Montauk Renewables (NASDAQ: MNTK) outlines RNG projects and risks
Rhea-AI Filing Summary
Montauk Renewables, Inc. files its annual report describing a large U.S. renewable natural gas and electricity platform built on landfill and agricultural biogas. The company operates 11 RNG and two Renewable Electricity projects across several states, selling both commodity energy and high‑value environmental credits such as RINs, LCFS credits and RECs.
Strategy centers on expanding agricultural feedstocks, optimizing existing sites, and developing new projects, including the Montauk Ag swine-waste project in North Carolina and an expanded dairy digester in Idaho. Key risks include project output shortfalls, severe weather, heavy reliance on a few projects and customers, evolving EPA and CARB rules for RINs and LCFS credits, and potential reductions in government incentives.
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐
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.
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).
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:
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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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No
The aggregate market value of common stock held by non-affiliates of the registrant, based on the closing price for the registrant’s common stock on the Nasdaq Capital Market on June 30, 2025, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $
The number of outstanding shares of the registrant’s common stock on March 6, 2026 was
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated herein by reference from the registrant’s definitive proxy statement relating to the registrant’s Annual Meeting of Shareholders to be held in 2026 (the “Proxy Statement”), which definitive proxy statement shall be filed with the Securities and Exchange Commission not later than 120 days after the end of the fiscal year to which this report relates.
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TABLE OF CONTENTS
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PART I |
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ITEM 1. |
BUSINESS |
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ITEM 1A. |
RISK FACTORS |
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ITEM 1B. |
UNRESOLVED STAFF COMMENTS |
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CYBERSECURITY |
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PROPERTIES |
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LEGAL PROCEEDINGS |
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MINE SAFETY DISCLOSURES |
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PART II |
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MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
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RESERVED |
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
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CONTROLS AND PROCEDURES |
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OTHER INFORMATION |
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DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS |
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DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
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EXECUTIVE COMPENSATION |
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
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PRINCIPAL ACCOUNTING FEES AND SERVICES |
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EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
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FORM 10-K SUMMARY |
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Glossary of Key Terms
This Annual Report on Form 10-K 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 Annual Report on Form 10-K to:
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Cautionary Note Regarding Forward-Looking Statements
This Annual Report on Form 10-K 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 delivery of biogenic carbon dioxide volumes to European Energy, 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:
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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.
See the “Risk Factors” section and elsewhere in this report for a more complete discussion of the risks and uncertainties mentioned above and for discussion of other risks and uncertainties we face that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements as well as others made in our other Securities and Exchange Commission (“SEC”) filings and public communications. You should evaluate all forward-looking statements made by us in the context of these risks and uncertainties.
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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Summary of Risks Associated with Our Business
Our business is subject to a number of risks and uncertainties, including those highlighted in the section titled “Risk Factors” in this Annual Report on Form 10-K. Some of these principal risks include the following:
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PART I
ITEM 1. BUSINESS.
Unless the context requires otherwise, references to “Montauk,” the “Company,” “we,” “us” or “our” refer to Montauk Renewables, Inc. and its consolidated subsidiaries. Additionally, amounts are in thousands unless indicated otherwise.
Overview
We are a renewable energy company specializing in the recovery and processing of biogas from landfills and other non-fossil fuel sources to beneficial use as a replacement to fossil fuels. We develop, own, and operate RNG projects, using proven technologies that supply renewable fuel into the transportation and electrical power sectors. We are one of the largest U.S. producers of RNG, having participated in the industry for over 30 years. We established our currently operating portfolio of eleven RNG and two Renewable Electricity projects and development projects through self-development, partnerships, and acquisitions that span seven states.
In January 2021, we closed the initial public offering of our common stock on the Nasdaq Capital Market with the shares traded under the symbol “MNTK.” Our common stock is also secondarily listed on the Johannesburg Stock Exchange under the trading symbol “MKR.”
Products Sold
The revenues Montauk receives from selling renewable energy consist of two main components. The first component consists of revenues from the commodity value of the natural gas or electricity generated, which we sell through a variety of term-length agreements. The second component consists of revenues from the Environmental Attributes derived from the production of RNG and Renewable Electricity.
Our current operating projects produce either RNG or Renewable Electricity by processing biogas from landfill sites or agricultural waste from livestock farms. 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. Once collected, biogas can be processed into pipeline-quality RNG or converted into electricity. The conversion facility is typically located on landfill property away from the active fill operations where additional waste is added to the landfill site. Because we are capturing waste methane and making use of a renewable source of energy, the RNG and Renewable Electricity we produce also generates valuable Environmental Attributes which we can monetize under federal and state renewable initiatives.
RNG
The RNG we process is pipeline-quality and can be used for transportation fuel when compressed or liquefied. Virtually all of the RNG we produce is used as a transportation fuel because this market generally provides the most value for our RNG production. CNG has been the most common fuel used by fleets where medium-duty trucks are close to the fueling station, such as city fleets, local delivery trucks and waste haulers. Additionally, landfill gas and gas from livestock digesters can be processed into pipeline-quality RNG by removing the majority of the non-methane components including carbon dioxide, water, sulfur, nitrogen, and other trace compounds.
RNG, like traditional natural gas, is traded nationally. Once in an interstate pipeline, RNG can be transported to vehicle fueling stations to be used as a transportation fuel, to utilities to generate power, or for use in generating fuel cell energy anywhere within the North American pipeline system. This flexibility enables us to capture value from the renewable attributes of biogas by delivering RNG to markets and customers that place a premium on renewable energy. Although RNG has the same chemical composition as natural gas from fossil sources, government incentive programs assign unique Environmental Attributes to it due to its origin from low-carbon, renewable sources, which we also monetize.
RNG is priced in-line with the wholesale natural gas market, based on Henry Hub pricing, with regional variation according to demand. We sell the RNG produced from our projects under a variety of short-term and medium-term agreements to counterparties, with tenures generally varying from three to five years. Our contracts with counterparties are typically structured to be based on varying natural gas price indices for the RNG produced. We also share a portion of our Environmental Attributes with certain pathway providers as consideration for the counterparty using our RNG as a transportation fuel.
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Renewable Electricity
Renewable electricity is generated using gas-fueled engines or turbine-driven electrical generators, which are designed to operate efficiently on medium-Btu gas. As such, electricity generation typically involves producing medium-Btu gas, which is then pumped into a generating facility. Electricity is a commodity that trades and is priced on a regional basis in and among regional control areas. Pricing for commodity-sold electricity can be based on day-ahead prices for scheduled deliveries or hourly, real-time prices for unscheduled deliveries. Prices vary across the country based on weather, load patterns and local or regional power and transmission restrictions. The Renewable Electricity produced at our biogas-to-electricity projects is sold under long-term contracts to creditworthy counterparties, typically under a fixed price with escalators. The terms of these contracts range up to 18 years, excluding renewal periods, with a weighted average remaining tenure of 16 years, based on 2025 electricity production.
Environmental Attributes
When used as a transportation fuel or to produce electricity, RNG can generate additional revenue streams through the generation and sale of Environmental Attributes under various programs, including the national renewable fuels standard and state-level California LCFS. The Environmental Attributes that we generate and sell are composed of RINs and LCFS credits, which are generated from the conversion of biogas to RNG that is used as a transportation fuel, as well as RECs generated from the conversion of biogas to Renewable Electricity. In addition to revenues generated from our product sales, we also generate revenues by providing various value-added services to certain of our biogas site partners. In 2025 and 2024, our projects generated approximately 4.6% and 6.2%, respectively, of all CNG and LNG D3 RINs in the United States. During 2021, we entered into an agreement to sell a portion of our production as a renewable component of refinery fuel exports into the European Union’s Renewable Energy Directive from certain RNG production facilities that have achieved International Sustainability & Carbon Certification registration. This diversification strategy accounted for approximately 0.9% of the reduction in generation of D3 RINs in 2025. We continue to sell a portion of our production as a renewable component of refinery fuel exports.
We seek to mitigate our exposure to commodity and Environmental Attribute pricing volatility. Through contractual arrangements with our site hosts and counterparties, we typically share pricing and production risks while retaining our ability to benefit from potential upside. A portion of the RNG volume we produce is sold under bundled fixed-price arrangements for the RNG and Environmental Attributes, some of which include a sharing arrangement where we benefit from prices above certain thresholds. For our remaining RNG projects, our partners may receive a cash payment instead of in-kind sharing arrangements where our partners receive the Environmental Attributes, thereby sharing in Environmental Attribute pricing risk.
On the electricity side of our business, all of our products and related Environmental Attributes are sold under fixed-price contracts with escalators, limiting our pricing risk. Finally, our contracts with site hosts often require payments to our site hosts in the form of royalties based on realized revenues, direct development contributions, or, in some select cases, based on production volumes.
D3 RINs
RNG has the same chemical composition as natural gas from fossil sources, but has unique Environmental Attributes assigned to it due to its origin from organic sources. These attributes qualify RNG as a renewable fuel under the federal RFS program, established pursuant to the EPACT 2005 and EISA, allowing RNG to generate renewable fuel credits called RINs when the RNG is used as a transportation fuel.
RINs are saleable regulatory credits that represent a quantity of qualifying fuel and are used by refiners and importers to evidence compliance with their RFS obligations. Given that the RFS is a national program, the price of a RIN is the same anywhere in the United States. The RFS program originally contemplated 1.75 billion gallons of fuel from cellulosic biofuels by 2014, the use of which would be tracked through D3 RINs. However, cellulosic biofuel production grew slower than expected and prompted the EPA to expand the definition of biofuels that could qualify for D3 RINs to include fuels from cellulosic biogas, including biogas from landfills, livestock farms, and WRRFs. This significantly increased the quantity of D3 RINs produced, with production increasing to approximately 33 million net RINs in 2014 and approximately 923 million net RINs in 2024. In addition, given the historic shortage in supply of D3 RINs to meet blending requirements, the EPA allows obligated refiners to satisfy RFS compliance obligations for D3 RINs by either purchasing CWC plus D5 RINs or by purchasing D3 RINs. CWC prices were set annually and were typically published by the EPA each November. Historically, the value of a D3 RIN is therefore a derivative of the market price for D5 RINs and CWCs, which in turn, are inversely linked to the wholesale price of gasoline. On July 12, 2023, the EPA issued final rules in the Federal Register which indicated that it will not be utilizing its cellulosic waiver authority to reduce cellulosic biofuel volume for 2023-2025, thus CWCs will not be available unless actual production is lower than the RVO. On December 5, 2024, the EPA proposed rules to partially waive the 2024 cellulosic biofuel volume requirement using the general waiver authority and revise the associated percentage standard under the RFS. This rule was finalized on July 7, 2025. The EPA made CWCs available for purchase under the final rule along with the partial waiver of the 2024 cellulosic biofuel volume requirement. The final rule also requires the use of a new data source for the average wholesale price of gasoline to be used in the calculation of the CWC price.
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The EPA proposed the 2026 and 2027 RVOs, and a Partial Waiver of the 2025 Cellulosic Biofuel Volume Requirement on June 17, 2025. On August 22, 2025, the EPA issued decisions on 175 Small Refinery Exemptions (SREs) for the years 2023-2025. EPA subsequently proposed a Supplemental Rule (referred to as the SRE reallocation volume) on September 18, 2025, which would account for the for 2023-2025 exempted RVOs. EPA co-proposed SRE reallocation volumes that would account for 100 percent or 50 percent of the exemptions granted for the 2023-2025 compliance years. EPA is aiming to finalize new biofuel mandates for 2025, 2026 and 2027 along with the Supplemental Rule in late March 2026.
We have been active in the RFS program since 2014 and expect to remain a significant contributor to the overall generation of RINs from RNG. We monetize our portion of the RINs, directly, at auction or through third-party agents or marketers.
CA LCFS
CA LCFS credits are environmental credits generated in California in order to stimulate the use of cleaner, low-carbon fuels. This program encourages the production of low-carbon fuels by setting annual CI standards, which are intended to reduce GHG emissions from the state’s transportation sector. One of the key aspects of the program is that it encourages the use of low-carbon transportation fuel, such as CNG, in vehicles instead of gasoline. This program further encourages use of renewable fuels in vehicles over CNG from fossil fuels.
The value of an CA LCFS credit varies according to the CI value of the fuel source as determined by CARB. Fuels that have a lower CI score benefit from a higher percentage of a CA LCFS credit. RNG from LFG and livestock digester biogas that are used as a transportation fuel both qualify for CA LCFS credits. The number of CA LCFS credits for RNG from livestock digesters is significantly higher than the number of CA LCFS credits for RNG from landfills, due to the relative CI scores of the two fuels. Fuel that is eligible for RINs can also receive CA LCFS credits. As a result, CA LCFS credits represent a revenue stream incremental to the value RNG producers receive for RINs. For livestock digester RNG projects, CA LCFS credits are a substantial revenue driver. We have one project that is currently approved and eligible to earn CA LCFS credits, which is a livestock digester RNG project. Because of the growth in the number of RNG projects developed in 2023-2025, the CA LCFS program has been saturated in credits. As a result, the lower CI score projects (e.g. livestock digester RNG projects) have the financial advantage of being accepted into the LCFS program. The revenue generated by CA LCFS credits will increase as we continue to develop dairy or livestock manure projects as long as construction on these type of projects is started before December 31, 2029. The LCFS program includes a targeted phase-out of all “avoided methane” credits for dairy and livestock manure projects by 2040.
On January 3, 2025, CARB submitted to the State of California Office of Administrative Law proposed amendments to the LCFS regulations. California’s amended LCFS regulations officially took effect on July 1, 2025, setting more aggressive carbon intensity reduction targets, 30% by 2030 and 90% by 2045.
Several states in the United States also have or are considering adopting this model. Oregon’s Clean Fuels Program, enacted in 2009 and implemented in 2016, operates using a credit system similar to the CA LCFS program. Washington’s Clean Fuel Standard was passed in 2021 and implemented in 2023 utilizing a similar credit system as Oregon and California. New Mexico’s Clean Fuel Standard was passed in 2024 with plans to finalize implementation in 2026. Similar to RINs, LCFS credits can be sold separately from the RNG fuel sold, allowing us to monetize LCFS credits for fuel produced and purchased outside of states that have LCFS programs.
RECs
The primary Environmental Attributes derived from the production of electricity from renewable resources are RECs, which translate into additional revenues for units of Renewable Electricity produced. Biogas is considered to be a renewable resource in all 37 states that encourage or mandate the use of renewable energy. Thirty states, the District of Columbia, and Puerto Rico have RPS that require utilities to supply a percentage of power from renewable resources, and seven states have a Renewable Portfolio Goal that is similar to RPS, but it is an objective or goal and not a requirement. Many states allow utilities to comply with RPS through tradable RECs, which provide an additional revenue stream to RNG projects that produce electricity from biogas.
The value of a REC is dependent on each state’s renewable energy requirements as mandated by its RPS. REC values are higher in states that require a percentage of total electricity to come from renewable resources. In states with no renewable energy requirements, RECs can have no value at all. In some markets, we have entered into PPAs under which we sell RECs bundled with the power being sold at a combined price. This occurs where the utility off-take counterparty offers a combined rate for the renewable energy it needs to satisfy RPS or other business requirements that is the best combined price for one of our projects.
Strategic Overview
Our business strategy focuses on the following three areas that we believe present the greatest growth opportunities for the Company at this time.
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Continued Expansion into Agricultural Feedstocks for RNG Production
As part of our long-term strategy, we are focused on diversifying our project portfolio beyond LFG through expansion into additional methane producing assets, while opportunistically adding third-party developed technology capabilities to boost financial performance and our overall cost competitiveness. We are commercially operating our first agricultural waste project (dairy manure), actively pursuing new fuel supply opportunities in WRRFs, and looking at long-term organic waste and sludge opportunities for the generation of biogas.
We view dairy farms and other forms of organic agricultural waste as a significant opportunity for us to expand our RNG business, as processing biogas from dairy farms and from other forms of organic agricultural waste requires similar expertise and capabilities as processing biogas from landfills. Many of the existing biogas processing in these industries is for electricity production, which creates additional opportunities for acquisition and conversion to higher-value RNG facilities.
Pico Facility
We undertook an agricultural project when we closed on the acquisition of Pico, the anaerobic digester and two Jenbacher engines at the Bettencourt dairy farm in Jerome, Idaho in September 2018. The project sources manure from a dairy farm with up to approximately 18,500 milking cows. While Pico was initially a Renewable Electricity site, we brought an RNG facility at that location online in 2020. The facility sells transportation fuel into the California transportation market. The collection of the fuel supply is potentially easier at dairy farms than at landfills due to higher quality, more uniform feedstock, and potentially less volatility in inlet gas and biogas collection in a more controlled environment. During the second quarter of 2021, we amended our Pico feedstock agreement (“Pico Feedstock Amendment”). The amendment increased the amount of feedstock supplied to the facility for processing over a four-year period.
As part of our overall capacity expansion at the Pico facility, in 2021 and 2024, we undertook significant efforts to improve the performance of the existing digestion process at our Pico facility. We temporarily idled RNG production at this facility in order to clean out settled solids in the digester, replace the cover of the digester, and make various other efficiency improvements. The dairy began delivering the first and second increases in feedstock during the third quarter of 2022 and we have made two payments to the dairy as required in the Pico Feedstock Amendment. The improved efficiencies of our existing digestion process and the water management improvements have enabled us to process the increased feedstock volumes. We completed the design of the digestion capacity expansion project in 2022, commenced construction of the digestion expansion, and commissioned the digestion expansion project in 2024. In 2025, we made the final payment to the dairy as required under the Pico Feedstock Amendment and the dairy began delivering the final increase in feedstock volumes.
CARB finalized in the first quarter of 2023 Pico's initial CI Score Pathway model. We have been recognizing revenues from RINs and LCFS credits since the fourth quarter of 2022.
As a result of the 2025 Annual Fuel Pathway Report ("AFPR") review, our CI score worsened. The worsening CI score is primarily due to increased biogas upgrading and fugitive emissions from the biogas upgrading process. We are currently conducting an analysis to determine the benefit of installing a combustion device to eliminate fugitive emissions. As a result of this, we may be subject to a claw back of LCFS credits related to the overgeneration of LCFS credits using the old CI Score. While we do not believe the penalty applies to us, the legislation does allow for a penalty of four times the number of LCFS credits to be taken away from a producer as a penalty if its score is lowered. As a result, the number of LCFS credits for RNG generated at our dairy farm project will decline.
Montauk Ag Renewables
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 natural gas, 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 870 tons of organic fertilizer alternative. We have entered into a ten-year agreement to sell all of the renewable electricity generated by the project. Furthermore, we have signed a REC agreement with Duke Energy for 47 RECs. We currently expect the first phase capital investment to be approximately $200,000 and have spent approximately $140,000 as of December 31, 2025. We expect our production and revenue generation activities to commence in April 2026.
