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, 2026

☐ 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 1, 2026 was 142,341,139 shares.

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TABLE OF CONTENTS


		Page

PART I FINANCIAL INFORMATION		7

ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)	7

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	28

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	45

ITEM 4.	CONTROLS AND PROCEDURES	45

PART II OTHER INFORMATION		46

ITEM 1.	LEGAL PROCEEDINGS	46

ITEM 1A.	RISK FACTORS	46

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	46

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	46

ITEM 4.	MINE SAFETY DISCLOSURES	46

ITEM 5.	OTHER INFORMATION	46

ITEM 6.	EXHIBITS	47

SIGNATURES		48

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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 GreenWave joint venture, the Bowerman RNG Facility, the development of a biogenic carbon dioxide facility and the related offtake, the Emvolon collaboration and pilot project, the Rumpke RNG Relocation 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 achieving anticipated levels of energy output on a sustained basis on the announced timeline, identifying suitable locations, obtaining and refinancing or otherwise repaying acquisition financing, and unexpected delays in construction and development;

• reduction or elimination of government loans, subsidies and other economic incentives to the renewable energy market, as a result of the current presidential administration and 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 (including the current unrest in the Middle East), domestic protests and other forms of civil unrest, terrorist activities, international hostilities, government shutdowns, political elections, security breaches, cyberattacks or other extraordinary events that impact general economic conditions, energy markets, 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 that raise our operating costs and increase the construction costs of our existing or new projects;

• rising interest rates increase the borrowing costs of 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 livestock farm and other 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;

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• 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, ability to refinance indebtedness at acceptable rates or at all and restrictions under existing and future indebtedness;

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

• our ability to meet milestone requirements under our PPAs;

• existing regulations and changes to regulations and policies that effect our operations;

• 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;

• ability 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

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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	8
Unaudited consolidated statements of operations	9
Unaudited consolidated statements of stockholders’ equity	10
Unaudited consolidated statements of cash flows	11
Condensed notes to unaudited consolidated financial statements	13

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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	2026			2025
Current assets:
Cash and cash equivalents	$	25,947		$	23,752
Accounts and other receivables		5,226			9,167
Current restricted cash		8			8
Income tax receivable		622			702
Current portion of derivative instruments	—				220
Prepaid insurance and other current assets		3,888			3,306
Total current assets	$	35,691		$	37,155
Non-current restricted cash	$	2,725		$	430
Property, plant and equipment, net		371,490			341,395
Goodwill and intangible assets, net		19,337			19,605
Deferred tax assets		5,930			5,550
Operating lease right-of-use assets		8,226			9,082
Finance lease right-of-use assets		20			39
Equity method investment		3,774			3,824
Other assets		20,587			18,380
Total assets	$	467,780		$	435,460

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	27,446		$	15,638
Accrued liabilities		11,620			11,735
Current portion of operating lease liability		2,899			3,287
Current portion of finance lease liability		13			32
Current portion of long-term debt	—				2,733
Total current liabilities	$	41,978		$	33,425
Long-term debt, less current portion	$	149,494		$	126,000
Non-current portion of operating lease liability		5,423			5,880
Non-current portion of finance lease liability		8			8
Asset retirement obligations		7,087			6,960
Other liabilities		17			39

Total liabilities	$	204,007		$	172,312

Commitments and contingencies (Note 21)

STOCKHOLDERS’ EQUITY

Common stock, $0.01 par value, authorized 690,000,000 shares; 143,912,811 shares issued at March 31, 2026 and December 31, 2025; 143,244,544 shares outstanding at March 31, 2026 and December 31, 2025	$	1,431		$	1,431
Treasury stock, at cost, 2,521,886 shares March 31, 2026 and December 31, 2025		(21,681	)		(21,681	)
Additional paid-in capital		226,922			226,302
Retained earnings		57,101			57,096
Total stockholders' equity	$	263,773		$	263,148
Total liabilities and stockholders' equity	$	467,780		$	435,460

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 share and per share data):


	Three Months Ended March 31,
	2026			2025
Total operating revenues	$	46,428		$	42,603

Operating expenses:
Operating and maintenance expenses		23,155			17,557
General and administrative expenses		8,019			8,754
Royalties, transportation, gathering and production fuel		8,037			7,571
Depreciation, depletion and amortization		8,373			6,264
Impairment loss		443			2,047
Total operating expenses	$	48,027		$	42,193
Operating (loss) income	$	(1,599	)	$	410

Other expenses (income):
Interest expense	$	1,336		$	1,243
Income from equity investment		(3,320	)	—
Loss on extinguishment of debt		944		—
Other income		(266	)		(52	)
Total other (income) expenses	$	(1,306	)	$	1,191
Loss before income taxes	$	(293	)	$	(781	)

Income tax benefit		(298	)		(317	)
Net income (loss)	$	5		$	(464	)

Income (loss) per share:
Basic	$	0.00		$	(0.00	)
Diluted	$	0.00		$	(0.00	)

Weighted-average common shares outstanding:
Basic		143,244,544			142,711,797
Diluted		143,258,120			142,711,797

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, 2024		142,711,797	$	1,426		2,038,524	$	(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		2,038,524	$	(21,262	)	$	223,139		$	54,884		$	258,187

Balance at December 31, 2025		143,244,544	$	1,431		2,521,886	$	(21,681	)	$	226,302		$	57,096		$	263,148
Consolidation of VIE		—		—		—		—			(15	)		—			(15	)
Net income		—		—		—		—			—			5			5
Stock-based compensation		—		—		—		—			635			—			635
Balance at March 31, 2026		143,244,544	$	1,431		2,521,886	$	(21,681	)	$	226,922		$	57,101		$	263,773

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,
	2026			2025
Cash flows from operating activities:
Net income (loss)	$	5		$	(464	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		8,373			6,264
Benefit for deferred income taxes		(380	)		(333	)
Loss on extinguishment of debt		944			—
Stock-based compensation		635			1,274
Derivative mark-to-market adjustments and settlements		220			214
Net (gain) loss on sale or disposal of assets		(13	)		15
Decrease in earn-out liability	—				(425	)
Accretion of asset retirement obligations		127			118
Amortization of debt issuance costs		142			97
Impairment loss		443			2,047
Non-cash expense - RINs from equity method investment		3,370		—
Income from equity method investment		(3,320	)	—
Cash provided (used) by changes in assets and labilities:
Accounts receivable		3,941			(319	)
Royalty offset long term receivable		(2,132	)		(739	)
Income tax receivable		80			(215	)
Critical spare inventory		(131	)		(303	)
Accounts payable and Accrued liabilities		3,916			2,213
Other		(374	)		(304	)
Net cash provided by operating activities	$	15,846		$	9,140
Cash flows from investing activities:
Capital expenditures	$	(30,867	)	$	(11,632	)
Proceeds from sale of assets		33		—
Net cash used in investing activities	$	(30,834	)	$	(11,632	)
Cash flows from financing activities:
Repayments of long-term debt	$	(44,000	)	$	(3,000	)
Borrowings of long-term debt		155,000		—
Repayments of revolver		(105,000	)	—
Borrowings of revolver		20,000		—
Debt extinguishment costs		(944	)	—
Debt issuance costs		(5,560	)	—
Finance lease payments		(18	)		(18	)
Net cash provided (used) in financing activities	$	19,478		$	(3,018	)
Net increase (decrease) in cash and cash equivalents and restricted cash	$	4,490		$	(5,510	)
Cash and cash equivalents and restricted cash at beginning of period	$	24,190		$	46,004
Cash and cash equivalents and restricted cash at end of period	$	28,680		$	40,494
Reconciliation of cash, cash equivalents, and restricted cash at end of period:
Cash and cash equivalents	$	25,947		$	40,111
Restricted cash and cash equivalents - current		8			8
Restricted cash and cash equivalents - non-current		2,725			375
	$	28,680		$	40,494

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	Three Months Ended March 31,
	2026		2025
Supplemental cash flow information:
Cash paid for interest, net of $1,579 and $0 capitalized respectively	$	1,853	$	1,055
Cash paid for income taxes		2		319
Accrual for purchase of property, plant and equipment included in accounts payable and accrued liabilities		19,562		8,534
Non-cash RIN distribution from equity method investment		3,370		—

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

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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, develops, operates and manages 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 electricity 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, 2025 included in the Company’s Annual Report on Form 10-K filed with the SEC on March 11, 2026 (the “2025 Annual Report”). The results of operations for the three months ended March 31, 2026 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, 2025, 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, 2025 in the 2025 Annual Report.

