are able to be separated and sold independently from the electricity produced. Therefore, no cost is allocated to the REC when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred.

Income Taxes

We are subject to income taxes in the U.S. federal jurisdiction and various state and local jurisdictions. Tax regulations within each jurisdiction are subject to the interpretation of the related tax laws and regulations and require significant judgment to apply.

Our net deferred tax asset position is a result of fixed assets, intangibles, and tax credit carryforwards. The realization of deferred tax assets is dependent upon our ability to generate sufficient future taxable income during the periods in which those temporary differences become deductible, prior to the expiration of the tax attributes. The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in our financial statements or tax returns and forecasting future profitability by tax jurisdiction.

We evaluate our deferred tax assets at reporting periods on a jurisdictional basis to determine whether adjustments to the valuation allowance are appropriate considering changes in facts or circumstances. As of each reporting date, management considers new evidence, both positive and negative, when determining the future realization of our deferred tax assets. We account for uncertain tax positions using a “more-likely-than-not” threshold for recognizing and resolving uncertain tax positions. The evaluation of uncertain tax positions is based on factors that include, but are not limited to, changes in tax law, the measurement of tax positions taken or expected to be taken in tax returns, the effective settlement of matters subject to audit, new audit activity and changes in facts or circumstances related to a tax position.

Intangible Assets

Separately identifiable intangible assets are recorded at their fair values upon acquisition. We account for intangible assets in accordance with ASC 350, Intangibles—Goodwill and Other. Finite-lived intangible assets include interconnections, customer contracts, and trade names and trademarks. The interconnection intangible asset is the exclusive right to utilize an interconnection line between the operating project and a utility substation to transmit produced electricity. Included in that right is full maintenance

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provided on this line by the utility. Intangible assets with finite useful lives are amortized on a straight-line basis over their estimated useful life. We evaluate our finite-lived intangible assets for impairment as events or changes in circumstances indicate the carrying value of these assets may not be fully recoverable. Events that could result in an impairment include, among others, a significant decrease in the market price or the decision to close a site.

If finite-lived or indefinite-lived intangible assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. The fair value is determined based on the present value of expected future cash flows. We use our best estimates in making these evaluations, however, actual future pricing, operating costs and discount rates could vary from the assumptions used in our estimates and the impact of such variations could be material.

Our assessment of the recoverability of finite-lived and indefinite-lived intangible assets is determined by performing monitoring assessment of the future cash flows associated with the underlying gas rights agreements. The cash flows estimates are performed at the operating unit level and based on the average remaining length of the gas rights agreements. Based on our analysis, we concluded the cashflows generated to be well in excess of the carrying amounts. Changes in market conditions related to the various price indexes used in estimating these cash flows could adversely affect these estimates.

Finite-Lived Asset Impairment

In accordance with FASB ASC Topic 360, Property, Plant and Equipment and intangible assets with finite useful lives are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by comparing the carrying amount of an asset or asset group to future undiscounted cash flows expected to be generated by the asset or asset group. Such estimates are based on certain assumptions, which are subject to uncertainty and may materially differ from actual results, including considering project specific assumptions for long-term credit prices, escalated future project operating costs and expected site operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Fair value is generally determined by considering (i) internally developed discounted cash flows for the asset group, (ii) third-party valuations, and/or (iii) information available regarding the current market value for such assets. We use our best estimates in making these evaluations and consider various factors, including future pricing and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates and the impact of such variations could be material. We identified discrete events and recorded impairment of $2,047 and $528 for the three months ended March 31, 2025 and 2024, respectively. See Note 3 in the unaudited condensed consolidated financial statements for further information related to asset impairments.

Emerging Growth Company

We are an emerging growth company, as defined in the JOBS Act, which ends after 2025. The JOBS Act allows emerging growth companies to delay the adoption of new or revised accounting standards until such time as those standards apply to private companies. We intend to utilize these transition periods, which may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the transition periods afforded under the JOBS Act.

Recent Accounting Pronouncements

For a description of our recently adopted accounting pronouncements and recently issued accounting standards not yet adopted, see Note 2 of our unaudited condensed consolidated financial statements in this report.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes since our disclosure in Quantitative and Qualitative Disclosures About Market Risk included as Item 7A in our 2024 Annual Report.

ITEM 4. CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) or 15d-15(e) under the Exchange Act, as of the end of the period covered by this quarterly report. Disclosure controls and procedures are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Our management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Our management, including our principal executive officer and principal financial officer, after evaluating the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report, concluded that as of such date, our disclosure controls and procedures were effective at a reasonable level of assurance.

Changes in Internal Control Over Financial Reporting

In March 2025, we implemented a new Enterprise Resource Planning ("ERP") system. In conjunction with the ERP implementation, we updated the design of key internal controls over financial reporting.

Except as discussed above, there were no changes in our internal control over financial reporting during our most recent fiscal quarter that have 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

From time to time, we and our subsidiaries may be parties to legal proceedings arising in the normal course of our business. We and our subsidiaries are currently not a party, nor is our property subject, to any material pending legal proceedings.

ITEM 1A. RISK FACTORS

We face a number of risks that could materially and adversely affect our business, results of operations, cash flow, liquidity, or financial condition. A discussion of our risk factors can be found in Part I, “Item 1A Risk Factors” in our 2024 Annual Report any of which could have a material effect on us.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS


Exhibit Number		Description



31.1		Certification of the Chief Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) of the Securities Exchange Act

31.2		Certification of the Chief Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) of the Securities Exchange Act

32.1		Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS		Inline XBRL Instance Document–the instance document does not appear in the Interactive Data File as its XBRL tags are embedded within the Inline XBRL document

101.SCH		Inline XBRL Taxonomy Extension Schema with Embedded Linkbase Documents

104		Cover page formatted as Inline XBRL and contained in Exhibit 101

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


May 8, 2025	MONTAUK RENEWABLES, INC.

	By:	/s/ SEAN F. MCCLAIN
		Sean F. McClain
		President and Chief Executive Officer (Principal Executive Officer)

	By:	/s/ KEVIN A. VAN ASDALAN
		Kevin A. Van Asdalan
		Chief Financial Officer (Principal Accounting Officer)