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Other Opportunities
Other industries that present opportunities of scale for biogas conversion include swine farms and WRRFs. Biogas production from swine farms is a nascent biogas industry with great growth potential because swine manure is the second largest source of manure methane from livestock and only a small percentage of farms currently have biogas conversion capabilities. Additionally, while a larger percentage of WRRFs have biogas processing facilities, many process biogas for electricity production creating additional opportunities for acquisition and conversion to RNG facilities. As with LFG and dairy farms, biogas from both swine farms and WRRFs qualify for D3 RINs under the RFS program. We believe our demonstrated versatility to operate processing facilities using multiple fuel supply sources will give us a competitive advantage in these markets relative to other new entrants who have only demonstrated capabilities with one fuel supply source. The drive toward voluntary and most likely regulatory-required organic waste diversion from landfills is of particular interest as we leverage our current experience base. As our biogas processing technology continues to improve and the required energy intensity of the RNG and Renewable Electricity production process is reduced, we expect that we will be able to enter new markets for our products.
Optimize Existing Assets and Project Portfolio and Opportunistically Develop New Projects
Expanding Operations at Existing Project Sites. We monitor biogas supply availability across our portfolio and seek to maximize production at existing projects by expanding operations when economically feasible. Most of our landfill locations continue to accept waste deliveries and the available LFG at these sites is expected to increase over time, which we expect to support expanded production. In 2025, this has allowed us to maintain average production availability of approximately 89% at our RNG projects and 92% at our Renewable Electricity projects.
We treat our existing assets as an integrated portfolio rather than a collection of individual projects. This allows us to utilize any new business practices or technologies across our entire project portfolio quickly, including advances with respect to troubleshooting, optimization, cost savings, and host site interaction. Our integrated, pro-active and value-add approach helps us maintain strong relationships with our partners, which we seek to leverage to optimize the performance of our existing projects.
In addition to monitoring biogas supply, we are incorporating similar collection and processing used for our biogas supply to our byproduct streams to capture, clean, and liquefy biogenic carbon dioxide at our existing projects. In 2024, we announced our first agreement for certain of our Texas facilities related to biogenic carbon dioxide collection.
We also experience organic growth in production at our existing projects as a result of increases in biogas supply at our projects and on-going optimization initiatives. We size our projects to account for this increase in the biogas supply curve over time. For example, at many of our newer projects, such as Apex and Galveston, we expect gradual increases in production as those landfill sites continue to grow. Additionally, many of our capacity expansion efforts to date, such as those at McCarty, Rumpke, and Pico, have helped to optimize our project capacity to take advantage of excess biogas at older landfills that are still open and growing. Not only have our projects achieved an initial increase in production following the capacity expansion project, but we also expect to see continued gradual increases in production over time.
Converting Existing Renewable Electricity Projects to RNG. We periodically evaluate opportunities to convert existing projects from electricity generation to RNG production. These opportunities tend to be attractive for our merchant electricity projects given the favorable economics for RNG plus RIN sales relative to merchant electricity rates plus REC sales. To date, we have converted two projects from LFG-to-electricity to LFG-to-RNG and a third project from ADG-to-electricity to ADG-to-RNG. We will continue to explore the feasibility of other opportunities across our remaining Renewable Electricity portfolio.
Opportunistic Development of New RNG Projects. We apply a financially disciplined model toward new project development that considers the relative risk of a given project and associated feedstock costs, offtake contracts and any other related Environmental Attributes that can be monetized. We are currently developing two project expansion opportunities at existing project sites and one project at a new project site. We regularly analyze potential new projects that are at various stages of negotiation, engineering design and financial review. The potential projects typically include a mix of new project sites and strategic acquisitions. Currently, no new potential projects are subject to definitive agreements and each potential opportunity is subject to competitive market conditions.
Developing LFG to Renewable Electricity Projects. We continue to analyze for future development to include sites from which we would generate renewable electricity. This evaluation of potential new renewable electricity projects would be reviewed with the same financially disciplined model we use to evaluate new LFG-to-RNG projects.
The RNG industry remains highly fragmented. We believe continued industry fragmentation presents an opportunity for further industry consolidation. We are well-positioned to take advantage of this consolidation opportunity because of our scale, operational and managerial capabilities, and execution track record in integrating acquisitions. Over the last ten years, we have acquired 13
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projects and members of our current management team have led all of those acquisitions. We expect that as we continue to scale up our business, our increased size, capabilities and access to capital will provide us with increased strategic acquisition opportunities.
Valued-Added Service Offerings
Over our three decades of experience, we have developed the full range of RNG project related capabilities from engineering, construction, management and operations, through EHS oversight and Environmental Attributes management. By vertically integrating across RNG services, we are able to reduce development and operations costs, optimize efficiencies and improve operations. Our full suite of capabilities allows us to serve a multi-project partner for certain project hosts across multiple transactions, including through strategic transactions. To that end, we actively identify and evaluate opportunities to acquire entities that will further our vertically-integrated services.
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Our Current Operating Portfolio
We currently own and operate 13 projects, 11 of which are RNG projects and two of which are Renewable Electricity projects. We are currently in the process of expanding two RNG projects from LFG. We are also working on other projects which will repurpose equipment from existing biogas facilities for use at new project sites. The below graphic does not include the Montauk Ag project, which is currently under development.
|
|
Renewable Natural Gas |
||||||
|
Site |
COD(1) |
Capacity |
Source |
||||
|
Rumpke Cincinnati, OH |
1986 |
7,271 |
Landfill |
||||
|
Atascocita Humble, TX |
2002*/ 2018 |
5,570 |
Landfill |
||||
|
McCarty Houston, TX |
1986 |
4,415 |
Landfill |
||||
|
Apex Amsterdam, OH |
2018/2025 |
5,273 |
Landfill |
||||
|
Monroeville Monroeville, PA |
2004 |
2,372 |
Landfill |
||||
|
Valley Harrison City, PA |
2004 |
2,372 |
Landfill |
||||
|
Galveston Galveston, TX |
2019 |
1,857 |
Landfill |
||||
Renewable Electricity Generation |
|
Raeger Johnston, PA |
2006 |
1,857 |
Landfill |
|||
Site |
COD (1) |
Capacity |
Source |
|
Shade Cairnbrook, PA |
2007 |
1,857 |
Landfill (3) |
Bowerman Irvine, CA |
2016 |
23.6 |
Landfill |
|
Coastal Plains Alvin, TX |
2020 |
1,775 |
Landfill |
AEL Sand Spring, OK |
2013 |
3.2 |
Landfill |
|
Pico Jerome, ID |
2020 |
903 |
Livestock |
Total Capacity (MW) |
26.8 |
|
|
Total Capacity (MMBtu) |
35,522 |
|
||
|
= Renewable Natural Gas Project |
|
= Renewable Electricity Project
|
We have a long history of operating our projects with partners, with our oldest relationship going back nearly 50 years. On average, we have had an approximate 20-year history with our current project site owners. As of December 31, 2025, our operating RNG projects have an average expected remaining useful life of approximately 17 years and our operating Renewable Electricity projects have an average expected remaining useful life of approximately 33 years, including renewal periods.
Approximately 63% of our 2025 RNG production has been monetized under fuel supply agreements with expiration dates more than 15 years from December 31, 2025. Approximately 94% of our 2025 Renewable Electricity production has been monetized under fuel supply agreements with expiration dates more than 15 years from December 31, 2025. Concurrent with our fuel supply agreements, we typically enter into property leases with our project hosts, which govern access rights, permitted activities, easements and other property rights. We own all equipment and facilities on each leased property, other than equipment provided by utility companies providing services on-site. Lease termination typically requires the restoration of the leased area to its original condition. We have successfully ended leases on six of our former facilities.
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Our RNG projects currently utilize three of the four proven commercial technologies available to process raw biogas into RNG, including: pressure swing absorption (“PSA”), Membrane Filtration and solvent scrubbing. We are capable of working with virtually all available biogas processing technologies at our sites. We attend industry conferences and maintain an ongoing dialogue with key equipment providers to ensure we stay informed of the latest technology that could be deployed at our current and future facilities.
Stated capacity reflects the design capacity of each facility. Several of our projects have reserve capacity when comparing design capacity to available biogas feedstock. Several previous acquisitions are gas limited and therefore do not operate at their design capacity. Our larger projects have expansions planned or are being evaluated for future expansions dependent on the availability of excess biogas feedstock.
RNG Projects
We currently own and operate 11 RNG projects across four states: Ohio (two), Pennsylvania (four), Texas (four) and Idaho (one) which, in the aggregate, have a total design capacity of approximately 35,9522 MMBtu/day.
RNG Projects
Site |
|
Location |
|
Capacity* |
Rumpke |
|
Cincinnati, OH |
|
7,271 MMBtu/day |
Atascocita |
|
Humble, TX |
|
5,570 MMBtu/day |
McCarty |
|
Houston, TX |
|
4,415 MMBtu/day |
Apex (1) |
|
Amsterdam, OH |
|
5,273 MMBtu/day |
Monroeville |
|
Monroeville, PA |
|
2,372 MMBtu/day |
Valley |
|
Harrison City, PA |
|
2,372 MMBtu/day |
Galveston |
|
Galveston, TX |
|
1,857 MMBtu/day |
Raeger Mountain |
|
Johnstown, PA |
|
1,857 MMBtu/day |
Shade |
|
Cairnbrook, PA |
|
1,857 MMBtu/day |
Coastal Plains |
|
Alvin, TX |
|
1,775 MMBtu/day |
Pico |
|
Jerome, ID |
|
903 MMBtu/day |
Total |
|
35,522 MMBtu/day |
||
(1) Includes the capacity for our second Apex Facility, which was commissioned in 2025.
* Assumes inlet methane content of 56% for all sites other than Pico, which assumes inlet methane content of 62%, and process efficiency of 91%.
Renewable Electricity Projects
We currently own and operate the following two Renewable Electricity projects in California and Oklahoma, which, in the aggregate, have a total design capacity of approximately 29.1 MW. Our Renewable Electricity projects utilize reciprocating engine generator sets to generate electricity at landfills. This does not include the Montauk Ag Renewables project in North Carolina, which is not yet operational.
Renewable Electricity Projects
Site |
|
Location |
|
Capacity(1) |
Bowerman Power |
|
Irvine, CA |
|
23.6 MW |
Tulsa/AEL |
|
Sand Springs, OK |
|
3.2 MW |
Pico(1) |
|
Jerome, ID |
|
2.3 MW |
|
|
|
||
Total |
|
29.1 MW |
||
* Assumes inlet methane content of 56% and process efficiency of 91%,
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A critical component of our business is our ability to negotiate and maintain long-term fuel supply agreements at our project sites. We have developed strong working relationships with our landfill site owners, including eight of 13 operating projects and other potential development projects each with Waste Management and Republic Services, the two largest waste companies in the United States, and actively seek to strategically extend our tenure at our project sites.
Our projects provide our landfill and agricultural partners a solution to monetize biogas from their sites, support their regulatory compliance and provide them with environmental services. We have had working relationships with Republic Services since 1986 and with Waste Management since 2004 and we enable monetization of their biogas while maintaining regulatory compliance. We seek to differentiate ourselves from our competitors through our extensive experience across a variety of commercialized beneficial uses of processed biogas, including pipeline-quality natural gas, power generation and boiler fuel gas products. To date, we have not had any fuel supply agreement terminated by any site partner once we have established a facility on the site, which we believe serves as evidence of our operational expertise, reliability and consistent value delivered to our site partners. The table below is a summary of the expiration periods of those agreements. We are consistently reviewing and pursuing extensions for all of our fuel supply agreements well before their expirations and for future agreements, we continue to target contracts with expirations of 20 years from commencement of operation with options for extension.
Fuel Supply Agreement Summary
RNG Projects
Fuel Supply Agreement Expiration Dates |
|
Current Sites as of December 31, 2025 |
|
|
% of 2025 Total RNG Production |
|
||
Within 0-5 years |
|
|
2 |
|
|
|
3.0 |
% |
Between 6-15 years |
|
|
3 |
|
|
|
34.0 |
% |
Greater than 15 years |
|
|
6 |
|
|
|
63.0 |
% |
Renewable Electricity Projects
Fuel Supply Agreement Expiration Dates |
|
Current Sites as of December 31, 2025 |
|
|
% of 2025 Total |
|
||
Within 0-5 years |
|
|
— |
|
|
|
— |
% |
Between 6-15 years |
|
|
— |
|
|
|
— |
% |
Greater than 15 years(1) |
|
|
2 |
|
|
|
93.8 |
% |
Customers
Our customers for RNG and RINs typically include large, long-term owner-operators of landfills and livestock farms, local utilities, and large refiners in the natural gas and refining sectors. Royalty structures included in our agreements, as well as the large size of our counterparties, limit their credit risk. Valero and Exxon represented approximately 17.4% and 11.3%, respectively, of our operating revenues in 2025 from the sale of Environmental Attributes. We sell RINs to numerous RIN off-take parties and our largest RIN off-taker as a percentage of revenue can vary year to year given the short-term nature of these contracts. In addition to revenues from sales of RNG and RINs, we also share a portion of our Environmental Attributes with our pathway providers as in-kind consideration for the counterparty using our RNG as a transportation fuel.
Our customers for electricity typically include investor-owned and municipal electricity utilities. For the sale of Renewable Electricity and RECs, the City of Anaheim represented approximately 9.3% of our operating revenues in 2025. These sales occurred under a PPA between us and the City of Anaheim, in which electricity and RECs are sold at fixed prices. In 2025, we converted 100% of the monetization of our Renewable Electricity production and Environmental Attributes under fixed-price agreements. For our electricity sales, all of our customers with whom we have off-take agreements are investment-grade entities with low credit risk.
No other single customer represented more than 10% of our total 2025 operating revenues.
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Suppliers and Equipment Vendors
The major technologies used by our projects for gas processing include solvent scrubbing PSA and membrane separation. For electricity generation, we use reciprocating engines. This affords Montauk experience with substantially all major vendors in the sector, and technical expertise in numerous technologies.
We source equipment from a variety of major suppliers with specialties in each technology. We enter into written ordinary-course agreements with suppliers to obtain industry-standard equipment for use in our operations. The contracts generally do not include any intellectual property rights other than for the intended use of the equipment. Membrane separation equipment is primarily provided by UOP and Air Liquide. PSA equipment is primarily provided by Xebec, Guild, Air Products, and BioFerm. Solvent scrubbing is primarily provided by Selexol. RNG ancillary constituent removal is done using equipment provided by Iron Sponge, MV Technologies, Thiopaq, Guild Associates, and PSB Industries. Electricity generation equipment is provided by Solar Turbines, Caterpillar, and Jenbacher.
In 2025, we made a substantial investment in a centralized Enterprise Resource Planning (“ERP”) system Microsoft Dynamics 365. It allows us to better integrate operations across our projects. This system centralizes maintenance operations across all of our projects. Our proactive approach to maintenance, corrective maintenance, root cause analysis, failure reporting, project management, and budgeting are all completed using the ERP system.
Competition
There are several other companies operating in the renewable energy and waste-to-energy space, ranging from other project developers to service or equipment providers.
Our primary competition is from other companies or solutions for access to biogas from waste. Evolving consumer preferences, regulatory conditions, ongoing waste industry trends, and project economics have a strong effect on the competitive landscape and our relative ability to continue to generate revenues and cash flows. We believe that our status as one of the largest operators of LFG-to-RNG projects, our 30-year track record of operating and developing projects, and our deep relationships with some of the largest landfill owners and dairy farms in the country position us very well to continue to operate and grow our portfolio, and respond to competitive pressures. We have demonstrated a track record of strategic flexibility across our 30-year history which has allowed us to pivot towards projects and markets that we believe deliver optimal returns and stockholder value in response to changes in market, regulatory and competitive pressures.
The biogas market is highly fragmented. We believe our size relative to many other LFG companies and our capital structure puts us in a strong position to compete for new project development opportunities or acquisitions of existing projects. However, competition for such opportunities, including the prices being offered for fuel supply, will impact the expected profitability of projects to us, and may make projects unsuitable to pursue. Likewise, prices being offered by our competitors for fuel supply may increase the royalty rates that we pay under our fuel supply agreements when such agreements expire and need to be renewed or when expansion opportunities present themselves at the landfills where our projects currently operate. It is also possible that more landfill owners may seek to install their own LFG projects on their sites, which would reduce the number of opportunities for us to develop new projects. Our overall size, reputation, access to capital, experience and decades of proven execution on LFG project development and operation leave us well-positioned to compete with other companies in our industry.
We are aware of several competitors in the United States that have a similar business model to our own, including Clean Energy Fuels Corp, Opal Fuels, U.S. Gain, Brightmark, Gevo Inc., and AMP Energy, as well as companies with biogas-to-energy facilities as a segment or subsidiary of their operations, including DTE, Ameresco, and British Petroleum (bp, acquired Archaea Energy in 2022). In addition, certain landfill operators, such as Waste Management, have also chosen to selectively pursue biogas conversion projects at their sites. Finally, Republic has entered into a joint venture with bp (formerly through Archaea Energy) to develop certain of its LFG locations.
Government Regulation
Our projects are subject to a range of federal, state and local environmental, health and safety laws and regulations, depending on the nature and configuration of the project, as well as where the project is located. We have established processes and procedures to comply with laws and regulations applicable to our operations, and have partnered with external experts, as needed, to meet applicable compliance requirements. As a renewable energy company, we are committed to being good stewards of the environment and to positively impacting the communities in which we operate.
All of our current Renewable Electricity projects are QFs. As a result, the facilities are exempt from rate regulation under Sections 205 and 206 of the Federal Power Act. We are required to document the QF status of each of our facilities in applications or self-certifications filed with FERC, which typically require disclosure of upstream facility ownership, fuel and size characteristics,
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power sales, interconnection matters, and related technical disclosures. Failure to maintain QF status may subject the project to additional regulatory requirements and may require the payment of refunds to customers and other costs or penalties.
We are subject to the Clean Air Act, which regulates the emissions of air pollutants to protect the environmental and public health. The combustion of biogas results in emissions of carbon monoxide, oxides of nitrogen, sulfur dioxide, volatile organic compounds and particulate matter. Federal, state and local laws may require us to obtain permits or impose other burdens, including monitoring, testing, recordkeeping and reporting by us in order for us to conduct operations. In addition, our operations and the operations of landfills may be subject to additional air emissions laws and regulations, such as those designed to address the emission of methane, a potent GHG.
Among other laws, we are subject to Subtitle D of the Resource Conservation and Recovery Act and other federal, state and local laws, which impose conditions on the handling of hazardous and non-hazardous waste, including the emission of methane in landfills. Likewise, we are subject to the Comprehensive Environmental Response Compensation and Liability Act of 1980 and other federal, state and local laws, which govern the investigation and cleanup of sites contaminated with hazardous substances. We have not been identified as a potentially responsible party with respect to environmental remedial costs at any site to date. We also may be required to obtain permits to discharge wastewater and stormwater pursuant to the Clean Water Act’s National Pollutant Discharge Elimination System and other federal, state and local laws governing such discharges.
Our RNG projects are subject to federal RFS program regulations, including the Energy Policy Act of 2005 and the Energy Independence and Security Act. The EPA administers the RFS program with volume requirements for several categories of renewable fuels. The EPA’s RFS regulations establish rules for fuel supplied and administer the RIN system for compliance, trading credits and rules for waivers. The EPA calculates a blending standard for each year based on estimates of gasoline usage from the Department of Energy’s Energy Information Agency. Separate quotas and blending requirements are determined for cellulosic biofuels, BBD, advanced biofuels and total renewable fuel. Further, we are required to register each RNG project with the EPA and relevant state regulatory agencies.