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

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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 17 – 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.

Cash and Cash Equivalents

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.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.

Segment Reporting

The Company reports segment information in two segments: RNG and Renewable Electricity Generation. 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 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 December 2025, the FASB issued ASU No. 2025-07, Derivatives and Hedging (Topic 815) and Revenue from Contracts with Customers (Topic 606): derivatives scope refinements and scope clarification for share-based noncash consideration from a customer in a revenue contract. This ASU (1) refines the scope of the guidance on derivatives in ASC 815 (Issue 1) and (2) clarifies the guidance on share-based payments from a customer in ASC 606 (Issue 2). The Company has adopted the standard retrospectively, as of December 31, 2025.

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. The Company has adopted the standard retrospectively, and the enhanced expense disclosures can be found in the 2025 Annual Report.

Recently Issued Accounting Standards Not Yet Adopted

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

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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.

NOTE 3 – ASSET IMPAIRMENT

The Company recorded an impairment loss of $443 and $2,047 for the three months ended March 31, 2026 and 2025, respectively. All 2026 impairments were for specifically identified discrete or non-operable assets, of which $308 was impaired at four RNG sites and $135 at one REG site. 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.

NOTE 4 – REVENUES FROM CONTRACTS WITH CUSTOMERS

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 to customers. Revenue is recorded net of allowances and customer discounts. Transportation and gathering costs incurred by customers after the transfer of control of the commodities are netted from revenue, as the Company does not control these services and acts as an agent with respect to such costs. 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. In certain cases, the Company's performance obligation under its sale of RNG contracts include variable components, whose consideration is based on subsequent monetization of environmental attribute credits by third parties. These variable components are recognized over time to the extent it is probable that a significant reversal will not occur.

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 20% and 37% of revenue for the three months ended March 31, 2026 and 2025, respectively.

The Company’s performance obligations related to the sale of Environmental Attributes are generally satisfied at a point in time and were 80% and 63% of revenue for the three months March 31, 2026 and 2025, 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 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, 2026 and 2025:


	Three months ended March 31, 2026
	Goods transferred at a point in time		Goods transferred over time		Total
Major goods/Service line:
Natural gas commodity	$	—	$	6,759	$	6,759
Natural gas environmental attributes		35,459		—		35,459
Electric commodity		—		2,510		2,510
Electric environmental attributes		1,700		—		1,700
	$	37,159	$	9,269	$	46,428
Operating segment:
RNG	$	35,459	$	6,759	$	42,218
REG		1,700		2,510		4,210
	$	37,159	$	9,269	$	46,428

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	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	$	—	$	13,247	$	13,247
Natural gas environmental attributes		24,991		—		24,991
Electric commodity		—		2,657		2,657
Electric environmental attributes		1,708		—		1,708
	$	26,699	$	15,904	$	42,603
Operating segment:
RNG	$	24,991	$	13,247	$	38,238
REG		1,708		2,657		4,365
	$	26,699	$	15,904	$	42,603

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, 2026.

NOTE 5 – EQUITY METHOD INVESTMENTS

In March 2025, the Company entered into a joint venture, GreenWave Energy Partners, LLC, ("GreenWave"). 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 ("PREM"), with an ownership percentage of 49%. Although the Company holds a 51% ownership interest, GreenWave is jointly controlled by each party, and no single entity has the unilateral ability to direct the activities that most significantly impact GreenWave’s economic performance; accordingly, consolidation is not required. As of March 31, 2026, the Company has contributed $4,000. Additionally, the Company provided for a $167 short-term loan. Subject to various and certain requirements as defined in the underlying agreements, the Company could be required to make additional short term loans up to $333. Any additional funding, if required, would be evaluated at the time of funding to determine the appropriate accounting treatment. The joint venture is primarily intended to help address the limited capacity of RNG usage in transportation by dispensing RNG through expanded Transportation Fuel uses under the RFS. While the joint venture is not expected to use RNG produced by the Company, it is expected to provide access to exclusive unique and proprietary pathways for other industry producers of RNG. PREM facilitates access to these pathways and the Company provides for the efficient RIN separation for the joint venture. As part of the agreement, the Company receives separated RINs as distributions. For the three months ended March 31, 2026 and the year ended December 31, 2025, the Company received 1,398 and 706 RINs, respectively, with a with a distribution value of $3,370 and $1,661, respectively. The Company records these distributed RINs within “Prepaid insurance and other current assets” on the Consolidated Balance Sheet, and are valued at the lower of cost or net realizable value. The distributions of separated RINs are accounted for as a return on investment and are recognized based on the Company’s share of GreenWave’s earnings, with any excess distributions treated as a return of investment and recorded as a reduction of the carrying amount of the equity method investment.


	Three Months Ended March 31,			Year Ended December 31,
	2026			2025
Equity balance—beginning of period	$	3,824		$	-
Contributions	—				4,000
Income from joint venture		3,320			1,485
Distributions		(3,370	)		(1,661	)
Equity balance—end of period	$	3,774		$	3,824

The Company utilizes the equity method of accounting related to this joint venture. Refer to Note 2 – Summary of Significant Accounting Policies.

NOTE 6 – 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, 2026 and 2025.

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Accounts and other receivables consist of the following as of March 31, 2026, December 31, 2025 and 2024:


	March 31, 2026		December 31, 2025		December 31, 2024
Accounts receivables	$	4,577	$	6,578	$	7,869
Other receivables		630		2,589		294
Reimbursable expenses		19	—			9
Accounts and other receivables, net	$	5,226	$	9,167	$	8,172

NOTE 7 – PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant and equipment consist of the following as of March 31, 2026 and December 31, 2025:


	March 31, 2026			December 31, 2025
Land	$	1,568		$	1,568
Buildings and improvements		38,914			38,914
Machinery and equipment		324,311			321,834
Gas mineral rights		35,526			35,526
Construction work in progress		198,087			163,277
Total	$	598,406		$	561,119
Less: Accumulated depreciation and amortization		(226,916	)		(219,724	)
Property, plant & equipment, net	$	371,490		$	341,395

Depreciation expense for Property, plant and equipment was $7,969 and $5,908 for the three months ended March 31, 2026 and 2025, respectively. Depletion expense for gas mineral rights was $91 and $90 for the three months ended March 31, 2026 and 2025, respectively.

Construction work in progress consists of RNG and REG capital expenditures on developmental projects and improvements to existing sites. Development 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 8 – GOODWILL AND INTANGIBLE ASSETS, NET

Goodwill and intangible assets consist of the following as of March 31, 2026 and December 31, 2025:


	March 31, 2026		December 31, 2025
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 $5,532 and $5,344	$	13,810	$	13,972
Customer contracts, net of accumulated amortization of $17,948 and $17,841		5,237		5,343
Total intangible assets with finite lives:	$	19,047	$	19,315
Total Goodwill and Intangible assets	$	19,337	$	19,605

As of March 31, 2026, the weighted average remaining useful lives for both customer contracts and interconnections were 12 years. Amortization expense was $295 and $248 for the three months ended March 31, 2026 and 2025, respectively.

NOTE 9 – 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

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political environments can affect the fair value of the obligations. As such, asset retirement obligations are considered a level 3 financial instrument.

The following table summarizes the activity associated with asset retirement obligations of the Company as of March 31, 2026 and December 31, 2025:


	Three Months Ended March 31,		Year Ended December 31,
	2026		2025
Asset retirement obligations—beginning of period	$	6,960	$	6,338
Accretion expense		127		485
New asset retirement obligation	—			137
Asset retirement obligations—end of period	$	7,087	$	6,960

NOTE 10 – 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 losses in the Consolidated Statements of Operations the three months ended March 31, 2026 and 2025:


		Three Months Ended March 31,
Derivative Instrument	Location	2026			2025
Interest rate swaps	Interest expense		(29	)		(214	)
Net loss		$	(29	)	$	(214	)

NOTE 11 – 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, 2026 and December 31, 2025, set forth by level, within the fair value hierarchy:


	March 31, 2026
	Level 1		Level 2		Level 3			Total

Asset retirement obligations		—		—		(7,087	)		(7,087	)
	$	—	$	—	$	(7,087	)	$	(7,087	)


	December 31, 2025
	Level 1		Level 2		Level 3			Total

Interest rate swap derivative asset	$	—	$	220	$	—		$	220
Asset retirement obligations		—		—		(6,960	)		(6,960	)
	$	—	$	220	$	(6,960	)	$	(6,740	)

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.

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Interest rate swap derivatives are classified as Level 2 financial instruments and are valued utilizing Secured Overnight Financing Rates. The Company's remaining interest rate swaps were settled on March 9, 2026 with a cash gain of $191, due to the debt refinancing and the extinguishment of the prior Comerica debt.

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.

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, 2026 and the year ended December 31, 2025 is included in Note 9.

There were no transfer of assets or liabilities between Levels 1, 2 or 3 of the fair value hierarchy as of March 31, 2026 and December 31, 2025.

NOTE 12 – ACCRUED LIABILITIES

The Company’s accrued liabilities consist of the following as of March 31, 2026 and December 31, 2025:


	March 31, 2026		December 31, 2025
Accrued expenses	$	1,915	$	3,342
Payroll and related benefits		2,090		2,865
Royalty		5,327		2,962
Utility		1,547		1,588
Accrued interest	—			813
Other		741		165
Accrued liabilities	$	11,620	$	11,735

NOTE 13 – DEBT

The Company’s debt consists of the following as of March 31, 2026 and December 31, 2025:


	March 31, 2026			December 31, 2025
Term loans	$	155,000		$	44,000
Revolver	—				85,000
Less: current principal maturities	—				(3,000	)
Less: debt issuance costs (on long-term debt)		(5,506	)	—
Long-term debt	$	149,494		$	126,000
Current portion of long-term debt	—				2,733
Total debt	$	149,494		$	128,733

New Senior Credit Facility

On March 9, 2026, the Company entered in a new, five year senior credit facility ("New Senior Credit Facility") with CCH1 MEH Lender LLC (a wholly owned subsidiary of Hannon Armstrong Capital LLC “HASI”) that consists of up to $200,000 in senior indebtedness, of which $155,000 is outstanding as of March 31, 2026. These proceeds were used to repay all outstanding debt of the Company at the date of closing. Subject to various requirements as defined in the underlying agreement, the Company expects to have an additional $45,000 in proceeds to draw upon the conclusion of certain engineering review and operational requirements of its Montauk Ag Renewables project in North Carolina. Finally, the Company maintains a cash collateralized facility with an entity not related to the HASI New Senior Credit Facility and has issued $2,185 of letters of credit, for which the Company is required to maintain 105% of cash collateral. The New Senior Credit Facility matures in March 2031. The New Senior Credit Facility includes various affirmative and negative covenants that require the Company to meet specified financial ratios and financial tests, as defined in the underlying agreement. Under the New Senior Credit Facility, the Company is required to maintain:

•

Total Net Leverage Ratio (as defined in the New Senior Credit Facility) of not more than 4.00 to 1.00, and

•

As of the end of each fiscal quarter, a Fixed Charge Coverage Ratio (as defined in the New Senior Credit Facility) of not less than 1.20 to 1.00, and

•

Various other financial covenants or mandatory prepayments (as defined in the New Senior Credit Facility)

The New Senior Credit Facility is subject to customary events of default and contemplates that the Company would be in default if, for any fiscal quarter (x) the average monthly D3 RIN price is less than $1.00 per RIN and (y) the consolidated average quarterly trailing EBITDA over the previous four quarters is less than $10,000.

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The New Senior Credit Facility has a 24-month availability period during which only interest is payable quarterly. After the availability period, the Company is required to make quarterly principal payments equal to 1.25% of the total outstanding principal. A final $131,750 payment is due March 2031. The interest rate of the New Senior Credit Facility is 10.25%.

As of December 31, 2025, under the prior credit agreement with Comerica Bank, $44,000 and $85,000 was outstanding under the term loan and revolver, respectively. In addition, the Company had $2,571 of outstanding letters of credit as of December 31, 2025. Amounts available under the revolving credit facility are reduced by any amounts outstanding under letters of credit. As of December 31, 2025, the Company’s capacity available for borrowing under the revolving credit facility was $32,429. Borrowings of the term loan and revolving credit facility bore interest at the Secured Overnight Financing Rate plus an applicable margin. The interest rate as of December 31, 2025 was 6.44%.

As of December 31, 2025, the Company was in compliance with all applicable financial covenants under the old credit agreement. The New Senior Credit Facility debt covenants commence June 30, 2026, with trailing cumulative calculations as applicable under the agreement.

NOTE 14 – INCOME TAXES

The Company’s provision for income taxes in interim periods is 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, 2026, the Company utilized an estimated effective tax rate.


	Three Months Ended March 31,
	2026			2025
Income tax benefit		(298	)		(317	)
Effective tax rate		102	%		41	%

The effective tax rate of 102% for the three months ended March 31, 2026 was higher than the rate for the three months ended March 31, 2025, of 41% primarily due to the change in our pre-tax book loss year over year.

Income tax expenses for the three months ended March 31, 2026 and March 31, 2025 were calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21% primarily due to the adjustment for production tax credits.

NOTE 15 – 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 $60 and $197 for the three months ended March 31, 2026 and 2025, respectively.

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 $575 and $657 for the three months ended March 31, 2026 and 2025, respectively.

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

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of the exercise dates. The fair value of the MRI EICP options was estimated using the Black-Scholes option pricing model. The following table provides the weighted-average option assumptions (no dividends were expected):



	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, 2026 and 2025, 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		—		—		—		—		—		—
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, 2025		—	$	—		130,000	$	4.97		2,100,000	$	6.77
Beginning of period - January 1, 2026		—	$	—		130,000	$	4.97		2,100,000	$	6.77
Granted		—	—			—		—		—		—
Vested		—		—		—		—		—		—
Forfeited		—		—		—		—		—	—
End of period - March 31, 2026		—	$	—		130,000	$	4.97		2,100,000	$	6.77

As of March 31, 2026, no vested options have been exercised. Unrecognized MRI EICP compensation expense for awards the Company expects to vest as of March 31, 2026 was $2,310 and will be recognized over approximately 2 years.

NOTE 16 – 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 $245 and $244 for the three months ended March 31, 2026 and 2025, respectively.

NOTE 17 – 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

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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. 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, 2026, we consolidated MNK’s current assets ($56), current liabilities ($14) and long-term liabilities ($17).

NOTE 18 – SEGMENT INFORMATION

The Company’s reportable segments for the three months ended March 31, 2026 and 2025 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 and though not an operating segment, certain corporate costs are disclosed as reconciling items to the Company’s consolidated results. 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, as these operating sites have similar economic characteristics, including production processes, customer types and regulatory environments. Total Assets and Capital expenditures by segment are also provided within the tables below, as these amounts are regularly reviewed by the CODM. “RNG” refers to Renewable Natural Gas and “REG” refers to Renewable Electricity Generation.