We qualify our RINs through a voluntary Quality Assurance Plan, which typically takes from three to five months from first injection of RNG into the commercial pipeline system. Further, we typically make a large investment in the project prior to receiving the regulatory approval and RIN qualification. In addition to registering each RNG project, we are subject to quarterly audits under the Quality Assurance Plan of our projects to validate our qualification.
Our RNG projects are also subject to state renewable fuel standard regulations. The CA LCFS program requires producers of petroleum-based fuels to reduce the CI of their products, beginning with a quarter of a percent in 2011, a 10% total reduction in 2020, and a 30% total reduction in 2030. Petroleum importers, refiners and wholesalers can either develop their own low-carbon fuel products, or buy CA LCFS credits from other companies that develop and sell low-carbon alternative fuels, such as biofuels, electricity, natural gas or hydrogen. We are subject to a qualification process for CA LCFS credits that is similar to that for RINs, including verification of CI levels and other requirements.
Our RNG projects are also impacted by state and federal gas quality standards. State regulators determine whether RNG may be purchased by the state’s local gas utilities, and whether a site operator may directly sell gas to a retail, or direct end-use, customer. FERC regulates the natural gas pipelines that transport gas in interstate commerce, and specifies or approves a gas pipeline’s tariff that sets the rates, terms and conditions, gas quality, and other requirements applicable to transportation of natural gas on the pipelines, including shipping RNG. Our sites are not permitted, and may not be physically able, to deliver RNG to a FERC regulated pipeline unless the pipeline’s receipt of the gas is consistent with the standards adopted in the pipeline’s FERC tariff. RNG-related gas quality standards may vary by pipeline and may be revised at any time, subject to all required regulatory approvals. We routinely test the RNG produced at our facilities in order to ensure compliance with applicable pipeline gas quality standards.
We monitor regulatory trends and developments in the U.S. regarding the regulation of greenhouse gas emissions. The EPA published final regulations for methane emissions, a greenhouse gas, from oil and gas facilities in March 2024. The regulation does not apply to our operations and could, combined with another public policy and private sector initiatives, increase interest in developing more renewable energy projects in the U.S. We will continue to monitor greenhouse gas regulatory initiatives in the U.S. and assess their potential relevance to our business and operations.
We routinely conduct compliance audits on our projects to proactively identify and correct potential compliance deficiencies or risks. Additionally, we closely monitor emerging regulatory developments that may impact our operations or business strategy. Montauk also participates in industry trade groups, such as the RNG Coalition and American Biogas Council, to advocate policies and regulatory frameworks that support continued expansion of renewable energy in the United States.
The operation of our business may expose us to certain liabilities and compliance costs related to environmental matters. These liabilities or compliance costs did not have a material effect on our capital expenditures or competitive position for fiscal 2024, nor do
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we expect them to have a material effect in the future. We believe we are in material compliance with all environmental regulations applicable to our operations.
Tax Regulation. The Inflation Reduction Act ("IRA" or the "Act") will be administered by multiple federal agencies including EPA, U.S. Department of Energy and the Internal Revenue Service of the U.S. Department of the Treasury. The goals of the IRA include incentivizing the development and production of renewable energy. We cannot speculate on exactly how the IRA will be implemented; however, the Act does contain numerous incentives for the production of clean energy which may impact our products. President Trump signed Executive Order 14154 in January 2025, which immediately paused the disbursement of funds under the IRA. The funding pause has been challenged by several states and the District of Columbia. The One Big Beautiful Bill Act was signed into law in July 2025 and, while we are still analyzing its potential impacts, we do not think that it will materially impact us.
Employees and Human Capital Resources
Employee Profile
We employed 189 people on December 31, 2025, located in California, Idaho, Ohio, Oklahoma, Pennsylvania, North Carolina and Texas. Our employee population is comprised of a mix of field operations personnel and office-based professionals. As of December 31, 2025, none of our employees were represented by a collective bargaining unit or labor union. We consider our employee relations to be good across our organization.
Health and Safety
Safety, including the health of our employees, is one of our core values and a priority across our operations. We are committed to developing a strong health and safety culture that reduces injuries and illness whenever possible. Our health and safety strategy is designed to proactively identify, mitigate and eliminate conditions that could result in serious injury or fatality. We also routinely train our employees on health and safety practices applicable to their job function and provide them all necessary personal protective equipment to perform their job in a safe manner.
Our recordable cases and total recordable incident rate (“TRIR”), excluding COVID-19 related incidents, was 1.06 and 2.89 in 2025 and 2024, respectively. The 2024 TRIR national average was 2.4 for all industries. We continue to focus on practices and measures to lower our TRIR.
Employee Development and Training
The success and growth of our business is significantly correlated with our ability to recruit, train, promote and retain talented individuals at all levels of our organization. To succeed in a competitive labor market, we have developed and implemented various recruitment and retention strategies. These include competitive salary structures, bonus programs and competitive benefits, as well as paid time off, sick leave, disability coverage, group term life insurance, and a retirement savings program. We also offer our employees tuition reimbursement for job-related education and training opportunities. We continue to provide leadership and developmental training for our executive, director and manager level employees.
Intellectual Property
We rely on a combination of patent, trademark, copyright and trade secret laws, employee and third-party nondisclosure/confidentiality agreements and non-compete and license agreements to protect our intellectual property. We acquired certain technology in the Montauk Ag Renewables Acquisition for which we received a patent during 2021 with a term of 20 years. In 2022, we filed a provisional patent application pertaining to a combustion-based oxygen removal condensate neutralization technology we developed. The provisional patent covers a new low pH neutralization technology designed to mitigate unfavorable pH condensate that is produced when wastewater is removed from the biogas conversion process. In 2024, we filed a provisional patent application pertaining to a renewable natural gas processing skid that we developed. In 2025, we filed a provisional patent application pertaining to a mobile swine waste separation, collection and removal apparatus and method as well as a provisional patent application for a mixing and solids removal system that we developed for our manure digester in Jerome, Idaho. Further, GreenWave Energy Partners, LLC (“GreenWave”), of which we own 51%, has a provisional patent application filed in 2025 for dispensing of RNG through expanded Transportation Fuel uses under the RFS.
Segments and Geographic Information
We have two operating segments: Renewable Natural Gas and Renewable Electricity Generation. For information regarding revenues and other information regarding our results of operations for each of our last two financial years, please refer to our financial
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statements included in this report and within “Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report.
Corporate Information
Montauk Renewables, Inc. is incorporated in the State of Delaware. Our principal executive offices are located at 5313 Campbells Run Road, Suite 200, Pittsburgh, PA 15205. Our telephone number is (412) 747-8700.
We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.
We also make financial information, news releases and other information available on our corporate investor relations website at www.ir.montaukrenewables.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are available free of charge on this website as soon as reasonably practicable after we file these reports and amendments with, or furnish them to, the SEC. The information contained on or connected to our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report filed with the SEC.
We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012. As an emerging growth company, we may take advantage of certain reduced reporting requirements that are otherwise applicable generally to public companies. We currently intend to take advantage of several of these reduced reporting requirements, including the extended transition periods for complying with new or revised accounting standards. See “Item 1A. Risk Factors—Emerging Growth Company Risks” for certain risks related to our status as an emerging growth company.
We are a “controlled company” within the meaning of the Nasdaq Stock Market LLC (“Nasdaq”) corporate governance standards. Certain stockholders, which are affiliates of two of our directors, Mr. John A. Copelyn and Theventheran G. Govender, own approximately 52.3% of our common stock and have entered into a Consortium Agreement (the “Consortium Agreement”) whereby the parties thereto will agree to act in concert with respect to voting our common stock, including in the election of directors, among other matters. As a controlled company, we may elect not to comply with certain Nasdaq corporate governance standards. See “Item 1A. Risk Factors—Common Stock Risks” for certain risks related to our status as a controlled company.
This report includes estimates, projections, and other information concerning our industry and market data, including data regarding the estimated size of the market, projected growth rates, and perceptions and preferences of consumers. We obtained this data from industry sources, third-party studies, including market analyses and reports, and internal company surveys. Industry sources generally state that the information contained therein has been obtained from sources believed to be reliable. Although we are responsible for all of the disclosure contained in this report, and we believe the industry and market data to be reliable as of the date of this report, this information could prove to be inaccurate.
Information About Our Executive Officers
Below is a list of the names, ages, and positions of our executive officers, and a brief summary of the business experience of our executive officers (ages as of March 1, 2026).
Name |
|
Age |
|
Position |
Sean F. McClain |
|
51 |
|
President and Chief Executive Officer, Director |
Kevin A. Van Asdalan |
|
48 |
|
Chief Financial Officer and Treasurer |
James A. Shaw |
|
54 |
|
Chief Operating Officer |
John Ciroli |
|
55 |
|
Chief Legal Officer and Secretary |
Sharon Frank |
|
69 |
|
Vice President of Environmental, Health and Safety |
Sean F. McClain. Mr. McClain has served as our President and Chief Executive Officer and a member of our Board of Directors since January 2021. Prior to the Reorganization Transactions, Mr. McClain served as President and Chief Executive Officer of Montauk Holdings USA and as a member of its Board of Directors. From April 2011 until September 2019, Mr. McClain served as Chief Financial Officer of Montauk Holdings USA and Montauk Energy Holdings. Prior to joining Montauk in 2011, he held various management positions with BPL Global Limited, Bayer and Dick’s Sporting Goods and was in public accounting at Arthur Andersen LLP. He is a certified public accountant and has over 25 years of business and financial management experience.
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Kevin A. Van Asdalan. Mr. Van Asdalan has served as our Chief Financial Officer and Treasurer since January 2021. Prior to the Reorganization Transactions, Mr. Van Asdalan served as Chief Financial Officer of Montauk Holdings USA and as a member of its Board of Directors. From March 2018 until September 2019, Mr. Van Asdalan served as Controller of Montauk Energy Holdings and Montauk Holdings USA. Prior to joining Montauk in 2018, Mr. Van Asdalan served as a lines of business controller and manager of external reporting at L.B. Foster Company, a manufacturer, distributor and service provider for transportation and energy infrastructure, from July 2011 to March 2018. Prior to L.B. Foster, Mr. Van Asdalan held senior associate accounting positions at PricewaterhouseCoopers LLP and Sisterson & Co LLP. He is a certified public accountant and chartered global management accountant with nearly 25 years of business and financial management experience and holds a Master of Business Administration from the University of Pittsburgh Katz Graduate School of Business.
James A. Shaw. Mr. Shaw has served as our Chief Operating Officer since October 2025. He served as our Vice President of Operations from January 2021 until September 2025 and as the Vice President of Operations of Montauk Energy Holdings from September 2019 until December 2020. He previously served as North Region Manager of Montauk Energy Holdings from May 2016 until September 2019 and held positions of increasing responsibility as a site manager from 2010 until 2016. Prior to joining Montauk, Mr. Shaw was a facility manager for SONY Electronics at the world’s first vertically integrated television manufacturing facilities. Mr. Shaw has more than 25 years of experience in facilities operations and management.
John Ciroli. Mr. Ciroli has served as our Chief Legal Officer since January 2023. He served as our Vice President, General Counsel and Secretary from January 2021 until January 2023 and in the same role with Montauk Energy Holdings upon joining in July 2020. From July 2016 to July 2020, Mr. Ciroli was the North American Counsel and HR Manager for the North American subsidiaries of FAAC Group, a company that designs solutions for pedestrian and vehicle needs, representing the entities in their American and Canadian portfolio. From 2014 to July 2016, Mr. Ciroli was a Senior Litigation Counsel with the Housing Authority of the City of Pittsburgh. Mr. Ciroli has over 25 years of experience representing and advising domestic and international corporations and government entities in the areas of contracts, mergers and acquisitions, litigation, employment and governmental procurement and regulatory affairs. He was also a professor for Concord Law School, now Purdue Global, in the areas of Contracts, Constitutional Law, Torts and Evidence and is a member of the Pennsylvania State Bar and the bar of the U.S. Supreme Court.
Sharon Frank. Ms. Frank has served as our Vice President of Environmental, Health and Safety since October 2021. She served as our Director of Environmental, Health and Safety from April 2020 until October 2021 and as Manager of Environmental Compliance from June 2007 until April 2020. Prior to joining Montauk, from 2000 to 2007, Ms. Frank was Manager of Environmental Affairs for Duquesne Light Company’s unregulated business group. Ms. Frank has over 30 years of regulatory and environmental compliance experience.
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ITEM 1A. RISK FACTORS.
This Annual Report on Form 10-K contains forward-looking information based on our current expectations. Because our business is subject to many risks and our actual results may differ materially from any forward-looking statements made by or on behalf of us, this section includes a discussion of important factors that could affect our business, operating results, financial condition and the trading price of Montauk common stock. You should carefully consider these risk factors, together with all of the other information included in this Annual Report on Form 10-K as well as our other publicly available filings with the SEC. Although the risks are organized by headings, and each risk is discussed separately, many are interrelated.
Operational Risks
Our renewable energy projects may not generate expected levels of output.
Landfills contain organic material whose decomposition causes the generation of gas consisting primarily of methane, which our RNG projects use to generate power or renewable natural gas, and carbon dioxide. The estimation of landfill gas production volume is an inexact process and dependent on many site-specific conditions, including the estimated annual waste volume, composition of waste, regional climate and the capacity and construction of the landfill. Production levels are subject to a number of additional risks, including a failure or wearing out of our or our landfill operators’, customers’ or utilities’ equipment; an inability to find suitable replacement equipment or parts; less than expected supply or quality of the project’s source of biogas and faster than expected diminishment of such biogas supply; or volume disruption in our fuel supply collection system. Any extended interruption and/or volume disruption in the project’s operation, or failure of the project for any reason to generate the expected amount of output, could adversely affect our business and operating results. For example, certain of our Houston-based operating sites were impacted by severe weather events during the first nine month of 2024 including multiple day extended outages from Hurricane Beryl in July 2024. Furthermore, we produced fewer MMBtu and MWh in the third quarter of 2023 compared with the third quarter of 2022 due to dry weather conditions and higher ambient temperatures. In addition, we have in the past, and may in the future, incur material asset impairment charges if any of our renewable energy projects has operational issues that indicate our expected future cash flows from the project are less than the project’s carrying value. Any such impairment charge could adversely affect our operating results in the period in which the charge is recorded.
In addition, to maximize collection of LFG, we need to take various measures, such as drilling additional gas wells in the landfill to increase LFG collection, balancing the pressure on the gas field based on the data collected by the landfill operator from the gas wells to ensure optimum landfill gas utilization and ensuring that we match availability of engines and related equipment to availability of LFG. There can be no guarantee that we will be able to take all necessary measures to maximize collection. For example, we do not operate the wellfields at all sites. In addition, the LFG available to our projects is dependent in part on the actions of other persons, such as landfill operators. We may not be able to ensure responsible management of the landfill site by owners and operators or there could be a change in operations and maintenance providers that results in less effective operations. This could result in less-than-optimal gas generation or increase the likelihood of “hot spots” occurring. Hot spots can temporarily reduce the volume of gas which may be collected from a landfill site, resulting in a lower gas yield. Landfill owner negligence such as covering gas wells with landfill material and breaking gas lines could also result in decreased output. Other events that result in a reduction in LFG output include: extreme hot or cold temperatures or drought or excessive rainfall; liquid levels within a landfill increasing; oxidation within a landfill, which can kill the anaerobic microbes that produce landfill gas; and the buildup of sludge or inorganic materials (such as construction materials) that do not produce gases as they decompose.
The occurrence of these or any other changes within any of the landfills where our projects operate could lead to a reduction in the amount of LFG available to operate our projects, which could have a material adverse effect on our business, financial condition and results of operations.
The concentration in revenues from five of our projects and geographic concentration of our projects expose us to greater risks of production interruptions from severe weather or other interruptions of production or transmission.
A substantial portion of our revenues are generated from five project sites. For the years ended December 31, 2025 and 2024, excluding the effect of derivative instruments, approximately 67.7% and 69.1%, respectively, of operating revenues derived from these locations. During 2025, RNG production at our Rumpke, Atascocita, McCarty and Apex facilities accounted for approximately 20.7%, 20.3%, 16.0% and 7.7% of our RNG revenues, respectively, and 20.7%, 20.3%, 16.0% and 7.7% of the RNG we produced, respectively. During 2025, Renewable Electricity production at our Bowerman facility accounted for approximately 94.9% of our Renewable Electricity Generation revenues and 85.5% of the Renewable Electricity we produced during 2025. A lengthy interruption of production or transmission of renewable energy from one or more of these projects, due to a severe weather event, failure or degradation of our or a landfill operator’s equipment or interconnection transmission problems could have a disproportionate effect on our revenues and cash flow.
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Our Atascocita, McCarty, Galveston and Coastal Plains projects are located within 20 miles of each other near Houston, Texas and six of our other RNG projects are in relatively close proximity to each other in Pennsylvania and Ohio. Regional events, such as gas transmission interruptions, regional availability of replacement parts and service in the event of equipment failures and severe weather events in either of those geographic regions have previously adversely affected, and if the future could adversely affect, our RNG production and transmission. These impacts are greater than would be if our business was more geographically diverse.
We have significant customer concentration, with a limited number of customers accounting for a substantial portion of our revenues.
In 2025, RIN sales to Valero and ExxonMobil represented approximately 17.4% and 11.3%, respectively, of our operating revenue. In 2024, RIN sales to Valero, GE Warren, ExxonMobil and Mercuria represented approximately 17.6%, 15.7%, 13.8 and 11.8%, respectively, of our operating revenue. Five customers made up approximately 68.2% of our accounts receivable as of December 31, 2025 and December 31, 2024. Revenues from our largest customers may fluctuate from time to time based on our customers’ business needs, market conditions or other factors outside of our control. If any of our largest customers terminates its relationship with us, such termination could adversely affect our revenues and results of operations.
Our projects are not able to insure against all potential risks and may become subject to higher insurance premiums.
Our projects are exposed to the risks inherent in the construction and operation of renewable energy projects, such as breakdowns, manufacturing defects, extreme weather, natural disasters, terrorist attacks and sabotage. We are also exposed to environmental risks.
We have insurance policies covering certain risks associated with our business. Our insurance policies do not, however, cover all losses, including, in some situations, those because of force majeure, which is generally defined as events that are beyond the control of the parties. Even if insurance policies for some of our projects cover losses as a result of certain types of force majeure events, such coverage is subject to important limitations. Furthermore, insurance liabilities are difficult to assess and quantify due to unknown factors, including the severity of an injury, the determination of our liability in proportion to other parties, the number of incidents not reported and the effectiveness of our safety program. Insurance coverage is not always available on commercially reasonable terms (if at all) and is often capped at predetermined limits. In addition, our insurance policies are subject to annual review by our insurers and may not be renewed on similar or favorable terms or at all. A serious uninsured loss or a loss significantly exceeding the limits of our insurance policies could adversely affect our business, financial condition and results of operations.
Competition Risks
We may face intense competition and may not be able to successfully compete.
There are a number of other companies operating in the renewable energy and waste-to-energy markets. These include other renewable energy companies and service or equipment providers, consultants, managers and strategic investors.
We may not have the resources to compete with our existing competitors or with any new competitors, including in a competitive bidding process. Some of our competitors have significantly larger personnel, financial and managerial resources than we have, and we may fail to maintain or expand our business. Our competitors may also offer energy solutions at prices below cost, devote significant sales forces to competing with us or attempt to recruit our key personnel by increasing compensation, any of which could improve their competitive positions. Moreover, if the demand for renewable energy increases, new companies may enter the market, and the influx of added competition will pose an increased risk to us.
Further, certain of our strategic partners and other landfill or agricultural operators could decide to manage, recover and convert biogas from waste to renewable energy on their own which would further increase our competition, limit the number of commercially viable landfill sites available for our projects or require us to reduce our profit margins to maintain or acquire projects.
Our success depends, in part, on technological innovation to stay ahead of market competitors.
Our success depends on our ability to create and maintain a competitive position in the renewable energy industry. We do not have exclusive rights to many of the technologies that we utilize, and our competitors may currently use and may be planning to use identical, similar or superior technologies. In addition, our technologies may ultimately prove ineffective, may be hampered by frequent mechanical breakdowns, or rendered obsolete or uneconomical by technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of our competitors or others.
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We may also face competition based on technological developments that reduce demand for electricity, increase power supplies through existing infrastructure or otherwise compete with our projects. We also encounter competition in the form of potential customers electing to develop solutions or perform services internally rather than engaging an outside provider such as us.
Our use and enjoyment of real property rights for our projects may be adversely affected by the rights of lienholders and leaseholders that are superior to those of the grantors of those real property rights to our projects.
Our projects generally are, and any of our future projects are likely to be, located on land occupied pursuant to long-term easements, leases and rights of way. The ownership interests in the land subject to these easements, leases and rights-of-way may be subject to mortgages securing loans or other liens (such as tax liens) and other easements, lease rights and rights-of-way of third parties (such as leases of oil or mineral rights) that were created prior to our projects’ easements, leases and rights-of-way. As a result, certain of our projects’ rights under these easements, leases or rights-of-way may be subject, and subordinate, to the rights of those third parties. In the future, our existing projects may need new easements or rights-of-way and there is no guaranty that we will be able to secure these. For example, our Shade facility in Johnstown needs a change in the easement due to road construction. We may not be able to protect our operating projects against all risks of loss of our rights to use the land on which our projects are located, and any such loss or curtailment of our rights to use the land on which our projects are located and any increase in rent due on such lands could adversely affect our business, financial condition and results of operations.
We may not be able to obtain long-term contracts for the sale of power produced by our projects on favorable terms and we may not meet certain milestones and other performance criteria under existing PPAs.
Obtaining long-term contracts for the sale of power produced by our projects at prices and on other terms favorable to us is essential for the long term success of our business. We must compete for PPAs against other developers of renewable energy projects. This intense competition for PPAs has resulted in downward pressure on PPA pricing for newly contracted projects. The inability to compete successfully against other power producers or otherwise enter into PPAs favorable to us would negatively affect our ability to develop and finance our projects and negatively affect our revenues. In addition, the availability of PPAs depends on utility and corporate energy procurement practices that could evolve and shift allocation of market risks over time. Further, PPA availability and terms are a function of a number of economic, regulatory, tax, and public policy factors, which are also subject to change.
Our PPAs typically require us to meet certain milestones and other performance criteria. Our failure to meet these milestones and other criteria, including minimum quantities, may result in price concessions, in which case we would lose any future cash flow from the relevant project. In addition, we have in the past and, in the future, may be required to pay fees and penalties to our counterparty. We cannot assure you that we will be able to perform our obligations under such agreements, that fees and penalties will remain insignificant, or that we will have sufficient funds to pay any fees or penalties thereunder.
Business Strategy Risks
Our commercial success depends on our ability to identify, acquire, develop and operate individual renewable energy projects, as well as our ability to maintain and expand production at our current projects.
We aim to maintain and grow our position as a leading producer of RNG in the United States. Our specific focus on the renewable energy sector exposes us to risks related to the supply of, demand for and the ultimate price of energy commodities and Environmental Attributes, inflation, taxes, tariffs, duties, or other assessments on necessary equipment, the cost of capital expenditures, government regulation, world and regional events and economic conditions, labor market conditions and the acceptance of alternative power sources. As a renewable energy producer, we may also be negatively affected by lower energy output resulting from variable inputs, mechanical breakdowns, faulty technology, competitive electricity markets or changes to the laws and regulations that mandate the use of renewable energy sources by refiners and importers of gasoline and diesel fuel and electric utilities.
In addition, several other factors related to the development and operation of individual renewable energy projects could adversely affect our business, including:
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In addition, new projects have no operating history and may employ recently developed technology and equipment. The technology may not be successful or our use of intellectual property may be challenged for infringement. A new project may be unable to fund principal and interest payments under its debt service obligations or may operate at a loss, which may adversely affect our business, financial condition or results of operations. This may also make it more difficult to obtain capital for new projects.
We may also experience delays and cost overruns in converting existing facilities from Renewable Electricity to RNG production. During the conversation projects, there is a gap in production and relating revenue while the electricity project is offline until it commences operation as an RNG facility, which adversely affects our financial condition and results of operations.
Any of these factors could prevent us from identifying, completing or operating our projects, or otherwise adversely affect our business, financial condition and results of operations.
If there is not sufficient demand for renewable energy, or the associated Environmental Attributes, or if renewable energy projects do not develop or take longer to develop than we anticipate, we may be unable to achieve our investment objectives.
If demand for renewable energy or Environmental Attributes fails to grow sufficiently, we may be unable to achieve our business objectives. In addition, demand for renewable energy projects and Environmental Attributes in the markets and geographic regions that we target may not develop or may develop more slowly than we anticipate. Many factors will influence the widespread adoption of renewable energy and demand for renewable energy projects, including:
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Our fuel supply agreements with site hosts have defined contractual periods, and we cannot assure you that we will be able to successfully extend these agreements at their historic revenue levels or at all.
Fuel supply rights are issued by the landfill owner to operators for a contractual period. As operators, we have already invested resources in the development of existing sites and the ability to extend these contracts on expiration would enable us to achieve operational efficiency in continuing to generate revenues from a site without significant additional capital investments. We cannot assure you that we will be able to extend existing fuel supply agreements at their historic revenue levels or at all when they expire.
Our agreements contain complex price adjustments, calculations and other terms based on gas price indices and other metrics, the interpretation of which could result in disputes with counterparties that could affect our results of operations and customer relationships.
Certain of our PPAs, fuel supply agreements, RNG off-take agreements and other agreements require us to make payments or adjust prices to counterparties based on past or current changes in gas price indices, project productivity or other metrics and involve complex calculations. Moreover, the underlying indices governing payments under these agreements are subject to change, may be discontinued or replaced. The interpretation of these price adjustments and calculations and the potential discontinuation or replacement of relevant indices or metrics have resulted, and in the future, could result in disputes with the counterparties with respect to these agreements. Any such disputes could adversely affect project revenues, expense margins, customer or supplier relationships, or lead to costly litigation, the outcome of which we would be unable to predict.
In order to secure contracts for new projects, we typically face a long and variable development cycle that requires significant resource commitments and a long lead time before we realize revenues.
The development, design and construction process for our renewable energy projects generally lasts from 18 to 36 months, on average. This extended development process requires the dedication of significant time and resources from our sales and management personnel, with no certainty of success or recovery of our expenses. A potential site host may go through the entire sales process and not accept our proposal. Further, upon commencement of operations, it typically takes 12 months or longer for the project to ramp up to our expected production level. All of these factors, and in particular, increased spending that is not offset by increased revenues, can contribute to fluctuations in our quarterly financial performance and increase the likelihood that our operating results in a particular period will fall below investor expectations.
We plan to expand our business in part through developing RNG recovery projects at landfills and livestock farms, including our Turkey, North Carolina location, but we may not be successful.
We plan to continue to develop new RNG projects at landfills and livestock farms but we may be unable to implement this growth strategy. We may not be able to identify suitable landfills and livestock farms on which to develop projects, reach agreements with landfill or livestock farm owners to develop RNG projects or arrange required financing for new projects. While the EPA has identified an additional 444 landfills as candidates for biogas projects, we believe that approximately 32 of these sites produce sufficient quantities of LFG to support commercial-scale projects, with 24 of the approximately 32 sites being operated by Waste Management or Republic Waste, with whom we would need to negotiate with to secure sufficient LFG rights to support an RNG project. In the future, additional candidate landfills may become economically viable as their growth increases LFG production and requires installation of LFG collection systems. However, the time and effort involved in attempting to identify suitable sites and development of new projects may divert members of our management from our operations.
While our Montauk AG swine manure facility in Turkey, North Carolina is scheduled to begin commercial operations in April 2026, we have experienced delays due to inclement weather, construction delays, mechanical breakdowns and failure of technology to perform as expected. As of December 31, 2025, we have spent approximately $142 million to develop the facility and expect that total capital investment will be approximately $200 million. There can be no assurances that the facility will produce the projected amount of renewable electricity and swine RECs or that the project will not need additional capital investment to become fully operational. Furthermore, while we are contracted to sell a portion of the swine RECs produced, we do not have a contract to sell all projected swine RECs we produce. There is no established market for swine RECs so we are unsure at what price we will be able to sell them, if we are able to sell them at all.
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Our dairy farm project has, and any future digester project will have, different economic models and risk profiles than our landfill facilities, and we may not be able to achieve the operating results we expect from these projects.
Our Pico dairy farm project produces significantly less RNG than our landfill facilities. As a result, we are even more dependent on the LCFS credits and RINs produced at our dairy farm project than on the RINs produced at our landfill facilities for the project’s commercial viability. As a result of the 2025 AFPR review, our CI score worsened. The worsening CI score is primarily due to increased biogas upgrading and fugitive emissions from the biogas upgrading process. We are currently conducting an analysis to determine the benefit of installing a combustion device to eliminate fugitive emissions. As a result of this, we may be subject to a claw back of LCFS credits related to the overgeneration of LCFS credits using the old CI Score. While we do not believe the penalty applies to us, the legislation does allow for a penalty of four times the number of LCFS credits to be taken away from a producer as a penalty if its score is lowered. As a result, the number of LCFS credits for RNG generated at our dairy farm project will decline. Additionally, revenue from LCFS credits also depends on the price per LCFS credit, which is driven by various market forces, including the supply of and demand for LCFS credits, which in turn depends on the demand for traditional transportation fuel and the supply of renewable fuel from other renewable energy sources, and mandated CI targets, which determine the number of LCFS credits required to offset LCFS deficits, and which increase over time. Fluctuations in the price of LCFS credits or the number of LCFS credits assigned will have a significantly greater impact on the success of our dairy farm project than the value that RINs have on our landfill facilities. A significant decline in the value of LCFS credits could require us to incur an impairment charge on our dairy farm project and could adversely affect our business, financial condition and results of operations.
While we currently focus on converting methane into renewable energy, in the future we may decide to expand our strategy to include other types of projects. Any future energy projects may present unforeseen challenges and result in a competitive disadvantage relative to our more established competitors.
Our business is currently focused on converting methane into renewable energy. In the future, we may expand our strategy to include other types of projects. We cannot assure you that we will be able to identify attractive opportunities outside of our current area of focus or acquire or develop such projects at a price and on terms that are attractive or that, once acquired or developed, such projects will operate profitably. Risks include a lack of supply offtake, lower than expected prices for generated supplies, malfunctioning equipment, unsuccessful new technologies, and intellectual property challenges. In addition, these projects could expose us to increased operating costs, unforeseen liabilities or risks, and regulatory and environmental concerns associated with entering into new sectors of the energy industry, including requiring a disproportionate amount of our management’s attention and resources, which could adversely affect our business, as well as place us at a competitive disadvantage relative to more established market participants. A failure to successfully integrate such new projects into our existing project portfolio as a result of unforeseen operational difficulties or otherwise, could adversely affect our business, financial condition and results of operations.
The profitability of our renewable fuel projects may be limited by our ability to dispense fuel to separate RINs and the volatility of the price of RINs.
A RIN is separated by dispensing RNG through permitted channels. If we are unable to dispense RNG through such permitted channels because of a lack of demand, we are unable to separate RINs. Furthermore, if the supply of RNG to be separated through the permitted channels is greater than the demand for the RNG, the price we pay to separate the RIN could be higher.
Furthermore, the price of Environmental Attributes, including RINs, is driven by various market forces, including regulatory action, gasoline prices and the availability of renewable fuel from other renewable energy sources and conventional energy sources. For example, following the EPA’s issuance of annual Renewable Volume Obligations in recent years, market prices for certain RIN categories have experienced significant volatility in response to changes in mandated volumes, compliance flexibility, and market expectations. In addition, refiners are permitted to carry over up to 20% of RINs generated for one calendar year to satisfy their RVOs for the following year. As a result, we are generally only able to sell RINs on a forward basis for the year in which the RINs are generated and the subsequent year.
We may be unable to manage the risk of volatility in RIN pricing for all or a portion of our revenues from RINs, which would expose us to the volatility of commodity prices with respect to all or the portion of RINs that we are unable to sell through forward contracts, including risks resulting from changes in regulations, general economic conditions and changes in the level of renewable energy generation. We expect quarterly variations in the revenues from the projects in which we generate revenue from the sale of RINs that we are unable to sell through forward contracts and may experience reduced revenues if we are unable to separate RINs through the dispensing of produced RNG through permitted channels or reduced net income if we must pay a higher price to separate such RINs due to excess supply.
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Our revenues may be subject to the risk of fluctuations in commodity prices.
The operations and financial performance of projects in the renewable energy sectors may be affected by the prices of energy commodities, such as natural gas, wholesale electricity and other energy-related products. For example, the price of renewable energy resources changes in relation to the market prices of natural gas and electricity. The market price for natural gas is sensitive to cyclical demand and capacity supply, changes in weather patterns (including extreme temperatures spells), natural gas storage levels, natural gas production levels, general economic and geopolitical conditions (including the current conflict in the Middle East) and the volume of natural gas imports and exports. The market price of electricity is sensitive to changes in demand and capacity supply (including both cyclical demand and increased long term demand due to, among others, data storage centers and artificial intelligence), and in the economy and geopolitical conditions, as well as to regulatory trends and developments impacting electricity market rules and pricing, transmission development and investment to power markets within the United States and in other jurisdictions through interconnects and other external factors outside of the control of renewable energy power-producing projects. Volatility of commodity prices also creates volatility in the prices of Environmental Attributes, which are inversely related to the wholesale price of unleaded gasoline. In addition, volatility of commodity prices, such as the market price of gas and electricity, may also make it more difficult for us to raise any additional capital for our renewable energy projects that may be necessary to operate, to the extent that market participants perceive that a project’s performance may be tied directly or indirectly to commodity prices. Accordingly, the potential revenues and cash flows of these projects may be volatile and adversely affect the value of our investments.
Our off-take agreements for the sale of RNG are typically shorter in duration than our fuel supply agreements. Accordingly, if we are unable to renew or replace an off-take agreement for a project for which we continue to produce RNG, we would be subject to the risks associated with selling the RNG produced at that project at then-current market prices. We may be required to make such sales at a time when the market price for natural gas as a whole or in the region where that project is located is depressed. If this were to occur, we would be subject to the volatility of gas prices and be unable to predict our revenues from such project, and the sales prices for such RNG may be lower than what we could sell the RNG for under an off-take agreement.
We are exposed to the risk of failing to meet our contractual commitments to sell RINs from our production.
We may sell forward a portion of our RINs under contracts to fix the revenues from such attributes for financing purposes or to manage our risk against future declines in prices of such Environmental Attributes. If our RNG projects do not generate the amount of RINs sold under such forward contracts we may be required to make up the shortfall of RINs under such forward contracts through purchases on the open market or the payment of liquidated damages. Forward selling our RINs could result in realized prices monetized in a year which do not correspond directly to index prices.
Regulatory Risks
The reduction or elimination of governmental economic incentives for renewable energy projects or other related policies could adversely affect our business, financial condition and results of operation.
We depend on Environmental Attributes, which are 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. RINs are created through the RFS program administered by the EPA, which requires transportation fuel sold in the United States to contain a minimum volume of renewable fuel and has historically permitted refineries and importers of transportation fuel to satisfy their RVOs by purchasing either (i) D5 RINs and cellulosic waiver credits (“CWCs”) or (ii) D3 RINs. In a December 1, 2022 proposed rule, EPA proposed to not utilize its cellulosic waiver authority for the years 2023-2025. However, if actual production is lower than the RVO, the EPA will have discretion to utilize CWC. This rule was finalized on July 12, 2023. On December 12, 2024, EPA proposed a partial waiver of 2024 Cellulosic Biofuel Volume Requirements due to the projected shortfall of D3 RINs available to meet the 2024 RVO. This rule was finalized on July 7, 2025. EPA made CWCs available for purchase under the final rule along with the partial waiver of the 2024 cellulosic biofuel volume requirement. The final rule also requires the use of a new data source for the average wholesale price of gasoline to be used in the calculation of the CWC price. The EPA proposed the 2026 and 2027 RVOs and a Partial Waiver of the 2025 Cellulosic Biofuel Volume Requirement on June 17, 2025. On August 22, 2025, the EPA issued decisions on 175 Small Refinery Exemptions (SREs) for the years 2023-2025. EPA subsequently proposed a Supplemental Rule (referred to as the SRE reallocation volume) on September 18, 2025, which would account for the for 2023-2025 exempted RVOs. EPA co-proposed SRE reallocation volumes that would account for 100 percent or 50 percent of the exemptions granted for the 2023-2025 compliance years. EPA is aiming to finalize new biofuel mandates for 2025, 2026 and 2027 along with the Supplemental Rule in late March 2026. RECs are created through state law requirements for utilities to purchase a portion of their energy from renewable energy sources. Approximately, 67% and 74% of our operating revenues for 2025 and 2024, respectively, were generated from the sale of Environmental Attributes. These government economic incentives could be reduced or eliminated altogether or interpretations of existing regulations or the categories of renewable energy qualifying for such government economic incentives could be changed. These renewable energy program incentives are subject to regulatory oversight and could be administratively or legislatively changed
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in a manner that could adversely affect our operations. Reductions in, changes to, or eliminations or expirations of governmental incentives could result in decreased demand for, and lower revenues from, our projects. Changes in the level or structure of the RPS of a state for electricity could also result in a decline in our revenues or decreased demand for, and lower revenues from, our electricity projects.
We may be unable to obtain, modify or maintain the regulatory permits, approvals and consents required to construct and operate our projects.
Our operations are subject to various federal, state, and local EHS laws and regulations, including those relating to the release, emission or discharge of materials into the air, water and ground, the generation, storage, handling, use, transportation and disposal of hazardous materials and wastes, the health and safety of our employees and other persons, and the generation of RINs and LCFS credits.
These laws and regulations impose numerous obligations applicable to our operations, including the acquisition of permits before construction and operation of our projects; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of our activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from the ownership or operation of our properties. These laws, regulations and permits can require expensive pollution control equipment or operational changes to limit actual or potential impacts to the environment.
Numerous governmental entities have the power to enforce difficult and costly compliance measures or corrective actions pursuant to these laws and regulations and the permits issued under them. We may be required to make significant capital and operating expenditures on an ongoing basis, or to perform remedial or other corrective actions at our properties, to comply with the requirements of these environmental laws and regulations or the terms or conditions of our permits. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required environmental regulatory permits or approvals, which may delay or interrupt our operations and limit our growth and revenue.