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Three months ended March 31, 2026
	RNG			REG			Total
Operating segment revenue	$	38,075		$	4,117		$	42,192

Corporate and other revenue								4,236
Total consolidated revenue							$	46,428

Less (1)
Payroll and related expenses		2,372			1,311			3,683
Wellfield operating and maintenance		1,920			569			2,489
Plant expense		561			275			836
Waste disposal		510			59			569
Preventative maintenance		3,695			1,005			4,700
Breakdown expenses		283			248			531
Utility expense		4,398			146			4,544
Royalties, transportation, gathering and production fuel		7,581			456			8,037
Depreciation, depletion and amortization		7,088			1,213			8,301
Impairment		308			135			443
Other operating expenses (2)		614			871			1,485
Operating segment expenses	$	29,330		$	6,288		$	35,618

Corporate and other operating expenses (3)								12,409
Total consolidated operating expenses							$	48,027

Operating segment income (loss)	$	8,745		$	(2,171	)	$	6,574

Corporate and other operating loss								(8,173	)
Total consolidated operating loss							$	(1,599	)

Operating segment other (income) expenses	$	(3	)	$	14		$	11
Corporate and other income (4)								(1,317	)
Total consolidated other income							$	(1,306	)

Operating segment income (loss) before income taxes	$	8,748		$	(2,185	)	$	6,563

Corporate and other loss before income taxes								(6,856	)
Total consolidated loss before income taxes							$	(293	)

Operating segment assets	$	192,876		$	226,298		$	419,174
Corporate and other assets								48,606
Total consolidated assets							$	467,780

Operating segment capital expenditures	$	2,569		$	28,249		$	30,818
Corporate and other capital expenditures								49
Total consolidated capital expenditures							$	30,867

(1) Significant expenses regularly reviewed by 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 operating expenses for Corporate and other are payroll and related expenses of $4,450, insurance of $1,070 and professional and IT fees of $1,717.

(4) The majority of other expense (income) for Corporate and other are interest expense of $1,335 and income from equity investment of ($3,320).

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Three months ended March 31, 2025
	RNG		REG			Total
Operating segment revenue	$	38,451	$	4,152		$	42,603

Corporate and other revenue							-
Total consolidated revenue						$	42,603

Less (1)
Payroll and related expenses		2,410		683			3,093
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
Royalties, transportation, gathering and production fuel		7,114		457			7,571
Depreciation, depletion and amortization		4,900		1,310			6,210
Impairment		1,993		54			2,047
Other operating expenses (2)		900		442			1,342
Operating segment expenses	$	28,082	$	5,173		$	33,255

Corporate and other operating expenses (3)							8,938
Total consolidated operating expenses						$	42,193

Operating segment income (loss)	$	10,369	$	(1,021	)	$	9,348

Corporate and other operating loss							(8,938	)
Total consolidated operating income						$	410

Operating segment other expenses	$	8	$	9		$	17
Corporate and other expenses (4)							1,174
Total consolidated other expenses						$	1,191

Operating segment income (loss) before income taxes	$	10,361	$	(1,030	)	$	9,331

Corporate and other loss before income taxes							(10,112	)
Total consolidated loss before income taxes						$	(781	)

Operating segment assets	$	188,732	$	115,729		$	304,461
Corporate and other assets							49,765
Total consolidated assets						$	354,226

Operating segment capital expenditures	$	7,568	$	3,983		$	11,551
Corporate and other capital expenditures							81
Total consolidated capital expenditures						$	11,632

(1) Significant expenses regularly reviewed by 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 operating expenses for Corporate and other are payroll and related expenses of $5,158, insurance of $1,330 and professional and IT fees of $1,360.

(4) The majority of other expense (income) for Corporate and other is interest expense of $1,243.

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For both the three months ended March 31, 2026 and 2025, three customers made up greater than 10% of total revenues.


	Three months ended March 31, 2026
	RNG			REG		Corporate		Total

Customer A		26.8	%		—		—		26.8	%
Customer B		15.7	%		—		—		15.7	%
Customer C		13.1	%		—		—		13.1	%

	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	%

NOTE 19 – 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, 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,
	2026		2025
Cash paid for amounts included in the measurement of operating lease liabilities	$	967	$	671
Weighted average remaining lease term (in years)		2.73		3.53
Weighted average discount rate	5.00%-6.00%		5.00%-6.00%

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Future minimum operating lease payments are as follows:


Year Ending
2026	$	2,695
2027		2,147
2028		1,767
2029		606
2030		618
Thereafter		1,490
Imputed interest		(1,001	)
Total	$	8,322

Supplemental information related to finance lease arrangements was as follows:


	Three Months Ended March 31,
	2026		2025
Cash paid for amounts included in the measurement of financing lease liabilities	$	21	$	21
Weighted average remaining lease term (in years)		3.94		2.21
Weighted average discount rate	5.00%-6.00%		5.00%-6.00%

Future minimum finance lease payments are as follows:


Year Ending
2026	$	13
2027		1
2028		1
2029		1
2030		1
Thereafter		8
Imputed interest		(4	)
Total	$	21

NOTE 20 – INCOME (LOSS) PER SHARE

Basic and diluted income (loss) per share was computed using the following common share data for the three months ended March 31, 2026 and 2025, respectively:


	Three Months Ended March 31,
	2026		2025
Net income (loss)	$	5	$	(464	)
Basic weighted-average shares outstanding		143,244,544		142,711,797
Dilutive effect of share-based awards		13,576		—
Diluted weighted-average shares outstanding		143,258,120		142,711,797
Basic income per share	$	0.00	$	(0.00	)
Diluted income per share	$	0.00	$	(0.00	)

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 21 – COMMITMENTS AND CONTINGENCIES

Environmental

The Company is subject to a variety of environmental laws and regulations governing discharges to 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

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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, 2026, 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.

NOTE 22 – SUBSEQUENT EVENTS

The Company evaluated its March 31, 2026 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.

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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 2025 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. 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 and as the RFS is based on annual compliance, a decision not to commit to transfer and monetize available RINs during a period will impact the timing of our operating revenues and operating profit recognized during a period. We sold all 3,903 D3 RINs generated and available for sale from our 2025 RNG production in the first quarter of 2026. We had approximately 165 RINs generated but unseparated at March 31, 2026. The average D3 RIN index price for the first quarter of 2026 was approximately $2.41. The following table summarizes select historical data related to RINs generated, RINs sold, and RINs generated but unsold. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The results related to our GreenWave joint venture are excluded from the table below. 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
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%
2025 Second Quarter	11,158	11,050	99.0%	108	1.0%
2025 Third Quarter	12,421	12,411	99.9%	10	0.1%
2025 Fourth Quarter	10,786	10,786	100.0%	-	0.0%
2026 First Quarter	12,482	12,403	99.4%	79	0.6%

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
Bowerman RNG Facility	3,600	2027	$85,000-$95,000
Atascocita LCO2 Facility	N/A	TBD	$30,000-$40,000
Tulsa RNG Facility	1,500	2027	$25,000-$35,000
Rumpke RNG Relocation Project	7,500	2028	$70,000-$90,000

Montauk Ag Renewables Acquisition

In 2021, Montauk Ag Renewables purchased technology and assets (the “Montauk Ag Renewables Acquisition”) to recover residual natural resources from swine waste and to refine and recycle such waste products through proprietary and other processes to produce high quality renewable electricity, North Carolina swine RECs, and micronutrient organic fertilizer alternatives. Upon completion of the first phase of the project, we expect that it will annually produce 41 MWh of electric power, approximately 120 RECs and 8.7 tons of organic fertilizer alternative.