Our operations inherently risk incurring significant environmental costs and liabilities due to the need to manage waste from our processing facilities. Spills or other releases of regulated substances, including spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws, rules and regulations. Under certain such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damage to persons or property, including natural resources, may result from the EHS impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.
New laws, changes to existing laws, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments could require us to make significant additional expenditures and these additional expenditures may result in us terminating new projects or ceasing operations of existing projects. Present and future federal and state environmental laws and regulations, and interpretations of those laws and regulations, applicable to our operations, more vigorous enforcement policies and discovery of currently unknown conditions may require substantial expenditures that could have a material adverse effect on our results of operations and financial condition. On January 7, 2026, President Trump signed a presidential memorandum to exit the United Nations Framework Convention on Climate Change (UNFCCC) along with the Intergovernmental Panel on Climate Change (IPCC) and over 60 other international organizations, arguing they did not serve U.S. interests. While federal support for renewable projects may decline, states and the private sector are expected to continue driving development.
Our ability to generate revenue from sales of RECs, RINs and LCFS credits depends on our strict compliance with these federal and state programs, which are complex and can involve a significant degree of judgment. If the agencies that administer and enforce these programs disagree with our judgments, otherwise determine that we are not in compliance, conduct reviews of our activities or make changes to the programs, then our ability to generate or sell these credits could be temporarily restricted pending completion of reviews or as a penalty, permanently limited or lost entirely, and we could also be subject to fines or other sanctions. Moreover, the inability to sell RINs and LCFS credits could adversely affect our business.
In order to construct, modify and operate our projects, we will need to obtain or may need to modify numerous environmental and other regulatory permits, approvals and consents from federal, state and local governmental entities, including air permits, wastewater discharge permits, stormwater permits, permits or consents related to the management of municipal solid waste landfills and permits or consents related to the management and disposal of waste. A number of these permits, approvals and consents must be obtained prior to the start of development of a project. Other permits, approvals and consents are required to be obtained at, or prior to,
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the time of first commercial operation or within prescribed time frames following commencement of commercial operations. Any failure to successfully obtain or modify the necessary environmental and other regulatory permits, approvals and consents on a timely basis could delay the construction, modification or commencement of commercial operation of our projects. In addition, once a permit, approval or consent has been issued or acquired for a project, we must take steps to comply with the conditions of each permit, approval or consent conditions, including conditions requiring timely development and commencement of the project. Failure to comply with certain conditions within a permit, approval or consent could result in the revocation or suspension of such permit, approval or consent; the imposition of penalties; or other enforcement action by governmental entities. We also may need to modify permits, consents or approvals we have already obtained to reflect changes in project design or requirements, which could trigger a legal or regulatory review under a standard more stringent than the standard under which the permits, approvals or consents were originally issued.
Obtaining and modifying necessary permits, approvals and consents is a time-consuming and expensive process, and we may not be able to obtain or modify them on a timely or cost-effective basis or at all. In the event that we fail to obtain or modify all necessary permits, approvals or consents, we may be forced to delay construction or operation of a project or abandon the project altogether, which could adversely affect our business, financial condition and results of operations. In addition, we may be required to make capital expenditures on an ongoing basis to comply with increasingly stringent federal, state, provincial and local EHS laws, regulations and permits.
Negative attitudes toward renewable energy projects from the U.S. government, other lawmakers and regulators, and activists could adversely affect our business, financial condition and results of operations.
Parties with an interest in other energy sources, including lawmakers, regulators, policymakers, environmental and advocacy organizations or other activists may invest significant time and money in efforts to delay, repeal or otherwise negatively influence regulations and programs that promote renewable energy. Many of these parties have substantially greater resources and influence than we have. Further, changes in U.S. federal, state or local political, social or economic conditions, including a lack of legislative focus on these programs and regulations, could result in their modification, delayed adoption or repeal. Any failure to adopt, delay in implementing, expiration, repeal or modification of these programs and regulations, or the adoption of any programs or regulations that encourage the use of other energy sources (such as coal) over renewable energy, could adversely affect our business, financial condition and results of operations. The current presidential administration’s focus on maximizing coal, oil, and gas production primarily hurts the renewable energy sector by reducing and eliminating financial incentives, pausing wind/solar projects on public lands, and creating regulatory uncertainty. Policies aimed at reversing climate change progress and prioritizing fossil fuels have slowed investment, though market forces and state-level actions continue to drive clean energy growth.
On January 20, 2025, Executive Order 14154 was signed and directed agencies to review agency actions that may “impose an undue burden” on domestic energy resources. In particular, President Trump directed the EPA to make a recommendation within 30 days regarding the legality and continuing applicability of the 2009 Endangerment Finding for greenhouse gas emissions under the Clean Air Act.
On March 12, 2025, the EPA Administrator Zeldin announced that the EPA would reconsider the 2009 Endangerment Finding, as well as “regulations and actions that rely on that Finding,” which likely include EPA’s 2024 GHG performance standards for the electric utility sector, the 2024 methane performance standards for the refining sector, and various light-, medium-, and heavy-duty vehicle emission standards, among other actions. On June 11, 2025, Zeldin proposed to repeal all “greenhouse gas” emissions standards for fossil fuel-fired power plants. On February 12, 2026, the EPA formally repealed the 2009 Greenhouse Gas Endangerment Finding, a foundational policy that determined carbon dioxide and other greenhouse gases pose a threat to public health and welfare. This action, described by officials as the largest deregulatory move in U.S. history, removes the legal basis for federal regulation of greenhouse gas emissions from vehicles, power plants, and oil and gas operations. While these policies aim to boost fossil fuels, economic trends suggest that clean energy is increasingly competitive, leading some to view this approach as a temporary obstacle rather than a permanent halt to the energy transition.
Revenue from any projects we complete may be adversely affected if there is a decline in public acceptance or support of renewable energy, or regulatory agencies, local communities, or other third parties delay, prevent, or increase the cost of constructing and operating our projects.
Certain persons, associations and groups could oppose renewable energy projects in general or our projects specifically, citing, for example, misuse of water resources, landscape degradation, land use, food scarcity or price increase and harm to the environment. Moreover, regulation may restrict the development of renewable energy plants in certain areas. In order to develop a renewable energy project, we are typically required to obtain, among other things, environmental impact permits or other authorizations and building permits, which in turn require environmental impact studies to be undertaken and public hearings and comment periods to be held during which any person, association or group may oppose a project. Any such opposition may be considered by government officials responsible for granting the relevant permits, which could result in the permits being delayed or not being granted or being granted
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solely on the condition that we carry out certain corrective measures to the proposed project. Opposition to our projects’ requests for permits or successful challenges or appeals to permits issued for our projects could adversely affect our operating plans.
As a result, we cannot guarantee that the renewable energy plants we currently plan to develop or, to the extent applicable, are developing, will ultimately be authorized or accepted by the local authorities or the local population. For example, the local population could oppose the construction of a renewable energy plant or infrastructure at the local government level, which could in turn lead to the imposition of more restrictive requirements. This type of negative response may lead to legal, public relations or other challenges that could impede our ability to meet our construction targets, achieve commercial operations for a project on schedule, address the changing needs of our projects over time or generate revenues.
In certain jurisdictions, if a significant portion of the local population were to mobilize against a renewable energy plant, it may become difficult, or impossible, for us to obtain or retain the required building permits and authorizations. Moreover, such challenges could result in the cancellation of existing building permits or even, in extreme cases, the dismantling of, or the retroactive imposition of changes in the design of, existing renewable energy plants.
Authorization for the use, construction, and operation of systems and associated transmission facilities on federal, state, and local lands will also require the assessment and evaluation of mineral rights, private rights-of-way, and other easements; environmental, agricultural, cultural, recreational, and aesthetic impacts; and the likely mitigation of adverse effects to these and other resources and uses. The inability to obtain the required permits and other federal, state and local approvals, and any excessive delays in obtaining such permits and approvals due, for example, to litigation or third-party appeals, could potentially prevent us from successfully constructing and operating such projects in a timely manner and could result in the potential forfeiture of any deposit we have made with respect to a given project. Moreover, project approvals subject to project modifications and conditions, including mitigation requirements and costs, could affect the financial success of a given project. Changing regulatory requirements and the discovery of unknown site conditions could also adversely affect the financial success of a given project.
A decrease in acceptance of renewable energy plants by local populations, an increase in the number of legal challenges, or an unfavorable outcome of such legal challenges could adversely affect our business, financial condition and results of operations. We may also be subject to labor unavailability due to multiple simultaneous projects in a geographic region. If we are unable to grow and manage the capacity that we expect from our projects in our anticipated timeframes, it could adversely affect our business, financial condition and results of operations.
Existing regulations and policies, and future changes to these regulations and policies, may present technical, regulatory and economic barriers to the generation, purchase and use of renewable energy, and may adversely affect the market for credits associated with the production of renewable energy.
The market for renewable energy is influenced by U.S. federal, state and local government regulations and policies concerning renewable energy. These regulations and policies are continuously being modified, which could result in a significant future reduction in the potential demand for renewable energy, including RINs, RECs and LCFS credits, renewable energy project development and investments. For example, on December 12, 2024, EPA proposed a partial waiver of 2024 Cellulosic Biofuel Volume Requirements due to the projected shortfall of D3 RINs available to meet the 2024 RVO. This rule was finalized on July 7, 2025. EPA made CWCs available for purchase under the final rule along with the partial waiver of the 2024 cellulosic biofuel volume requirement. Any new government regulations applicable to our renewable energy projects or markets for renewable energy may result in significant additional expenses or related development costs and, as a result, could cause a significant reduction in demand for our renewable energy. For additional information on regulatory developments, see “Item 7A.—Management’s Discussion and Analysis of Financial Condition and Results of Operations —Key Trends—Regulatory, Environmental and Social Trends.”
In order to benefit from RINs and LCFS credits, our RNG projects are required to be registered and are subject to regulatory audit.
We are required to register an RNG project with the EPA and relevant state regulatory agencies to generate Environmental Attributes. As a participant of the EPA's RFS program, we qualify our RINs through a voluntary Quality Assurance Plan, which typically takes from three to five months from first injection of RNG into the commercial pipeline system. The Biogas Regulatory Reform Rule ("BRRR") implemented changes to the RFS program effective January 1, 2025. 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 has proven to 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. Furthermore, although no similar qualification process currently exists for LCFS credits, we expect such a process to be implemented and would expect to seek qualification on a state-by-state basis under such future programs. Changes to the LCFS program require annual verification of the CI
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score assigned to a project. Annual verification could significantly affect the profitability of a project, particularly in the case of a livestock farm project. Delays in obtaining registration, RIN qualification, and any future LCFS credit qualification, or change in CI scores through CARB annual audits, of a new project could delay future revenues from the project and could adversely affect our cash flow. Further, we typically make a large investment in the project prior to receiving the regulatory approval and RIN qualification. BRRR now requires that all RNG producers register their projects and use a Quality Assurance Plan (QAP). QAPs required third-party audits and semi-annual on-site visits of projects to validate generated RINs and overall compliance with the RFS program. We are also subject to a separate third party’s annual attestation review. The QAP provides a process for RIN owners to follow, for an affirmative defense to civil liability, if used or transferred QAP verified RINs were invalidly generated. A project’s failure to comply could result in remedial action by the EPA, including penalties, fines, retirement of RINs, or termination of the project’s registration, any of which could adversely affect our business, financial condition and results of operations. For additional information on recent developments in this area, including the Pico facility’s CI score, see “Item 7A.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Trends—Regulatory, Environmental and Social Trends.”
Our business is subject to the risk of extreme or changing weather patterns.
Extreme weather patterns related to climate change could cause changes in rainfall and storm patterns and intensities, water shortages and changing temperatures, which could result in significant volatility in the supply and prices of energy. In addition, legislation and increased regulation regarding climate change could impose significant costs on us and our suppliers, including costs related to capital equipment, environmental monitoring and reporting and other costs to comply with such regulations.
Furthermore, extreme weather events, such as lightning strikes, ice storms, tornados, extreme wind, hurricanes and other severe storms, wildfires and other unfavorable weather conditions or natural disasters, such as droughts, floods, fires, earthquakes, and rising sea-levels, could adversely affect the input and output commodities associated with the renewable energy sector. Such weather events or natural disasters could also require us to temporarily or permanently shut down the equipment associated with our renewable energy projects, such as our access to power and our power to biogas collection, separation and transmission systems, which would impede the ability of our projects to operate and decrease production levels and our revenue. Operational problems, such as degradation of our project’s equipment due to wear or weather or capacity limitations or outages on the electrical transmission network, could also affect the amount of energy that our projects are able to deliver. Any of these events, to the extent not fully covered by insurance, could adversely affect our business, financial condition and results of operations.
These events could result in significant volatility in the supply and prices of energy. This volatility may create fluctuations in commodity or energy prices and earnings of companies in the renewable energy sectors. See “—Operational Risks—“The concentration in revenues from five of our projects and geographic concentration of our projects expose us to greater risks of production interruptions from severe weather or other interruptions of production or transmission” for additional information.
Cybersecurity and Information Technology Risks
A failure of our IT and data security infrastructure could have a material adverse effect on our business and operations.
We rely upon the capacity, reliability and security of our IT and data security infrastructure and our ability to expand and continually update this infrastructure in response to the changing needs of our business. Our existing IT systems and any new IT systems may not perform as expected. We also face the challenge of supporting our older systems and implementing necessary upgrades. If we experience a problem with the functioning of an important IT system or a security breach of our IT systems, including during system upgrades or new system implementations, the resulting disruptions could have a material adverse effect on our business.
We and some of our third-party vendors receive and store personal information in connection with our human resources operations and other aspects of our business. Our IT systems and those of our third-party vendors, are vulnerable to damages from computer viruses, natural disasters, fire, power loss, telecommunications failures, personnel misconduct, human error, unauthorized access, physical or electronic security breaches, cyber-attacks (including malicious and destructive code, phishing attacks, ransomware, and denial of service attacks), and other similar disruptions. We continue to develop our processes relating to identification, mitigation and response to potential cybersecurity threats, and such processes may prove to be inadequate. Such attacks or security breaches may be perpetrated by bad actors internally or externally (including computer hackers, persons involved with organized crime, or foreign state or foreign state-supported actors). Cybersecurity threat actors employ a wide variety of methods and techniques that are constantly evolving, increasingly sophisticated, and difficult to detect and successfully defend against. Cybersecurity incidents involving our IT systems or those of our third-party vendors could expose us to claims, litigation, regulatory or other governmental investigations, administrative fines and potential liability. Any system failure, accident or security breach could result in disruptions to our operations. A material network breach in the security of our IT systems or those of our third-party vendors could include the theft of our trade secrets, customer information, human resources information or other confidential data, including but not limited to personally identifiable information, that could have a material adverse effect on our business, financial condition, or results of operations. To the extent that any material disruptions or security breaches result in a loss or damage to our data, or an inappropriate disclosure of confidential, proprietary or customer information, it could materially cause damage to our reputation,
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affect our relationships with our customers and strategic partners, lead to claims against us from governments and private plaintiffs, and ultimately have a material adverse effect on our business. While we have been the previous target of cyberattacks and security breaches, none of these attacks or breaches to date have had a material adverse effect on us. We cannot guarantee that future cyberattacks, if successful, will not have a material effect on our business or financial results.
Many governments have enacted laws requiring companies to provide notice of cyber incidents involving certain types of data, including personal data. Any compromise of our security could result in a violation of applicable domestic and foreign security, privacy or data protection, consumer and other laws, regulatory or other governmental investigations, enforcement actions, and legal and financial exposure, including potential contractual liability that could have a material adverse effect on our business. In addition, we may be required to incur significant costs to protect against and remediate damage caused by these disruptions or security breaches in the future that could have a material adverse effect on our business.
We rely on the technology, infrastructure, and software applications of certain third parties in order to host or operate some of our business. Additionally, we rely on computer hardware purchased in order to operate our business. We do not have control over the operations of the facilities of the third parties that we use. However, our recent adoption of a governance, risk and compliance platform to manage third party risk will help us establish and maintain a formalized program. If any of these third-party services experience errors, disruptions, security issues, or other performance deficiencies, if these services, software, or hardware fail or become unavailable due to extended outages, interruptions, defects, or otherwise, or if they are no longer available on commercially reasonable terms or prices (or at all), these issues could result in material errors or defects in our platforms (including causing our platforms to fail), our revenue and margins could materially decline, or our reputation and brand to be materially damaged. Additionally, we could be exposed to material legal or contractual liability, our expenses could materially increase, our ability to manage our operations could be materially interrupted, and our processes for servicing our customers could be materially impaired until equivalent services or technology, if available, are identified, procured, and implemented, all of which may take significant time and resources, increase our costs, and could materially and adversely affect our business. Many of these third-party providers attempt to impose limitations on their liability for such errors, disruptions, defects, performance deficiencies, or failures, and if such limitations are enforceable, we may have additional liability to our customers or third-party providers that could have a material adverse effect on our business. A failure to maintain our relationships with our third-party providers (or obtain adequate replacements), and to receive services from such providers that do not contain any material errors or defects, could adversely affect our ability to deliver effective products and solutions to our customers and adversely affect our business and results of operations.
Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions.
As a renewable energy producer, we face various security threats, including among others, computer viruses, malware, ransomware, telecommunication and electrical failures, cyber-attacks or cyber-intrusions over the internet, attachments to emails, persons with access to systems inside our organization, cybersecurity threats to gain unauthorized access to sensitive information or to expose, exfiltrate, alter, delete or render our data or systems unusable, threats to the security of our projects and infrastructure or third-party facilities and infrastructure, such as processing projects and pipelines, natural disasters, threats from terrorist acts and war.
As cyber incidents become more frequent and the sophistication of threat actors increases, our associated cybersecurity costs have and are expected to continue to increase. Recent advancements in our cybersecurity program, such as the adoption of a governance, risk, and compliance platform, provide us with more information to manage and report on our technical controls environment, maintain a functional cyber risk register, evaluate third party risk and measure our cyber initiatives against standard industry frameworks. Despite our ongoing and anticipated cybersecurity efforts, a successful cybersecurity incident could lead to additional material costs, including those related to the loss of sensitive information, repairs to infrastructure or capabilities essential to our operations, responding to litigation or regulatory investigations, and those related to a material and adverse impact on our reputation, financial position, results of operations, or cash flows.
Third-Party Partner Risks
Failure of third parties to manufacture quality products or provide reliable services in a timely manner could cause delays in developing and operating our projects, which could damage our reputation, adversely affect our partner relationships or adversely affect our growth.
Our success depends on our ability to develop and operate projects in a timely manner, which depends in part on the ability of third parties to provide us with timely and reliable products and services. In developing and operating our projects, we rely on products meeting our design specifications and components manufactured and supplied by third parties, and on services performed by subcontractors. We also rely on subcontractors to perform substantially all of the construction and installation work related to our projects, and we often need to engage subcontractors with whom we have no experience.