With the change in REC generation passed by the state of North Carolina in 2024, we continue our negotiations with other utility users to provide swine RECs from our expected first phase production of MWh. We expect the annual REC capacity of the Turkey, NC location to be approximately 120 RECs and have signed a REC agreement with Duke Energy for annual sales of 47 RECs, which represents approximately 45% of the set-aside compliance volumes for swine under North Carolina’s Renewable Energy and Energy Efficiency Portfolio Standard. We continue to optimize our monetization strategies for the currently uncontracted portion of annually generated RECs and are in various stages of negotiation and responses to requests from obligated purchasers. Many of these agreements contain competitive details and, while there remains a limited active swine REC market in North Carolina, we believe the prices we are negotiating will be market based. We believe our average achievable price per swine REC could fall within the range of $200 to $400 per REC.

In September 2025, a joint motion was filed with the North Carolina Utility Commission (“NCUC”) by various entities seeking to modify and delay the 2025 requirements of certain aspects of the North Carolina Clean Energy and Portfolio Standard, specifically, the portfolio standards relating to swine RECs. We note this filing is consistent with historical annual filings in response to the historically limited swine REC market in North Carolina. In October 2025, we filed response comments to the joint motion with the NCUC requesting they grant modifications or delays only to individual power supplies that have demonstrated need, require power suppliers that have not achieved 100% compliance in 2025 to apply any cumulatively acquired swine RECs to the suppliers unsatisfied 2025 pro rata obligation, and modify the swine REC set-aside for 2026 and beyond to match the requirement originally set by North Carolina in 2018. In January 2026, the NCUC denied the request for waivers and determined that parties must use banked RECs to meet 2025 compliance targets. The compliance obligations for those utilities filing the September 2025 joint motion continue to increase through 2029.

We have commissioned our Montauk Ag Renewables project and are producing syngas. We expect our production and sale of renewable electricity from our syngas to commence in May 2026, with revenue generation triggered upon the calibration of the sales meter from the interconnection utility. We have operated the full production line as part of the commissioning process and expect to be able to produce our targeted first phase of 47 MWh and 120 RECs annually with approximately 50 percent of our installed reactor capacity. Our capital investment expectation for this first phase of the project remains unchanged at $200,000. We expect a ramp-up in production volumes throughout 2026 directly related to additional feedstock collection.

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We continue to develop opportunities with Montauk Ag Renewables and can give no assurances that our plans related to this acquisition will meet our expectations. We estimate our Montauk Ag Renewables project to potentially generate tax attributes once placed into service consisting mainly of a mix of federal investment tax and production tax credits and North Carolina state tax attributes. We give no assurances that our estimates on tax attributes for our Montauk Ag Renewables project will meet these expectations.

Raeger Gas Rights Extension

In March 2026, we successfully negotiated a five-year gas rights extension at our Raeger facility. The extension secures our access to biogas feedstock at the site through 2031, supporting the continued operation of the facility.

GreenWave Joint Venture

Through our wholly-owned subsidiary Pesta Energy, LLC, we entered into an agreement with Pioneer Renewables Energy Marketing, LLC to form a joint venture, GreenWave Energy Partners, LLC. The primary goal of the joint venture is to help address the limited capacity of RNG utilization for transportation by offering third party RNG volumes access to exclusive unique and proprietary pathways. We recorded income from GreenWave of approximately $3,320 in the first quarter of 2026. We also received 1,398 in separated RINs distributed from GreenWave of which we have 425 available for sale as of March 31, 2026. Our capital investment in the joint venture is estimated to be up to approximately $4,500, subject to various and certain requirements as defined in the underlying agreements.

New Senior Credit Facility

On March 9, 2026, , we entered into a five year New Senior Credit Facility with HASI that consists of up to $200,000 in senior indebtedness, of which $155,000 is outstanding as of March 31, 2026. We used this facility to refinance our existing outstanding debt and have $45,000 available to borrow subject to terms of the agreement.

Carbon Dioxide Beneficial Use Opportunity

In April 2026, we sent a letter confirming termination of our contract with European Energy North America (“EENA”) for the delivery of biogenic carbon dioxide (“CO2”). The termination was due to EENA’s failure to provide certain contractual assurances and notices related to the construction of their Texas-based e-methanol facility. We are currently exploring alternative offtake arrangements with interested parties at our Atascocita location. The timing of capital expenditures will be synchronous with the finalization of replacement offtake agreements. We continue to anticipate a capital investment between $30,000 and $40,000.

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.

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.

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Factors Affecting Our Future Operating Results:

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.

•

Shifts in Revenue Composition for Projects from New Fuel Sources: As we expand into agriculture projects, our revenue composition from Environmental Attributes will change. We believe that agriculture offers 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 scoring.

•

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. Our business is dependent on federal and state programs that support renewable fuels, including RIN, RECs and greenhouse gas reduction initiatives. These programs are subject to legislative and regulatory changes that could impact the timing and level of incentives available to our projects.

On July 12, 2023, the EPA issued final rules establishing Renewable Fuel Standard (“RFS”) volume requirements for 2023 through 2025. Final cellulosic biofuel volumes were set at 838, 1,090 and 1,376 D3 RINs for 2023, 2024 and 2025, respectively. The rule also included significant changes to the RFS program, referred to as the biogas regulatory reform rule (“BRRR”), which modified the manner in which RINs are generated beginning January 1, 2025. We have registered all of our facilities under the BRRR provisions and have obtained Q-RIN status for RIN generation commencing January 1, 2025. Under these provisions, biogas from a single facility is limited to a single qualifying use under the RFS (e.g., as a biointermediate, RNG, or CNG/LNG via a biogas closed distribution system), although non-RFS uses at the same facility remain permissible.

On June 13, 2025, the EPA issued a final rule partially waiving the 2024 cellulosic biofuel volume requirement, reducing the requirement from 1,090 to 1,010 D3 RINs based on actual production levels. In connection with this action, the EPA made Cellulosic Waiver Credits (“CWCs”) available to obligated parties as an additional compliance mechanism.

On March 27, 2026, the EPA finalized RFS standards for 2026 and 2027, as well as a partial waiver of the 2025 cellulosic biofuel volume requirement. The 2025 cellulosic volume requirement was reduced from 1,376 to 1,210 D3 RINs, with CWCs also made available for 2025 compliance. Final cellulosic biofuel volume requirements for 2026 and 2027 were established at 1,360 and 1,430 D3 RINs, respectively. These volumes reflect the EPA’s assessment of expected RIN generation capacity and the related pathway constraints of the end-use demand for CNG/LNG transportation fuels derived from biogas.

On August 22, 2025, the EPA issued decisions on 175 Small Refinery Exemption (“SRE”) petitions, granting full exemptions to 63 petitions and partial exemptions to 77 petitions for the 2023 and 2024 compliance years. Additional SRE exemptions were granted by EPA on November 7, 2025. Full exemptions were granted to 2 petitions, 12 petitions were granted partial exemptions and 2 petitions were denied. These exemptions reduced renewable fuel blending obligations for affected parties and increased the availability of RINs in the market. In conjunction with these actions, the EPA finalized a reallocation mechanism as part of the 2026 and 2027 RFS rulemaking to redistribute a significant portion of exempted volumes into future RVOs. This reallocation is intended to partially offset the impact of prior exemptions by increasing future compliance requirements. The EPA, however, did not provide any reallocations of D3 RINs as part of the 2026 and 2027 RVO in the final rule issued March 27, 2026. This is primarily due to the statutory conditions on cellulosic biofuel volume requirements, which do not allow EPA to set the total applicable volume of cellulosic biofuel at a volume that is greater than the projected volume available, and which necessarily excludes cellulosic carryover RINs.

We continue to monitor regulatory developments related to the RFS and other low-carbon fuel programs. Changes in regulatory requirements, including the implementation of BRRR, adjustments to RVOs, the availability of CWCs, and the treatment of SREs, may affect the supply-demand balance for RINs and the overall economics of our projects.

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 90% by 2045. This reduction could have the potential impact of reducing the number of net credits in the program. On July 1, 2025, CARB’s amended LCFS rules officially took effect setting the aggressive

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carbon intensity reduction targets listed above. The industry may see gradual increases in LCFS credit prices over the next year. The rules also phase out 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 are 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. In June 2025, California lawmakers introduced California Senate Bill SB-237, which includes a potential cap on LCFS credit prices of approximately $75/ton.

On March 15, 2025, the Full-Year Continuing Appropriations and Extensions Act, 2025 was signed into law. In May 2025, we were informed that the law eliminated the United States Department of Agriculture Advanced Biofuel Payment Program. We received approximately $200 annually since 2021 under this program. In 2025, we received notice that the program was reinstated and that retroactive payments would be issued for the missed quarters while the program was closed. In the first quarter of 2026, we recorded approximately $265 related to the quarters for which the program was closed.

Income Tax and Tax Attributes

Our net deferred tax asset position is a result of NOLs, fixed assets, intangibles, and various 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. We generally complete our review for new tax attributes from assets when applicable, but generally as new assets are placed into service.

Included within our deferred tax assets are various energy-related federal tax credits totaling $17,339. This total is primarily comprised of approximately $14,663 in IRC code section 45 production tax credits from our applicable facilities. We also have recorded approximately $923 and estimated $1,753 in IRC code section 48 investment tax credits from our previous Pico digestion expansion and second Apex RNG facility, respectively, although our conclusions on the tax credits from our second Apex RNG facility are not finalized.

When placed into service, Montauk Ag Renewables will generate primarily a mix federal investment tax and production tax credits and North Carolina state tax attributes. Based on past experience with other large and qualifying projects, we believe that 50-75% of project capital will quality for IRC code section 48 investment tax credits and, depending on a variety of factors for projects started within various safe harbor guidelines, the tax benefits could be up to 30%. For qualifying projects that do not meet the various safe harbor guidelines, we expect the tax benefits to range between 6-12% for qualifying assets. As it relates to our capital expenditures and future electric power production, we estimate IRC code section 48 investment tax credits and section 45 production tax credits could range between $6,000 - $20,000, collectively. We give no assurances that our estimates on tax attributes for our Montauk Ag Renewables project will meet these expectations but expect to begin reviews of federal tax attributes and continue our review for North Carolina state income and property tax attributes in 2026.

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 complete a full analysis annually of our deferred tax assets and liabilities. We expect our New Senior Credit Facility could generate additional tax attributes related to interest expense limitations under applicable IRC code section 163(j). We continue to review our future tax planning including but not limited to the ability to stack tax attributes, limitation on deductibility and expiration, but we do not currently expect to transfer, as applicable, any tax attributes generated.

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 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. Corporate also includes revenues from RINs distributed from GreenWave which are not included in our operating metrics table. 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.

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•

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 entered into pathway renewals in the third quarter of 2025 for certain volumes at percentages consistent with our historical percentages. Historically, we have monetized less than 25% of our RNG volumes under these fixed-price agreements.

•

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.

•

Corporate and other revenues: Corporate reports realized and unrealized gains or losses under our gas hedge programs. We do 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. Includes revenues from RINs distributed from GreenWave which are not included in our operating metrics table.

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 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 throughout 2026.

•

Wellfield extraction environmental factors continue to impact gas extraction at our Apex site. We are collaborating with the landfill to mitigate these impacts and these mitigation efforts have continued in 2026. These wellfield extraction environmental factors could impact and lengthen the period during which we have excess available combined production capacity at our Apex site.

•

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. We expect these trends to continue through 2026.

•

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 our McCarty project, we have an operating and management agreement by which we earn revenue for managing the wellfield collection system. 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 increases. Delays in commencement of production or extended commissioning issues at a new project or a

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conversion project, such as those we are currently experiencing at Blue Granite, 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 separated. We have entered into commitments to transfer a significant portion of RINs generated and available for sale from 2026 RNG production at an average price of $2.42. 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.

•

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. Expenses from RINs distributed from GreenWave and the costs related to pathway dispensing are not included in our operating metrics table but are recorded within Operating and Maintenance Expenses.

•

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 2026. We account for share-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. For more information, see Note 15 to our unaudited condensed consolidated financial statements related to share-based compensation.

•

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.

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•

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 may carry-over a portion of the RINs generated or separated 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, 2026 and 2025

The following table summarizes the key operating metrics described above, which are metrics we use to measure performance. Results related to our GreenWave joint venture are excluded from the table below.


	Three Months Ended March 31,									Change
	2026			2025			Change			%
(in thousands, unless otherwise indicated)
Revenues
Renewable Natural Gas Total Revenues	$	38,075		$	38,451		$	(376	)		(1.0	%)
Renewable Electricity Generation Total Revenues	$	4,117		$	4,152		$	(35	)		(0.8	%)

RNG Metrics
CY RNG production volumes (MMBtu)		1,354			1,389			(35	)		(2.5	%)
Less: Current period RNG volumes under fixed/floor-price contracts		(89	)		(496	)		407			(82.1	%)
Plus: Prior period RNG volumes dispensed in current period		354			291			63			21.6	%
Less: Current period RNG production volumes not dispensed		(431	)		(336	)		(95	)		28.3	%
Total RNG volumes available for RIN generation (1)		1,188			848			340			40.1	%

RIN Metrics
Current RIN generation ( x 11.6935) (2)		13,882			9,932			3,950			39.8	%
Less: Counterparty share (RINs)		(1,425	)		(1,471	)		46			(3.1	%)
Plus: Prior period RINs carried into current period		190			6,822			(6,632	)		(97.2	%)
Less: RINs generated but unseparated		(165	)		(1,482	)		1,317			(88.9	%)
Total RINs available for sale (3)		12,482			13,801			(1,319	)		(9.6	%)
Less: RINs sold		(12,403	)		(9,885	)		(2,518	)		25.5	%
RIN Inventory		79			3,916			(3,837	)		(98.0	%)
RNG Inventory (volumes not dispensed for RINs) (4)		431			336			95			28.3	%
Average Realized RIN price	$	2.42		$	2.46		$	(0.04	)		(1.6	%)

Operating Expenses
Renewable Natural Gas Operating Expenses	$	21,934		$	21,204		$	730			3.4	%
Operating Expenses per MMBtu (actual)	$	16.20		$	15.26		$	0.94			6.2	%

REG Operating Expenses	$	4,940		$	3,808		$	1,132			29.7	%
$/MWh (actual)	$	114.88		$	82.78		$	32.10			38.8	%

Other Metrics
Renewable Electricity Generation Volumes Produced (MWh)		43			46			(3	)		(6.5	%)
Average Realized Price $/MWh (actual)	$	95.74		$	90.26		$	5.48			6.1	%

(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 (loss) for the periods set forth below:


	Three Months Ended March 31,									Change
	2026			2025			Change			%
Total operating revenues	$	46,428		$	42,603		$	3,825			9.0	%
Operating expenses:
Operating and maintenance expenses		23,155			17,557			5,598			31.9	%
General and administrative expenses		8,019			8,754			(735	)		(8.4	)%
Royalties, transportation, gathering and production fuel		8,037			7,571			466			6.2	%
Depreciation, depletion and amortization		8,373			6,264			2,109			33.7	%
Impairment loss		443			2,047			(1,604	)		(78.4	)%
Total operating expenses		48,027			42,193			5,834			13.8	%
Operating (loss) income	$	(1,599	)	$	410		$	(2,009	)		(490.0	)%
Other (income) expenses:		(1,306	)		1,191			(2,497	)		(209.7	)%
Loss before income taxes:		(293	)		(781	)		488			(62.5	)%
Income tax benefit		(298	)		(317	)		19			(6.0	)%
Net income (loss)	$	5		$	(464	)	$	469			(101.1	)%

Revenues for the Three Months Ended March 31, 2026 and 2025

Total revenues in the first quarter of 2026 were $46,428, an increase of $3,825 (9.0%) compared to $42,603 in the first quarter of 2025. The increase is related to environmental attribute revenues of approximately $4,236 from RINs sold related to the distribution of RINs from our GreenWave joint venture which had no RINs distributed and sold in the first quarter of 2025. Our first quarter of 2026 RNG volumes sold under fixed/floor-price contracts decreased approximately 82.1% as compared to first quarter of 2025 as a result of the expiration of fixed price pathway contract expiration. Our RNG commodity revenue decreased approximately 49.3% which was offset by an increase in RINs sold of 25.5%.