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If any of our subcontractors are unable to provide services that meet or exceed our customers’ expectations or satisfy our contractual commitments, our reputation, business and operating results could be harmed. For example, our development of the Montauk AG project in Turkey, North Carolina has been delayed due to the inability of the construction company to meet agreed upon deadlines. Furthermore, suppliers for this project have been unable to provide need materials to complete construction in a timely manner. In addition, if we are unable to avail ourselves of warranties and other contractual protections with providers of products and services, we may incur liability to our customers or additional costs related to the affected products and services, which could adversely affect our business, financial condition and results of operations. Moreover, any delays, malfunctions, inefficiencies or interruptions in these products or services could adversely affect the quality and performance of our projects and require considerable expense to maintain and repair our projects. This could cause us to experience interruption in our production and distribution of renewable energy and generation of related Environmental Attributes, difficulty retaining current relationships and attracting new relationships, or harm our brand, reputation or growth.
Our projects rely on interconnections with and access to electric distribution and transmission facilities and gas transportation pipelines that are owned and operated by third parties, and as a result, are exposed to risks related to such facilities’ development and operational curtailment risks.
Our projects are interconnected with electric distribution and transmission facilities owned and operated by regulated utilities necessary to deliver the Renewable Electricity that we produce. Our RNG projects are similarly interconnected with gas distribution and interstate pipeline systems required to deliver RNG. A failure or delay in the operation or development of these distribution or transmission facilities could result in a loss of revenues or breach of contract because such a failure or delay could limit the amount of RNG and Renewable Electricity that our operating projects deliver or delay the completion of our construction projects. In addition, certain of our operating projects’ generation may be curtailed without compensation due to distribution and transmission limitations, reducing our revenues and impairing our ability to capitalize fully on a particular project’s potential. Such a failure or curtailment at levels above our expectations could impact our ability to satisfy our supply agreements and adversely affect our business. Additionally, we experience work interruptions from time to time due to federally required maintenance shutdowns.
We are dependent upon our relationships with Waste Management and Republic Services for the operation and maintenance of landfills on which several of our RNG and Renewable Electricity projects operate.
We currently operate seven renewable energy projects (six RNG projects and one Renewable Electricity project) on landfills operated by Waste Management and two RNG projects on landfills operated by Republic Services. Our projects located on Waste Management operated landfills represented 36.8%, 38.5% and 37.3% of our revenue in 2025, 2024, and 2023, respectively. Our projects located on Republic Services operated landfills represented 19.9%, 24.6% and 22.2% of our revenue in 2025, 2024 and 2023, respectively. We are dependent upon Waste Management and Republic Services to operate and maintain their landfill facilities and provide a continuous supply of waste for conversion to RNG and Renewable Electricity. Further, we consider our relationship with these landfill operators an important factor in our growth strategy for additional projects. In the event that we fall out of favor with either of these landfill operators due to a dispute, problems with our operations at one of their facilities or otherwise, the landfill operator may seek to terminate the related project and be less inclined to work with us on future projects.
Additionally, Waste Management and Republic Services could seek to develop their own waste-to-renewable energy conversion projects at other existing landfill locations in lieu of contracting with us for these projects. Failure to maintain these favorable relationships could adversely affect our business, growth strategy, financial condition and results of operations.
Capital and Credit Risks
Our senior credit facility may not be sufficient to meet our financial needs and contains financial and operating restrictions that may limit our business activities and our access to other forms of credit.
On March 9, 2026, we established a new senior credit facility that consists of up to $200.0 million in senior indebtedness, of which $155.0 million is outstanding as of March 11, 2026. This facility may not be sufficient to meet our financial needs as our business grows. The senior credit facility matures in March 2031 and we may be unable to extend or replace it on acceptable terms, or at all. Furthermore, the credit agreement governing our facility (the “Credit Agreement”) imposes business restrictions and contains other covenants that require us to meet specified financial ratios and financial tests. Under the Credit Agreement, which became applicable upon entry into the new facility on March 9, 2026, we are required to maintain:
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The Credit Agreement is subject to customary events of default, and contemplates that we would be in default if, for any fiscal quarter, the average monthly D3 RIN price is less than $1.00 per RIN. Additional information regarding the senior credit facility and the Credit Agreement can be found in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
Our failure to comply with these covenants could result in the declaration of an event of default and cause us to be unable to borrow under the Credit Agreement. In addition to preventing additional borrowings under the Credit Agreement, an event of default, if not cured or waived, could result in the acceleration of the maturity of indebtedness outstanding under the facility, which would require us to immediately repay all amounts outstanding. If an event of default occurs, we may not be able to cure it within any applicable cure period, or at all.
We may be required to write-off or impair capitalized costs or intangible assets in the future or we may incur restructuring costs or other charges, each of which would harm our earnings.
In accordance with GAAP, we capitalize certain expenditures and advances relating to our acquisitions, pending acquisitions, project development costs, interest costs related to project financing and certain energy assets. In addition, we have considerable unamortized assets. In 2025, we recorded impairment charges of $3.2 million of which $2.7 related to an RNG development project interconnection for which the local utility is no longer accepting RNG into its distribution system and $0.5 million of RNG and REG assets that were deemed obsolete or inoperable for current operations. In 2024, we recorded impairment charges of $1.6 million of which $1.0 related to RNG and REG assets that were deemed obsolete or inoperable for current operations, $0.3 million related to an REG site that ceased operations and was subsequently sold, and $0.3 related to REG assets following initial startup testing failures for one of our construction work in progress sites. In 2023, we recorded impairment charges of $0.9 million of which $0.8 million related to specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use and $0.1 related to obsolete REG critical spares. In addition, from time to time in future periods, we may be required to incur a charge against earnings in an amount equal to any unamortized capitalized expenditures and advances, net of any portion thereof that we estimate will be recoverable, through sale or otherwise, relating to: (i) any operation or other asset that is being sold, permanently shut down, impaired or has not generated or is not expected to generate sufficient cash flow; (ii) any pending acquisition that is not consummated; (iii) any project that is not expected to be successfully completed; and (iv) any goodwill or other intangible assets that are determined to be impaired. A material write-off or impairment change could adversely affect our ability to comply with the financial covenants under the Credit Agreement, and otherwise adversely affect our business, financial condition and results of operations.
Emerging Growth Company Risks
We are in our last year of being an emerging growth company and will soon be required to comply with certain requirements that apply to other public companies.
For so long as we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. We cannot predict whether investors will find our common stock less attractive because we will rely on these exemptions. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.
Starting with our 2026 Form 10-K to be filed in the first quarter of 2027, we will no longer qualify as an emerging growth company, as defined in the JOBS Act. We will then be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide additional comprehensive disclosures regarding executive compensation required of larger public companies; and (iv) hold nonbinding advisory votes on executive compensation and any golden-parachute payments not previously approved.
As a public company, we are subject to the reporting requirements of the Exchange Act, the Sarbanes-Oxley Act of 2002, the Dodd-Frank Act, the listing requirements of The Nasdaq Stock Market LLC, and other applicable securities rules and regulations. Despite reforms made possible by the JOBS Act, compliance with these rules and regulations have nonetheless increased our legal and financial compliance costs, made some activities more difficult, time-consuming or costly, and increased demand on our systems and resources, and such compliance costs will be exacerbated after we are no longer an emerging growth company.
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If we identify material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, we may be unable to accurately or timely report our financial condition or results of operations, which may adversely affect our business.
We are required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act, which require management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of controls over financial reporting. As an emerging growth company, our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal controls over financial reporting pursuant to Section 404 until our Form 10-K for the year ended December 31, 2026. At such time, our independent registered public accounting firm may issue a report that is adverse if it is not satisfied with the level at which our controls are documented, designed or operating.
If we identify material weaknesses in our internal controls over financial reporting or are unable to comply with the requirements of Section 404 or assert that our internal controls over financial reporting are effective, or if our independent registered public accounting firm is unable to express an opinion as to the effectiveness of our internal controls over financial reporting, investors may lose confidence in the accuracy and completeness of our financial reports and the market price of our common stock could be negatively affected. In addition, we could become subject to investigations by the SEC or other regulatory authorities, which could require additional financial and management resources. Failure to remedy any material weakness in our internal control over financial reporting or to implement or maintain other effective control systems required of public companies could also restrict our future access to capital markets.
Compiling the system and processing documentation necessary to perform the evaluation needed to comply with Section 404 is costly and challenging. Our compliance with Section 404 requires that we incur substantial accounting expense and expend significant management efforts. We have hired and may need to continue to hire additional accounting and financial staff with appropriate public company experience and technical accounting knowledge and compile the system and process documentation necessary to maintain effective internal control over financial reporting.
Common Stock Risks
Our shares of common stock may trade on more than one market and this may result in price variations.
The Company’s common stock is traded on the Nasdaq Capital Market under the ticker symbol of “MNTK” and on the JSE under the ticker symbol of “MKR.” Trading in our common stock takes place in USD on the Nasdaq Capital Market and ZAR on the JSE, and at different times, resulting from different time zones, trading days and public holidays in the United States and South Africa. The trading prices of our common stock on these two markets may differ due to these and other factors. Any decrease in the price of our common stock on either exchange could cause a corresponding decrease in the trading price of the common stock on the other exchange.
Future sales of our common stock in the public market could cause the market price of our common stock to decline.
Sales of a substantial number of shares of our common stock in the public market, or the perception that these sales might occur, could depress the market price of our common stock and could impair our ability to raise capital through the sale of additional equity securities. Many of our existing equity holders have substantial unrecognized gains on the value of the equity they hold and may take steps to sell their shares or otherwise secure the unrecognized gains on those shares.
We are a “controlled company” within the meaning of the Nasdaq rules and, as a result, qualify for, and intend to rely on, exemptions and relief from certain governance requirements.
Stockholder affiliates of Mr. Copelyn and Mr. Govender have entered into a Consortium Agreement whereby they agree to act together when voting our common stock in the election of directors, among other matters. The parties to the Consortium Agreement beneficially owned, in the aggregate, approximately 52.3% of our common stock as of February 28, 2026. As a result, we are a “controlled company” within the meaning of the Nasdaq corporate governance standards. Under these corporate governance standards, a company of which more than 50% of the voting power in the election of directors is held by an individual, group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements. For example, controlled companies are not required to have:
We may rely on any or all of these exemptions so long as we remain a controlled company.
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The concentration of our capital stock ownership may limit our stockholders’ ability to influence corporate matters and may involve other risks.
As a result of the Consortium Agreement, certain stockholders control matters requiring stockholder approval, including the election of our directors and approval of significant corporate transactions. This concentration of ownership may also have the effect of delaying or preventing a change in control that may be otherwise viewed as beneficial by stockholders other than management. Accordingly, other stockholders may not have any influence over significant corporate transactions and other corporate matters. There is also a risk that certain controlling stockholders may have interests which are different from other stockholders and that they will pursue an agenda which is beneficial to themselves at the expense of other stockholders.
Certain of our directors reside outside of the United States and it may be difficult to enforce judgments against them in the United States.
One of our directors, all of our executive officers and all of our operating assets reside in the United States. Directors Copelyn, Govender, Ahmed and Shaik are residents of South Africa. As a result, it may not be possible for you to effect service of legal process, within the United States or elsewhere, upon certain of our directors, including matters arising under U.S. federal securities laws. This may make it difficult or impossible to bring an action against these individuals in the United States in the event that a person believes that their rights have been violated under applicable law or otherwise. Even if an action of this type is successfully brought, the laws of the United States and South Africa may render a judgment unenforceable.
General Risk Factors
If securities or industry analysts do not publish research or publish inaccurate or unfavorable research about our business, our share price and trading volume could decline.
The trading market for our common stock will be influenced by the research and reports that securities or industry analysts publish about us. If securities or industry analysts initiate coverage and one or more of the analysts who cover us downgrade our common stock or publish inaccurate or unfavorable research about our company, our common stock share price would likely decline. If analysts publish target prices for our common stock that are below historical sales prices or the then-current public price of our common stock, it could cause our stock price to decline significantly. Further, if one or more of these analysts cease coverage of us or fail to publish reports on us regularly, demand for our common stock could decrease, which might cause our common stock price and trading volume to decline.
We are highly dependent on our senior management team and other highly skilled personnel, and if we are not successful in attracting or retaining highly qualified personnel, we may not be able to successfully implement our business strategy.
Our success depends, in significant part, on the continued services of our senior management team and on our ability to attract, motivate, develop and retain a sufficient number of other highly skilled personnel, including engineering, design, finance and support personnel. Our senior management team has extensive experience in the renewable energy industry, and we believe that their depth of experience is instrumental to our continued success. The loss of any one or more members of our senior management team, for any reason, including resignation or retirement, could impair our ability to execute our business strategy and adversely affect our business, financial condition and results of operations.
Competition for qualified highly skilled personnel can be strong, and we cannot assure you that we will be successful in attracting or retaining such personnel now or in the future. Any inability to recruit, develop and retain qualified employees may result in high employee turnover and may force us to pay significantly higher wages, which may harm our profitability. Additionally, we do not carry key personnel insurance for any of our management executives, and the loss of any key employee or our inability to recruit, develop and retain these individuals as needed, could adversely affect our business, financial condition and results of operations.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 1C. CYBERSECURITY.
We have processes in place for identifying, assessing and managing material risks associated with cybersecurity threats. For a discussion of how risks from cybersecurity threats affect our business, please see our Risk Factors discussion under the heading, “Cybersecurity and Information Technology Risks” in this Form 10-K.
Risk Management and Strategy
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Enterprise risk management is the responsibility of our executive management team consisting of our chief executive officer, chief financial officer, chief legal officer, chief operations officer and our vice president of environmental, health and safety.
With respect to our employees, we run a multi-faceted security awareness program that includes regular, mandatory trainings for our personnel on data protection and malware detection, policy and process awareness, periodic phishing simulations and other kinds of preparedness testing.
As part of our Sarbanes-Oxley controls, our Internal Audit department tests our IT policies including those pertaining to passwords, backup and recovery, user access, change control and hardware and software maintenance. These audits assess key information security and cybersecurity risks in the environment that may affect the confidentiality, integrity and availability of financial reporting systems and data. Additionally, key employees complete a survey containing questions about cybersecurity in connection with the quarterly Sarbanes-Oxley certification process.
As of the date of this Annual Report on Form 10-K, we have not implemented formal processes to oversee and identify risks from cybersecurity threats associated with our use of third parties. We are working toward the implementation of a third-party risk management program. We believe that this program will better enable us to identify and manage material risks from cybersecurity threats related to our third-party service providers.
Governance
ITEM 2. PROPERTIES.
We own approximately 216 acres in Turkey, NC for which we are using to develop Montauk Ag Renewables. Montauk Ag Renewables is reported in our Renewable Electricity Generation segment.
Our principal executive office is located in Pittsburgh, Pennsylvania. We lease an approximate 24,000 square foot office space at this site for approximately $45,000 per month pursuant to a lease which expires on April 30, 2033.
We also lease an 8,400 square foot regional office and warehouse to service our sites in Houston, Texas, pursuant to a lease which expires on December 31, 2026, for approximately $8,000 per month. We currently own and operate 13 projects, 11 of which are RNG projects and two of which are Renewable Electricity projects. See “Item 1. Business—Our Current Operating Portfolio” for further descriptions of our projects, which information is incorporated into this item by reference.
ITEM 3. 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. None of our directors, officers, affiliates, or any owner of record or beneficial owner of more than 5% of our common stock, is involved in a material proceeding adverse to us or our subsidiaries or has a material interest adverse to us or our subsidiaries.
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ITEM 4. MINE SAFETY DISCLOSURES.
Not Applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Market Information
The Company’s common stock has traded on the Nasdaq Capital Market under the ticker symbol of “MNTK” and on the JSE under the ticker symbol of “MKR” since January 22, 2021. Prior to that time, there was no established public trading market for the Company’s common stock.
Holders of Montauk Common Stock
As of March 6, 2026, there were 12 holders of record of 143,717,391 shares of Montauk common stock outstanding as of such date. The number of holders of record of Montauk common stock does not reflect the number of beneficial holders whose shares are held by depositaries, brokers or other nominees.
Performance Graph
The following stock performance graph compares our total stock return with the total return for (a) NASDAQ Composite Index and (b) an industry peer group. Our 2025 and 2024 peer group, which is comprised of companies that we believe have comparable characteristics and are in the same industry or line-of-business, consists of Ameresco, Inc., Aemetis, Inc., Anaergia, Inc., Clean Energy Fuels Corp., Gevo, Inc., and Opal Fuels, Inc. The graph assumes that on January 22, 2021, the date our common stock began trading on the Nasdaq Capital Market, $100 was invested in our common stock and in each index based on the closing market price on that day and that all dividends were reinvested. The returns shown are based on historical events and are not intended to suggest future performance.
The following performance graph and related information is being furnished and shall not be deemed “soliciting material” or “filed” with the SEC for purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities under that section, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent we specifically incorporate it into reference into such filing.
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1/22/21 |
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3/31/21 |
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6/30/21 |
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9/30/21 |
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12/31/21 |
|
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3/31/22 |
|
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6/30/22 |
|
|
9/30/22 |
|
|
12/31/22 |
|
|||||||||
Montauk Renewables, Inc. |
|
|
100.00 |
|
|
|
116.49 |
|
|
|
73.87 |
|
|
|
108.29 |
|
|
|
98.84 |
|
|
|
108.00 |
|
|
|
96.91 |
|
|
168.18 |
|
|
106.36 |
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||
NASDAQ Composite |
|
|
100.00 |
|
|
|
102.95 |
|
|
|
112.92 |
|
|
|
112.66 |
|
|
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122.18 |
|
|
|
111.25 |
|
|
|
86.46 |
|
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83.08 |
|
|
82.43 |
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||
Peer Group |
|
|
100.00 |
|
|
|
121.76 |
|
|
|
85.76 |
|
|
|
78.41 |
|
|
|
54.99 |
|
|
|
65.34 |
|
|
|
34.06 |
|
|
38.35 |
|
|
34.48 |
|
||
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|||||||||
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3/31/23 |
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6/30/23 |
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9/30/23 |
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12/31/23 |
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3/31/24 |
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6/30/24 |
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9/30/24 |
|
|
12/31/24 |
|
|
3/31/25 |
|
|||||||||
Montauk Renewables, Inc. |
|
|
75.89 |
|
|
|
71.75 |
|
|
|
87.85 |
|
|
|
85.92 |
|
|
|
40.12 |
|
|
|
54.97 |
|
|
|
50.24 |
|
|
|
38.38 |
|
|
|
20.15 |
|
NASDAQ Composite |
|
|
96.48 |
|
|
|
109.07 |
|
|
|
104.77 |
|
|
|
119.22 |
|
|
|
130.32 |
|
|
|
141.36 |
|
|
|
145.26 |
|
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|
154.48 |
|
|
|
138.62 |
|
Peer Group |
|
|
47.23 |
|
|
|
49.77 |
|
|
|
42.25 |
|
|
|
35.22 |
|
|
|
28.09 |
|
|
|
27.16 |
|
|
|
33.85 |
|
|
|
27.12 |
|
|
|
15.36 |
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6/30/25 |
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9/30/25 |
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12/31/25 |
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Montauk Renewables, Inc. |
|
|
21.41 |
|
|
|
19.38 |
|
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|
16.10 |
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|
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|
|
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NASDAQ Composite |
|
|
163.52 |
|
|
|
182.18 |
|
|
|
187.14 |
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|
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Peer Group |
|
|
19.72 |
|
|
|
31.97 |
|
|
|
28.27 |
|
|
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Dividend Policy
The Company did not pay any dividends in the fiscal year ended December 31, 2025 and currently intends to retain future earnings, if any, to finance the operations, growth and development of its business. Any future determination as to the declaration and payment of dividends, if any, will be at the discretion of our Board of Directors, subject to compliance with contractual restrictions and covenants in the agreements governing our current and future indebtedness and the DGCL. Any such determination will also depend upon our business prospects, results of operations, financial condition, cash requirements and availability, and other factors that our Board of Directors may deem relevant.