Renewable Natural Gas Revenues

We produced 1,354 MMBtu of RNG during the first quarter of 2026, a decrease of 35 MMBtu (2.5%) compared to 1,389 MMBtu produced in the first quarter of 2025. Our Galveston facility produced 41 MMBtu fewer in the first quarter of 2026 compared to the first quarter of 2025 as a result of landfill host assuming responsibility of wellfield operations and maintenance beginning in the first quarter of 2026. Our McCarty facility produced 88 MMBtu fewer in the first quarter of 2026 compared to the first quarter of 2025 as a result of landfill host wellfield bifurcation and changes to the wellfield collection system. Our Atascocita facility produced 43 MMBtu more in the first quarter of 2026 compared to the first quarter of 2025 as a result of landfill host wellfield operational and collection system enhancements. Our Apex facility produced 37 MMBtu more in the first quarter of 2026 as compared to first quarter of 2025 as a result of the June 2025 commissioning of our second Apex facility and increased feedstock gas from improvements we are making to the landfill collection system.

Revenues from the Renewable Natural Gas segment in the first quarter of 2026 were $38,075, a decrease of $376 (1.0%) compared to $38,451 in the first quarter of 2025. Average commodity pricing for natural gas for the first quarter of 2026 was $5.04 per MMBtu, 38.1% higher than the first quarter of 2025. During the first quarter of 2026, we self-marketed 12,403 RINs, representing a 2,518 increase (25.5%) compared to 9,885 in the first quarter of 2025. Average pricing realized on RIN sales during the first quarter of 2026 was $2.42 as compared to $2.46 in the first quarter of 2025, a decrease of 1.7%. Average D3 RIN index price for the first quarter of 2026 was $2.41 compared to $2.43 in the first quarter of 2025, a decrease of approximately 0.6%. At March 31, 2026, we had approximately 431 MMBtu available for RIN generation, 165 RINs generated and unseparated, and 79 RINs generated and unsold. 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.

Renewable Electricity Generation Revenues

We produced approximately 43 MWh in Renewable Electricity in the first quarter of 2026, a decrease of 3 MWh (6.5%) from 46 MWh in the first quarter of 2025. Our Pico facility produced approximately 2 MWh fewer in the first quarter of 2026 compared to the first quarter of 2025. The decrease is primarily related to decommissioning of one our engines in the second quarter of 2025 due to the shift towards boiler heat for our digestion process. Our Bowerman facility produced approximately 1 MWh fewer in the first quarter of 2026 compared to the first quarter of 2025. The decrease is primarily related to original equipment manufacturer required lifecycle maintenance on our engines, beginning in the first quarter of 2026.

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Revenues from Renewable Electricity facilities in the first quarter of 2026 were $4,117, a decrease of $35 (0.8%) compared to $4,152 in the first quarter of 2025. The decrease was primarily driven by the decrease in production volumes.

In the first quarter of 2026, 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 2025. This provides us with certainty of price resulting from our Renewable Electricity sites.

General and Administrative Revenues

We recorded approximately $4,236 in the first quarter of 2026 related to RINs distributed from our joint venture, GreenWave. We sold approximately 1,755 RINs distributed from GreenWave and the RINs related to pathway dispensing, which are not included within our operating metrics table.

Expenses for the Three Months Ended March 31, 2026 and 2025

General and Administrative Expenses

Total general and administrative expenses in the first quarter of 2026 were $8,019, a decrease of $735 (8.4%) compared to $8,754 in the first quarter of 2025. The decrease is primarily related to the vesting of certain restricted share awards in 2025. Our corporate insurance fees decreased approximately $261 in first quarter of 2026 as compared to first quarter of 2025

Operating and Maintenance Expenses

Total operating and maintenance expenses in the first quarter of 2026 were $23,155, an increase of $5,598 (31.9%) compared to $17,557 in the first quarter of 2025.

We recorded approximately $4,247 in the first quarter of 2026 related to the cost of RINs distributed from GreenWave and the costs related to pathway dispensing associated with our dispensing RNG in exclusive unique and proprietary pathways, which are not included within our operating metrics table. There were no such expenses incurred during the first quarter of 2025.

Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in the first quarter of 2026 were $14,353, an increase of $263 (1.9%) as compared to $14,090 in the first quarter of 2025. Our Rumpke facility operating and maintenance expenses increased approximately $397 primarily related to preventative maintenance media changes. Our Apex facility operating and maintenance expenses increased approximately $262 primarily related to increased utility expense which was partially offset by decreased preventative maintenance media changes. Our Atascocita facility operating and maintenance expenses increased approximately $246 primarily related to wellfield operational enhancements. Offsetting the increase was our Galveston facility operating and maintenance expenses which decreased approximately $580. The decrease is primarily due to the timing of maintenance of gas processing equipment and preventative maintenance media changes.

Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in the first quarter of 2026 were $4,484, an increase of $1,133 (33.8%) compared to $3,351 in the first quarter of 2025. The increase is primarily driven by an increase in non-capitalizable costs of approximately $808 at our Montauk Ag Renewables project. Our Bowerman facility operating and maintenance expenses increased approximately $371 primarily related to timing of gas processing preventative maintenance.

Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in the first quarter of 2026 were $8,037, an increase of $466 (6.2%) compared to $7,571 in the first quarter of 2025. 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.

Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the first quarter of 2026 were $7,581, an increase of $467 (6.6%) compared to $7,114 in the first quarter of 2025. There was a reduction to our Pico earnout that was recorded in the first quarter of 2025. We settled the Pico earnout obligation in fourth quarter of 2025. Royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues to 19.9% for the first quarter of 2026 from 18.5% in the first quarter of 2025.

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Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the first quarter of 2026 were $456, a decrease of $1 (0.2%) compared to $457 in the first quarter of 2025. Royalties, transportation, gathering and production fuel expenses increased as a percentage of Renewable Electricity revenues to 11.1 % for the first quarter of 2026 from 11.0% in the first quarter of 2025.

Depreciation

Depreciation and amortization in the first quarter of 2026 was $8,373, an increase of $2,109 (33.7%) compared to $6,264 in the first quarter of 2025. The increase was primarily driven by the timing of wellfield and maintenance capital investments placed into service and our Second Apex RNG Facility project being placed into service.

Impairment loss

We calculated and recorded impairment losses of $443 in the first quarter of 2026, a decrease of $1,604 (78.4%) compared to $2,047 in the first quarter of 2025. The decrease primarily relates to the impairment of an RNG development project for which the local utility no longer accepted RNG into its distribution system in specifically identified assets deemed obsolete or non-operable.

Other (Income) Expenses

Other income in the first quarter of 2026 was $1,306, an increase of $2,497 (209.7%) compared to other expenses of $1,191 in the first quarter of 2025. In the first quarter of 2026, we recorded approximately $3,320 in income related to our joint venture investment in GreenWave. There was no such income reported during the first quarter of 2025. Also in the first quarter of 2026, we recorded approximately $944 in debt extinguishment costs from refinancing our credit agreement.

Income Tax Benefit

Income tax benefit for the three months ended March 31, 2026 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 as well as stock based compensation.

The effective tax rate of 101.4% for the three months ended March 31, 2026 was higher than the rate for the three months ended March 31, 2025 of 40.6% primarily due to the change in our pre-tax book loss for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025.

Operating (Loss) Income for the Three Months Ended March 31, 2026 and 2025

Operating loss in the first quarter of 2026 was $1,599 compared to operating income of $410 in the first quarter of 2025. RNG operating income for the first quarter of 2026 was $8,745, a decrease of $1,624 (15.7%) compared to $10,369 in the first quarter of 2025. Renewable Electricity Generation operating loss for the first quarter of 2026 was $2,171, an increase of $1,150 (112.6%) compared to $1,021 for the first quarter of 2025.

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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 income (loss) 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 income (loss), which is the most directly comparable GAAP measure, for the three months ended March 31, 2026 and 2025:


	Three Months Ended March 31,
	2026			2025
Net income (loss)	$	5		$	(464	)
Depreciation, depletion and amortization		8,373			6,264
Interest expense		1,336			1,243
Income tax benefit		(298	)		(317	)
Consolidated EBITDA		9,416			6,726

Impairment loss (1)		443			2,047
Loss on extinguishment of debt		944			—
Net (gain) loss on sale or disposal of assets		(13	)		15
Adjusted EBITDA	$	10,790		$	8,788

(1)

We recorded impairment losses of $443 and $2,047 for the three months ended March 31, 2026 and 2025, respectively. The impairment losses recorded in first three months of 2026 relate to specifically identified assets deemed obsolete or non-operable. The impairment losses recorded in first three months of 2025 primarily relate to an RNG interconnection impairment at our Blue Granite RNG project.

Liquidity and Capital Resources

Sources of Liquidity

At March 31, 2026 and March 31, 2025, our cash and cash equivalents, net of restricted cash, was $25,947 and $40,111, 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, 2026, we had debt before debt issuance costs of $155,000, compared to debt before debt issuance costs of $56,000 at December 31, 2025.

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


	March 31, 2026		December 31, 2025
Term loan	$	155,000		44,000
Revolving credit facility	—			85,000
Debt before debt issuance costs	$	155,000	$	129,000

New Senior Credit Facility

On March 9, 2026, we entered into a five year New Senior Credit Facility with HASI that provides up to $200,000 in senior indebtedness. The New Senior Credit Facility has a 24 month availability period during which only interest is payable quarterly. After the availability period, we will be subject to quarterly principal payments equal to 1.25% of the total outstanding principal balance. The New Senior Credit Facility has an interest rate of 10.25% and matures in 2031.

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The New Senior Credit Facility is subject to customary financial covenants. The New Senior Credit Facility 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 is less than $1.00 per RIN and (y) the consolidated average quarterly trailing EBITDA over the previous four quarters is less than $10,000. The New Senior Credit Facility includes various affirmative and negative covenants that require us to meet specified financial ratios and financial tests, as defined in the underlying agreement.

Under the New Senior Credit Facility, we are required to maintain the following as defined in the underlying agreement:

•

Total Net Leverage Ratio of not more than 4.00 to 1.00,

•

As of the end of each fiscal quarter, a Fixed Charge Coverage Ratio of not less than 1.20 to 1.00, and

•

Various other financial covenants or mandatory prepayments

The New Senior Credit Facility financial debt covenants commence June 30, 2026.

Under the prior amended credit agreement, as of December 31, 2025, $44,000 was outstanding under the term loan and we had $85,000 of outstanding borrowings under the revolving credit facility. The proceeds from the New Senior Credit Facility were used to repay all outstanding debt as of March 9, 2026.

As of March 9, 2026, $155,000 was outstanding under the New Senior Credit Facility.

For additional information regarding the New Senior Credit Facility, see Note 13— 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 2026 capital expenditures to range between $20,000 and $25,000. Our 2026 non- development capital plans include preventative maintenance expenditures, wellfield expansion projects, critical spare expenditures, other specific facility improvements, and information technology improvements. Additionally, included in our 2026 non-development capital expenditures are original equipment manufacturer required lifecycle expenditures on our engines at our Bowerman facility. We expect these lifecycle expenditures at our Bowerman facility to continue through 2027. We currently estimate that our existing 2026 development capital expenditures will range between $80,000 and $100,000. Our ongoing 2026 development capital expenditures relate to the development of Montauk Ag Renewables, Bowerman RNG project, our Rumpke RNG Relocation Project, Atascocita CO2 and Tulsa RNG project. The reduction of 2026 development capital expenditures is primarily driven by the timing of our CO2 project development and the refinement of long lead milestone payments. We believe that our credit refinancing with HASI will afford us increased flexibility with securing project based additional financing for our in progress development projects. We believe that our existing cash and cash equivalents, cash generated from operations, and credit availability under our New Senior Credit Facility will meet our debt service obligations and anticipated required capital expenditures (including for projects under development) for the next 12 to 24 months.

Cash Flow

The following table presents information regarding our cash flows and cash equivalents for the three months ended March 31, 2026 and 2025:


	Three Months Ended March 31,
	2026			2025
Net cash provided by (used in):
Operating activities	$	15,846		$	9,140
Investing activities		(30,834	)		(11,632	)
Financing activities		19,478			(3,018	)
Net increase (decrease) in cash and cash equivalents and restricted cash		4,490			(5,510	)
Restricted cash, end of the period		2,733			383
Cash and cash equivalents, end of period		28,680			40,494

For the first three months of 2026, we generated $15,846 of cash provided by operating activities compared to $9,140 in the first three months of 2025. For the first three months of 2026, income and adjustments to income from operating activities provided $10,545 compared to income and adjustments to income providing $8,807 in first three months of 2025. Working capital and other assets and liabilities provided $5,300 in the first three months of 2026 compared to working capital and other assets and liabilities providing $333 in the first three months of 2025.

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 2026 were $38,644, of which $33,145 and $1,752, were related to the Montauk Ag

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Renewables in North Carolina and Bowerman RNG, respectively. Our capital expenditure cash payments were $30,867. The variance is primarily driven by the timing differences related to capital expenditures in accounts payable.

Our net cash flows provided by financing activities of $19,478 for the first three months of 2026, increased $22,496, compared to cash used in financing activities in the first three months of 2025 of $3,018 as a result of proceeds received from our revolving credit agreement.

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 9 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 13 in the unaudited condensed consolidated financial statements for further discussion of the contractual commitments under our debt agreements. During the first three months of 2026, we had $2,185 of outstanding letters of credit. There have been no draw downs on these outstanding letters of credit. During the first three months of 2025, we did not have off-balance sheet arrangements other than outstanding letters of credit of $2,185.

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 19 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 1-17 years. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,746.

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, medium and long 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 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

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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 California and Oklahoma. 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 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 cash flows 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

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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 an impairment of $443 and $2,047 for the three months ended March 31, 2026 and 2025, 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. We will lose our emerging growth company status on December 31, 2026. As a result, we will no longer be permitted to take advantage of certain reduced disclosure and other requirements applicable to emerging growth companies, including the ability to delay the adoption of new or revised accounting standards.

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

Interest Rate Risk

On March 9, 2026, we repaid in full all outstanding borrowings under the Amended Credit Facility in connection with entering into the New Senior Credit Facility. As a result, we no longer have exposure to variable interest rate risk associated with the Amended Credit Facility.

The New Senior Credit Facility bears interest at a fixed rate of 10.25%. Based on our current expectations regarding borrowings under this facility, we do not expect to have material exposure to changes in market interest rates with respect to amounts outstanding under the New Senior Credit Facility. However, our actual exposure may differ from current expectations depending on, among other factors, future borrowings, potential amendments to the terms of the facility, or the incurrence of additional variable-rate indebtedness.

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

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 2025 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 6, 2026	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)