Securities Authorized for Issuance Under Equity Compensation Plans
The information required by Item 5 of Form 10-K regarding equity compensation plans is incorporated herein by reference to Item 12 of Part III of this Annual Report.
Issuer Repurchases of Equity Securities
None.
Recent Sales of Unregistered Securities
None.
ITEM 6. RESERVED
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ITEM 7. 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 Annual Report on Form 10-K. Amounts are in thousands unless indicated otherwise.
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” and “Item 1A.–Risk Factors” and elsewhere in this report.
This section generally discusses our results of operations for the year ended December 31, 2025 compared to the year ended December 31, 2024. For discussion and analysis of our results for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K filed with the SEC on March 14, 2025.
Overview
Montauk is a renewable energy company specializing in the recovery and processing of biogas from landfills and other non-fossil fuel sources for beneficial use as a replacement to fossil fuels. We develop, own, and operate RNG projects, using proven technologies that supply RNG into the transportation industry and use RNG to produce Renewable Electricity. We are one of the largest U.S. producers of RNG, having participated in the industry for over 30 years. We established our currently operating portfolio of 11 RNG and two Renewable Electricity and development 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 and ADG, which is produced inside an airtight tank used to breakdown organic matter, such as livestock waste. 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 short-, medium-, and long-term 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 initiatives.
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Recent Developments
RINs Generated but Unsold
Our profitability is highly dependent on the market price of Environmental Attributes, including the market price for RINs. As we self-market a significant portion of our RINs, a decision not to commit to transfer available RINs during a period will impact our revenue and operating profit. We expect the timing between RINs generated and unseparated and RINs available for sale to only impact 2025 which is the year BRRR became effective. We have entered into commitments to transfer all RINs generated and available for sale from 2025 RNG production. We had approximately 190 RINs generated and unseparated at December 31, 2025. We have entered into commitments to transfer approximately 2,500 RINs generated and available for sale from 2026 RNG production. The average D3 RIN index price for the fourth quarter of 2025 and January 2026 through February 28, 2026 was approximately $2.39 and $2.41, respectively. The following table summarizes select historical data related to RINs generated, RINs sold, and RINs generated but unsold. As we self-market a significant portion of our RINs and as the RFS is based on annual compliance, any strategic decision to not monetize available RINs in a quarter could impact the timing of operating revenues recognized during a fiscal year. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The timing of RIN transfers can vary year over year and by period within a year and is contingent on various factors including, but not limited to: (a) the Company’s expectations on RIN index price, (b) operational needs of the Company, (c) obligated parties’ purchase needs, or (d) the type of customer among other matters.
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 First Quarter |
11,240 |
7,889 |
70.2% |
3,351 |
29.8% |
2024 Second Quarter |
14,707 |
10,000 |
68.0% |
4,707 |
32.0% |
2024 Third Quarter |
15,895 |
15,750 |
99.1% |
145 |
0.9% |
2024 Fourth Quarter |
9,822 |
3,000 |
30.5% |
6,822 |
69.5% |
2025 First Quarter |
13,801 |
9,885 |
71.6% |
3,916 |
28.4% |
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% |
Capital Development Summary
The following summarizes our ongoing development growth plans, expected capacity contribution, anticipated commencement of operations, and capital expenditure estimate, 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 |
European Energy Facilities |
N/A |
TBD |
$65,000-$75,000 |
Tulsa RNG Facility |
1,500 |
2027 |
$25,000-$35,000 |
Rumpke RNG Relocation Project |
7,500 |
2028 |
$70,000-$90,000 |
Pico Digestion Capacity Increase
In 2025, we began processing the final tranche of increased feedstock. Upon receipt of the final tranche, we made the final contractual payment to the dairy host. As a result of the increased digestion capacity, we produced approximately 31.8% more MMBtu during 2025 as compared to 2024. During 2025, our digestion inlet feedstock averaged approximately 458 gallons per day, approximately 17% in excess of our contracted minimums of 390 gallons per day. We are currently evaluating additional development expansion opportunities to ensure beneficial processing of all available feedstock volumes.
Second Apex RNG Facility
In 2025, we successfully completed the construction and commissioning of a second RNG processing facility at the Apex landfill. The construction of a second facility under our existing fuel supply agreement was triggered by biogas feedstock volumes exceeding production capabilities, discussions with the landfill host, and the host's waste intake forecasted projections. We continue to expect there will be a period where we have excess availability capacity after the second facility is commissioned while the landfill host increases its waste intake. We continue to collaborate with the landfill host to mitigate impacts from wellfield extraction factors
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which could impact capacity utilization. In connection with the commissioning of the second facility, we produced approximately 7.8% more MMBtu during 2025 as compared to 2024.
Blue Granite RNG Project
In 2025, we received notice from the utility that it will no longer accept RNG into its distribution system, which was in opposition of the letter of intent that was issued when we were awarded the gas rights to the site. As a result, we impaired the capital associated with the interconnection and equipment. We continue to have $1,000 recorded associated with the payment upon award of the gas rights agreement. We continue to review various alternatives related to interconnection opportunities as part of our considerations for offtake options with the understanding those alternatives may differ from initial development project assumptions, including physical and virtual and fixed interconnections. We are also reviewing alternatives for this site around producing energy other than RNG. We have paused capital expenditures related to this site while we consider all alternatives and continue discussions with the landfill host.
Tulsa REG Conversion to RNG
In 2025, we announced the conversion of our Tulsa, Oklahoma Renewable Electric Generation facility to RNG project. The project will offer a variable inlet capacity, ranging from 550 scfm to 2,250 scfm per day, providing average production capacity we target to be approximately 1,500 MMBtu per day and designed to beneficially process all of available inlet gas feedstock from its landfill host. We expect commissioning in 2027 and to continue incurring capital expenditures for long lead items. For the second half of 2025, our wellfield development initiatives have yielded increased feedstock totaling an overage of 1200 scfm per day.
GreenWave Joint Venture
In 2025, 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 (“Greenwave”). 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. In the third quarter of 2025, Greenwave began matching available RNG volumes to dispensing opportunities through Greenwaves's transportation pathways. The joint venture has matched available dispensing capacity with available third party RNG volumes to separate RINs. We recorded income from Greenwave of $1,485 in 2025. 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.
Carbon Dioxide Beneficial Use Opportunity
In 2024, we signed a contract for the delivery of 140 thousand tons per year of biogenic carbon dioxide (“CO2”) from our four Texas facilities. We intend to capture, clean and liquefy CO2 at select Texas facilities, at which point it will be transported to EE North America (“EENA”), a Texas-based e-methanol facility. The delivery term is expected to last at least 15 years with first delivery expected to begin in 2027. In 2025, we have been recognizing an exclusivity fee related to the minimum tons of CO2. The annual price per ton under the contract is adjusted annually by the U.S. consumer price index. The agreement with EENA includes a 50% sharing component of any available tax attributes generated by us under code section 45Q, Carbon dioxide sequestration credit, in the Inflation Reduction Act, as applicable. We have completed the initial site surveys related to location of the CO2 processing equipment, evaluated equipment suppliers, and started engineering design. We believe that we can fulfill the contracted volumes with the development of CO2 at two of our Texas facilities. We continue to match our capital investment in these project opportunities with the development timeline of EENA’s facility.
Montauk Ag Asset 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 121 RECs and 8.7 tons of organic fertilizer alternative.
Regulatory Developments
In 2024, the North Carolina Utilities Commission ("NCUC") approved our Turkey, North Carolina location for a New Renewable Energy Facility (“NREF”) designation and Certificate of Public Convenience and Necessity. In October 2024, our amended NREF application was approved. In 2024, the North Carolina legislature approved a statutory change to its Clean Energy and Energy Efficiency Portfolio Standards ("CEPS") governing the generation of RECs from swine waste that established a REC multiplier for swine waste produced in a Tier 1 county, which includes Sampson County, the location of our Turkey facility. For
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qualifying projects, for each swine REC generated, 2 enhanced RECs will be credited for a total three RECs for a period of 8 years, followed by one enhanced REC for a total two RECs for a period of 6 years and a credit of one REC thereafter. There is a limit of 80 enhanced RECs in a year.
In September 2025, a joint motion was filed with the NCUC by various entities seeking to modify and delay certain aspects of the CEPS, specifically, the portfolio standards relating to swine RECs. 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 with the ability to use solar RECs to fill any compliance shortage. The compliance obligations for those utilities filing the September 2025 joint motion continue to increase through 2029.
Offtake Developments
We have entered into a ten-year agreement to sell all of the renewable electricity generated by the project. Furthermore, we expect the annual REC capacity of the Turkey location to be approximately 120 RECs and have signed a REC agreement with Duke Energy for 47 RECs. 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 the price per swine REC could fall within the range of $200 to $400 per REC.
Feedstock Collection
At full first phase capacity, we anticipate the ability to process feedstock from approximately 400 to 450 hog spaces per day, which equates to approximately 35 tons of annual waste collection. We have entered into long term agreements with over forty separate farming locations to provide access to waste from at least 300 hog spaces to support our expected processing needs under our first phase for the Turkey location. We continue to install collection equipment at these separate farms to access the waste. We currently estimate capital investment of approximately $250 at each farm related to the installed collection equipment. We intend to contract with additional farms to secure feedstock sources for future production processes. In advance of commercial operation date, feedstock collection has begun with collecting the dewatered feedstock from each farm and transporting to the project site for pelletization and storage.
Capital Investment and Progress towards Commercial Operation Date (COD)
We currently expect the first phase capital investment to be approximately $200,000 and have spent approximately $140,000 as of December 31, 2025. Winter storms in the Carolinas early 2026 and project deliveries have caused only nominal project delays. We have begun to commission the facility and expect our production and revenue generation activities to commence in April 2026.
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. Based on our Pico digestion expansion project experience, for 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 which 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 production tax credits could range between $6,000 - $20,000. We give no assurances that our estimates on tax attributes for our Montauk Ag Renewables project will meet these expectations.
Bowerman RNG Project
In 2023, we announced a planned development of a renewable natural gas landfill project in Irvine, CA at the Frank R. Bowerman Landfill to process the large and growing volumes of biogas in excess of the existing capacity of the REG facility. We expect facility commissioning in 2027 and the capital investment to range between $85,000 - $95,000. As part of the agreement to develop the RNG plant, we agreed to work with the landfill host on the landfill's management of its wellfield and flare facility permit requirements and this work remains ongoing. The project is anticipated to have production nameplate capacity of approximately 3,600 MMBtu per day, assuming currently forecasted biogas feedstock volumes projected to be available from the host landfill at the time of commissioning. We continue to incur capital expenditures for this project. During 2025, wellfield initiatives have resulted in
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approximately 4,100 scfm of averaged unprocessed gas which is more than the anticipated inlet of the RNG facility currently under development.
Rumpke RNG Relocation Project
In connection with our gas rights agreement with our landfill host at our Rumpke RNG location, in 2025, we began the process of relocating our existing Rumpke RNG facility. The timing of this project and requirement to relocate the facility coincides with the landfill's filling practices moving into the existing area of our Rumpke RNG facility and is contractually obligated. We expect facility commissioning in 2028 and the capital expenditures to range between $70,000 - $90,000, which is dependent on the timing of capital expenditures and potential other production capabilities requested by the landfill host. We continue to incur capital expenditures for this project. Additionally, the landfill host has requested a modification of our current development design to accommodate a large CNG filling station for their fleet.
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:
Factors Affecting Our Future Operating Results:
Acquisition and Development Pipeline
The timing and extent of our development pipeline affects our operating results due to:
Regulatory, Environmental and Social Trends
Regulatory, environmental and social factors are key drivers that incentivize the development of RNG and Renewable
Electricity projects and influence the economics of these projects. We are subject to the possibility of legislative and regulatory
changes to certain incentives, such as RINs, RECs and GHG initiatives. On July 12, 2023, the EPA issued final rules in the Federal
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Register for the RFS volume requirements for 2023-2025. Final volumes for cellulosic biofuel were set at 838, 1,090 and 1,376 RINs
for the three years 2023, 2024 and 2025, respectively. The final rule also included significant changes to the existing RFS program,
referred to as BRRR, that required the RNG industry to modify how all RINs are generated as of January 1, 2025. We have registered
all of our facilities under the BRRR provisions and have obtained Q-RIN status for RIN generation starting January 1, 2025. Under the
BRRR provisions, the EPA finalized a limitation that biogas from one facility has a single use under the RFS as proposed (i.e.,
biointermediate, RNG or CNG/LNG via biogas closed distribution system). The EPA clarified that this does not preclude non-RFS
uses at same facility.
On June 13, 2025, the EPA released both the Partial Waiver of the 2024 Cellulosic Biofuel Volume Requirement (Final Rule) and RFS Standards for 2026 and 2027, Partial Waiver of 2025 Cellulosic Biofuel Volume Requirement, and Other Changes (Proposed Rule). The final 2024 cellulosic biofuel volume requirement was reduced from 1,090 to 1,010 million D3 RINs. This reduction was based on actual volumes of D3 RINs generated in 2024. In addition, the EPA is making Cellulosic Waiver Credits ("CWCs") available for 2024 as an additional compliance flexibility for obligated parties.
In the EPA’s proposed rule released on June 13, 2025, the cellulosic biofuel volumes for 2025 were proposed to be reduced
from 1,376 to 1,190 RINs and make CWCs available for 2025. The proposed cellulosic biofuel volume requirements for 2026 and
2027 are 1,300 and 1,360 D3 RINs, respectively. These volumes are less than the EPA had previously finalized for 2025 and are
based on their belief that cellulosic RIN generation from biogas-derived CNG/LNG during 2026-2030 will be constrained by the total
usage capacity of CNG/LNG as transportation fuel. These proposed rules are subject to comment periods prior to finalization.
On August 22, 2025, EPA issued decisions on 175 Small Refinery Exemption (SRE) petitions. EPA granted full exemption (100%) to 63 petitions and partial exemptions (50%) to 77 petitions. The SRE decisions exempted corresponding volumes of gasoline and diesel for the 2023 and 2024 compliance years, and increased the number of RINs available for obligated parties to use for compliance with their RFS obligations. Taking into consideration the expected impacts of the SRE decisions on the RFS market, on September 16, 2025, EPA co-proposed a Supplemental Rule that provides additional volumes in 2026 and 2027 RVOs that will represent complete (100%) reallocation or partial (50%) reallocation for SREs granted in full or in part, respectively, for 2023 and 2024, as well as those projected to be granted for 2025.
EPA has indicated an intention to finalize the Supplemental Rule & the RVOs for 2025, 2026 and 2027 by the end of 2025, however, the duration of the US federal government shut down and any residual impacts on EPA staffing after the shutdown concludes may extend finalization of these items into 2026.
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 would 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
carbon intensity reduction targets listed above. The industry may see3 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 November 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.
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
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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.
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.
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Pricing
Our Renewable Natural Gas and Renewable Electricity Generation segments’ revenues are primarily driven by the prices under our off-take agreements and PPAs and the amount of RNG and Renewable Electricity that we produce. We sell the RNG produced from our projects under a variety of short-term and medium-term agreements to counterparties, with contract terms varying from three years to five years. Our contracts with counterparties are typically structured to be based on varying natural gas price indices for the RNG produced. All of the Renewable Electricity produced at our biogas-to-electricity projects is sold under long-term contracts to creditworthy counterparties, typically under a fixed price arrangement with escalators.
The pricing of Environmental Attributes, which accounts for a substantial portion of our revenues, is subject to volatility based on a variety of factors, including regulatory and administrative actions and commodity pricing.
The sale of RINs, which is subject to market price fluctuations, accounts for a substantial portion of our revenues. We manage against the risk of these fluctuations through forward sales of RINs, although currently we only sell RINs in the calendar year they are generated. We have entered into commitments to transfer approximately 2,500 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.
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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:
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Comparison of Years Ended December 31, 2025 and 2024
The following table summarizes the key operating metrics described above, which metrics we use to measure performance.
|
|
For the year ended |
|
|
|
|
|
Change |
|
|||||||
|
|
2025 |
|
|
2024 |
|
|
Change |
|
|
% |
|
||||
(in thousands, unless otherwise indicated) |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Renewable Natural Gas Total Revenues |
|
$ |
155,736 |
|
|
$ |
157,983 |
|
|
$ |
(2,247 |
) |
|
|
(1.4 |
%) |
Renewable Electricity Generation Total Revenues |
|
$ |
17,231 |
|
|
$ |
17,753 |
|
|
$ |
(522 |
) |
|
|
(2.9 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
RNG Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
||||
CY RNG production volumes (MMBtu) |
|
|
5,644 |
|
|
|
5,587 |
|
|
|
57 |
|
|
|
1.0 |
% |
Less: Current period RNG volumes under fixed/floor-price contracts |
|
|
(1,907 |
) |
|
|
(1,546 |
) |
|
|
(361 |
) |
|
|
23.4 |
% |
Plus: Prior period RNG volumes dispensed in current period |
|
|
291 |
|
|
|
358 |
|
|
|
(67 |
) |
|
|
(18.7 |
%) |
Less: Current period RNG production volumes not dispensed |
|
|
(354 |
) |
|
|
(291 |
) |
|
|
(63 |
) |
|
|
21.6 |
% |
Total RNG volumes available for RIN generation (1) |
|
|
3,674 |
|
|
|
4,108 |
|
|
|
(434 |
) |
|
|
(10.6 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
RIN Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Current RIN generation ( x 11.6935) (2) |
|
|
42,970 |
|
|
|
48,177 |
|
|
|
(5,207 |
) |
|
|
(10.8 |
%) |
Less: Counterparty share (RINs) |
|
|
(5,470 |
) |
|
|
(4,824 |
) |
|
|
(646 |
) |
|
|
13.4 |
% |
Plus: Prior period RINs carried into current period |
|
|
6,822 |
|
|
|
108 |
|
|
|
6,714 |
|
|
|
6216.7 |
% |
Less: RINs generated but unseparated |
|
|
(190 |
) |
|
|
— |
|
|
|
(190 |
) |
|
|
0.0 |
% |
Less: CY RINs carried into next CY |
|
|
— |
|
|
|
(6,822 |
) |
|
|
6,822 |
|
|
|
(100.0 |
%) |
Total RINs available for sale (3) |
|
|
44,132 |
|
|
|
36,639 |
|
|
|
7,493 |
|
|
|
20.5 |
% |
Less: RINs sold |
|
|
(44,132 |
) |
|
|
(36,639 |
) |
|
|
(7,493 |
) |
|
|
20.5 |
% |
RIN Inventory |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
0.0 |
% |
RNG Inventory (volumes not dispensed for RINs) (4) |
|
|
354 |
|
|
|
291 |
|
|
|
63 |
|
|
|
21.6 |
% |
Average Realized RIN price |
|
$ |
2.33 |
|
|
$ |
3.28 |
|
|
$ |
(0.95 |
) |
|
|
(29.0 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Renewable Natural Gas Operating Expenses |
|
$ |
90,095 |
|
|
$ |
82,916 |
|
|
$ |
7,179 |
|
|
|
8.7 |
% |
Operating Expenses per MMBtu (actual) |
|
$ |
15.96 |
|
|
$ |
14.84 |
|
|
$ |
1.12 |
|
|
|
7.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
REG Operating Expenses |
|
$ |
16,670 |
|
|
$ |
14,734 |
|
|
$ |
1,936 |
|
|
|
13.1 |
% |
$/MWh (actual) |
|
$ |
94.18 |
|
|
$ |
79.22 |
|
|
$ |
14.96 |
|
|
|
18.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Renewable Electricity Generation Volumes Produced (MWh) |
|
|
177 |
|
|
|
186 |
|
|
|
(9 |
) |
|
|
(4.8 |
%) |
Average Realized Price $/MWh (actual) |
|
$ |
97.35 |
|
|
$ |
95.45 |
|
|
$ |
1.90 |
|
|
|
2.0 |
% |
Results of Operations
Comparison of Years Ended December 31, 2025 and 2024
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The following table summarizes our revenues, expenses and net income for the periods set forth below:
|
|
For the year ended |
|
|
|
|
|
Change |
|
|||||||
|
|
2025 |
|
|
2024 |
|
|
Change |
|
|
% |
|
||||
Total operating revenues |
|
$ |
176,382 |
|
|
$ |
175,736 |
|
|
$ |
646 |
|
|
|
0.4 |
% |
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating and maintenance expenses |
|
|
77,646 |
|
|
|
66,663 |
|
|
|
10,983 |
|
|
|
16.5 |
% |
General and administrative expenses |
|
|
31,736 |
|
|
|
36,286 |
|
|
|
(4,550 |
) |
|
|
(12.5 |
)% |
Royalties, transportation, gathering and production fuel |
|
|
32,945 |
|
|
|
31,502 |
|
|
|
1,443 |
|
|
|
4.6 |
% |
Depreciation, depletion and amortization |
|
|
29,972 |
|
|
|
23,515 |
|
|
|
6,457 |
|
|
|
27.5 |
% |
Impairment loss |
|
|
3,231 |
|
|
|
1,586 |
|
|
|
1,645 |
|
|
|
103.7 |
% |
Transaction costs |
|
|
- |
|
|
|
61 |
|
|
|
(61 |
) |
|
|
(100.0 |
)% |
Total operating expenses |
|
|
175,530 |
|
|
|
159,613 |
|
|
|
15,917 |
|
|
|
10.0 |
% |
Operating income |
|
$ |
852 |
|
|
$ |
16,123 |
|
|
$ |
(15,271 |
) |
|
|
(94.7 |
)% |
Other expenses: |
|
|
3,339 |
|
|
|
3,946 |
|
|
|
(607 |
) |
|
|
(15.4 |
)% |
Net (loss) income before income taxes: |
|
|
(2,487 |
) |
|
|
12,177 |
|
|
|
(14,664 |
) |
|
|
(120.4 |
)% |
Income tax (benefit) expense |
|
|
(4,235 |
) |
|
|
2,443 |
|
|
|
(6,678 |
) |
|
|
(273.4 |
)% |
Net income |
|
$ |
1,748 |
|
|
$ |
9,734 |
|
|
$ |
(7,986 |
) |
|
|
(82.0 |
)% |
Revenues for the Years Ended December 31, 2025 and 2024
Total revenues in 2025 were $176,382, an increase of $646 (0.4%) compared to $175,736 in 2024. The increase is driven by the number of RINs we self-marketed during 2025 due to a strategic decision to not self-market 6,822 RINs in the fourth quarter of 2024. Offsetting the increase, is a decrease in the 2025 average realized RIN price of $2.33, which decreased approximately 29.0% compared to $3.28 in 2024, and an increase in our current period RNG volumes sold under fixed/floor-price contracts. Our margin sharing revenues increased approximately $1,016 in 2025 as compared to 2024. The natural gas index price increased approximately 51.1% from $2.27 in 2024 to $3.43 in 2025.
Renewable Natural Gas Revenues
We produced 5,644 MMBtu of RNG during 2025, an increase of 57 MMBtu (1.0%) compared to 5,587 MMBtu in 2024. We increased our production when considering our 2024 fourth quarter sale of our Southern facility which produced 85 MMBtu in 2024. Our Rumpke facility produced 218 MMBtu more in 2025 compared to 2024 as a result of increased volumes of feedstock gas. Our McCarty facility produced 76 MMBtu less in 2025 compared to 2024. The decrease is related to the landfill host wellfield bifurcation and changes to the wellfield collection system.
Revenues from the Renewable Natural Gas segment in 2025 were $155,736, a decrease of $2,247 (1.4%) compared to $157,983 in 2024. Average commodity pricing for natural gas for 2025 was 51.1% higher than the prior year. During 2025, we self-marketed 44,132 RINs, representing an 7,493 increase (20.5%) compared to 36,639 in 2024. The increase was primarily related to the decision to not self-market a significant amount of RINs in inventory in the fourth quarter of 2024. Average pricing realized on RIN sales during 2025 was $2.33 as compared to $3.28 in 2024, a decrease of 29.0%. This compares to the average D3 RIN index price for 2025 of $2.34 being approximately 25.0% lower than the average D3 RIN index price in 2024 of $3.12. At December 31, 2025, we had approximately 354 MMBtu available for RIN generation, 190 RINs generated and unseparated, and no RINs generated and unsold. At December 31, 2024,we had approximately 291 MMBtus available for RIN generation and had approximately 6,822 RINs generated and unsold. We have entered into commitments and transferred all of our RINs related to our 2025 RNG production.
Renewable Electricity Generation Revenues
We produced 177 MWh in Renewable Electricity in 2025, a decrease of approximately 9 MWh (4.8%) compared to 186 MWh in 2024. Our Security facility produced 6 MWh less in 2025 compared to 2024 as a result of us ceasing operations in connection with the 2024 sale of the gas rights back to the landfill host. Our Bowerman facility produced approximately 2 fewer MWh in 2025 compared to 2024 primarily related to the planned preventative engine maintenance that was completed in 2025.
Revenues from Renewable Electricity facilities in 2025 were $17,231, a decrease of $522 (2.9%) compared to $17,753 in 2024. The decrease is primarily driven by the decrease in our Security facility production volumes.
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General and Administrative Revenues
We recorded approximately $3,415 in Environmental Attribute revenues from RINs distributed from GreenWave. We sold approximately 1,483 RINs distributed from GreenWave, which are not included within our operating metrics table. As a result of the services performed by GreenWave, we recorded income from GreenWave of $1,485.
Expenses for the Years Ended December 31, 2025 and 2024
General and Administrative Expenses
Total general and administrative expenses were $31,736 in 2025, a decrease of $4,550 (12.5%) compared to $36,286 in 2024. Employee related costs, including stock-based compensation costs were $18,356 in 2025, a decrease of $4,743 (20.5%) compared to $23,099 in 2024. The decrease was primarily related to the accelerated vesting of certain restricted share awards as a result of the termination of an employee in 2024. Our corporate insurance fees decreased approximately $843 (15.4%) in 2025 compared to 2024.
Renewable Natural Gas Expenses
Operating and maintenance expenses for our RNG facilities in 2025 were $59,108, an increase of $5,721 (10.7%) compared to $53,387 in 2024. Our Apex facility operating and maintenance expenses increased approximately $2,258 primarily driven by increased utility expense, the timing of maintenance related to gas processing equipment, increased media change outs and disposal costs, as well as a wellfield operational enhancement program. Our Atascocita facility operating and maintenance expenses increased approximately $1,450 primarily driven by gas processing equipment maintenance, a wellfield operational enhancement program, media change outs, and utility expense. Our Rumpke facility operating and maintenance expenses increased approximately $1,348 as a result of a wellfield operational enhancement program and increased utility expense. Our Raeger facility operating and maintenance expenses increased approximately $917 as a result of a wellfield operational enhancement program and increased media change outs and disposal costs.
We recorded approximately $3,428 in environmental attribute expense 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 2024.
Royalties, transportation, gathering and production fuel expenses for our RNG facilities in 2025 were $30,986, an increase of $1,457 (4.9%) compared to $29,529 in 2024. Our Pico facility earnout expense increased approximately 22.6% during 2025 compared to 2024. We settled the Pico earnout obligation in 2025 resulting in a payment of $4,176. Royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues to 19.9% for 2025 from 18.7% in 2024.
Renewable Electricity Expenses
Operating and maintenance expenses for our Renewable Electricity facilities in 2025 were $14,711, an increase of $1,951 (15.3%) compared to $12,760 in 2024. The primary driver of the increase was operating and maintenance expenses at our Montauk Ag Renewables project which increased approximately $1,708 as a result of non-capitalizable costs.
Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for 2025 were $1,959, a decrease of $14 (0.7%) compared to $1,973 in 2024, and as a percentage of Renewable Electricity Generation segment revenues increased from 11.1% for 2024 to 11.4% for 2025.
Royalty Payments
Royalties, transportation, gathering, and production fuel expenses in 2025 were $32,945, an increase of $1,443 (4.6%) compared to $31,502 in 2024. We make royalty payments to our fuel supply site partners on the commodities we produce and the associated Environmental Attributes. These royalty payments are typically structured as a percentage of revenue subject to a cap, with fixed minimum payments when Environmental Attribute prices fall below a defined threshold. To the extent commodity and Environmental Attributes’ prices fluctuate, our royalty payments may fluctuate upon renewal or extension of a fuel supply agreement or in connection with new projects. Our fuel supply agreements are typically structured as 20-year contracts, providing long-term visibility into the margin impact of future royalty payments.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization in 2025 was $29,972, an increase of $6,457 (27.5%) compared to $23,515 in 2024. The increase was primarily driven by the timing of wellfield and maintenance capital investments and our Second Apex RNG Facility project being placed into service.
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Impairment loss
We calculated and recorded impairment losses of $3,231 for 2025, an increase of $1,645 (103.7%) compared to $1,586 for 2024. The impairment losses in 2025 primarily relate to an RNG development project for which the local utility is no longer accepting RNG into its distribution system. The impairment losses in 2024 primarily relate to the remaining book value of assets at the Security facility, various RNG equipment that was deemed obsolete for current operations, and REG assets that were impacted under initial startup testing for one of our REG construction work-in-progress sites.
Other Expenses
Other expenses in 2025 were $3,339, a decrease of $607 (15.4%) compared to $3,946 in 2024. The primary driver of the decrease is decreased interest expense of $461. In 2025, we recorded $1,485 in income related to our joint venture investment in GreenWave. In 2024, we recorded proceeds of $1,000 from the sale of gas rights ahead of the fuel supply agreement expiration of our Security facility.
Income Tax (Benefit) Expense
As of December 31, 2025 and 2024, we utilized all of our non-limited NOLs. A wholly-owned subsidiary continues to carry from 2024 to 2025 approximately $12,986 of federal net operating losses that are not expected to be realizable due to loss limitation rules.
As of December 31, 2025 and 2024, we had approximately $17,339 and $12,274, respectively, federal tax credit carryforwards that expire 20 years from the date incurred, which will begin to expire in tax year 2026. As of December 2025, we have no remaining state NOL’s. Additionally, we have created a federal net operating loss of $407 in 2025.
For the year ended December 31, 2025, we had an income tax benefit of $4,235 and for the year ended December 31 2024, we had income tax expense of $2,443. The 2025 effective tax rate was 170.3% and the 2024 effective tax rate was 20.1%.
Operating Profit (Loss) for the Years Ended December 31, 2025 and 2024
Operating profit in 2025 was $852, a decrease of $15,271 (94.7%) compared to $16,123 in 2024. RNG operating profit for 2025 was $38,173, a decrease of $17,859 (31.9%) compared to $56,032 in 2024. Renewable Electricity Generation operating loss for 2025 was $4,870, an increase of $2,047 (72.5%) compared to $2,823 in 2024.
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 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.
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The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net income:
|
|
For the year ended |
|
|||||
|
|
2025 |
|
|
2024 |
|
||
Net income |
|
$ |
1,748 |
|
|
$ |
9,734 |
|
Depreciation, depletion and amortization |
|
|
29,972 |
|
|
|
23,515 |
|
Interest expense |
|
|
4,816 |
|
|
|
5,277 |
|
Income tax (benefit) expense |
|
|
(4,235 |
) |
|
|
2,443 |
|
Consolidated EBITDA |
|
|
32,301 |
|
|
|
40,969 |
|
|
|
|
|
|
|
|
||
Impairment loss (1) |
|
|
3,231 |
|
|
|
1,586 |
|
Net loss on sale of assets |
|
|
36 |
|
|
|
— |
|
Transaction costs |
|
|
— |
|
|
|
61 |
|
Adjusted EBITDA |
|
$ |
35,568 |
|
|
$ |
42,616 |
|
Liquidity and Capital Resources
Sources of Liquidity
At December 31, 2025 and 2024, our cash and cash equivalents, net of restricted cash, was $23,752 and $45,621, respectively. We believe our credit refinancing with will afford us increased flexibility with securing project based additional financing for our in progress development projects. 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, operational, and political risks that could adversely affect our cash flows and liquidity.
At December 31, 2025, we had debt before debt issuance costs of $129,000, compared to debt before debt issuance costs of $56,000 at December 31, 2024.
Our debt before issuance costs (in thousands) is as follows:
|
|
December 31, 2025 |
|
|
December 31, 2024 |
|
||
Term loan |
|
$ |
44,000 |
|
|
|
56,000 |
|
Revolving credit facility |
|
|
85,000 |
|
|
|
— |
|
Debt before debt issuance costs |
|
$ |
129,000 |
|
|
$ |
56,000 |
|
Amended Credit Agreement
On December 31, 2025, we entered into the Sixth Amendment to the Second Amended and Restated Revolving Credit and Term Loan Agreement (the “Amended Credit Agreement”), with Comerica Bank (“Comerica”) and certain other financial institutions. The Amended Credit Agreement, which is secured by substantially all of our assets and assets of certain of our subsidiaries, provides for a five-year $80,000 term loan and a five-year $120,000 revolving credit facility.
The Amended Credit Agreement contains customary covenants applicable to us and certain of our subsidiaries, including financial covenants. The Amended Credit Agreement is subject to customary events of default, and contemplates that we would be in default if, for any fiscal quarter (x) the average monthly D3 RIN price (as determined in accordance with the Amended Credit Agreement) is less than $0.80 per RIN and (y) the consolidated EBITDA for such quarter is less than $6,000. Consolidated EBITDA is defined under the Amended Credit Agreement as net income plus (a) income tax expense, (b) interest expense, (c) depreciation, depletion, and amortization expense, (d) non-cash unrealized derivative expense and (e) any other extraordinary, unusual, or non-recurring adjustments to certain components of net income, as agreed upon by Comerica and in certain circumstances.
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Under the Amended Credit Agreement, we are required to maintain the following:
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 term loan amortizes in quarterly installments of $3,000 quarterly through 2026 with a final payment of $32,000, on December 21, 2026. Interest rates were 6.44% and 6.01% at December 31, 2025 and 2024, respectively. The revolving and term loans under the Amended Credit Agreement bore interest at the BSBY Margin or Base Rate Margin based on our Total Leverage Ratio (in each case, as those terms are defined in the Amended Credit Agreement) as of December 31, 2025. The BSBY ceased publication on November 15, 2024, and the current debt agreement was amended to utilize the Secured Overnight Financing Rate Index ("SOFR"), plus applicable margin.
As of December 31, 2025, we were in compliance with all financial covenants related to the Amended Credit Agreement.
New Senior Credit Facility
On March 9, 2026, we entered into a new five year senior credit facility ("New Senior Credit Facility") with CCH1 MEH Lender LLC (a wholly owned subsidiary of Hannon Armstong Capital LLC) ("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.
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, which became applicable upon entry into the new facility on March 9, 2026:
As of March 9, 2026, $155,000 was outstanding under the New Senior Credit Facility.
For additional information regarding the Amended Credit Agreement and the New Senior Credit Facility, see Note 13 to our audited 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. The increase in 2026 non-development capital expenditures relate to original equipment manufacturer required lifecycle expenditures on our engines at our Bowerman facility. We expect this process to continue through 2027. Additionally, we currently estimate that our existing 2026 development capital expenditures will range between $100,000 and $150,000. The majority of our 2026 development capital expenditures relate to our ongoing development of Montauk Ag Renewables, Bowerman RNG project, Rumpke RNG Relocation Project, and our EENA CO2 project. Our focus is on achieving COD for the Montauk Ag Renewables project which we expect to be funded by the undrawn $200,000 Senior Secured Credit Facility with HASI. We believe 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
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equivalents, cash generated from operations, and credit availability under our 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 years ended December 31, 2025 and 2024:
|
|
For the year ended |
|
|||||
|
|
2025 |
|
|
2024 |
|
||
Net cash provided by (used in): |
|
|
|
|
|
|
||
Operating activities |
|
$ |
30,334 |
|
|
$ |
43,795 |
|
Investing activities |
|
|
(120,487 |
) |
|
|
(62,191 |
) |
Financing activities |
|
|
68,339 |
|
|
|
(9,842 |
) |
Net decrease in cash and cash equivalents |
|
|
(21,814 |
) |
|
|
(28,238 |
) |
Restricted cash, end of the period |
|
|
438 |
|
|
|
383 |
|
Cash and cash equivalents, end of period |
|
|
24,190 |
|
|
|
46,004 |
|
For the year ended December 31, 2025, we generated $30,334 of cash from operating activities, a 30.7% decrease compared to $43,795 for the year ended December 31, 2024. For the year ended December 31, 2025, income and adjustments to income from operating activities provided $37,348 compared to $44,961 in 2024. Working capital and other assets and liabilities used $7,014 in 2025 compared to $1,166 in 2024.
Our net cash flows used in investing activities has historically focused on project development and facility maintenance. For 2025, our capital expenditures were $116,542, of which $80,978, $8,726, and $7,735, were related to the ongoing development of the Montauk Ag Renewables, Rumpke RNG relocation project, and second Apex RNG facility, respectively. For 2024, our capital expenditures were $62,323, of which $27,847, $12,643, and $8,759, were related to the ongoing development of the Montauk Ag Renewables, second Apex RNG facility, and Bowerman RNG project, respectively.
Our net cash flows in financing activities provided $68,339 for 2025 increased by $78,181 compared to cash used in financing activities of $9,842 in 2024. We had $105,000 in increased borrowings on our revolver in 2025 as compared to none in 2024. Offsetting this amount of cash were increased repayments of $24,000 on our debt in 2025 as compared to 2024.
Related-Party Transactions
On January 26, 2021, we 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, we advanced a cash loan of $5,000 to MNK for MNK to pay its dividend's tax liability arising from the Reorganization Transactions under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended. As a result of several amendments, the current principal balance of the loan is $10,690, the due date is December 31, 2033 and the security interest is 976,623 shares of our common stock held by MNK (as amended the “Fifth Amended Promissory Note”).
In December 2021, Rivetprops 47 Proprietary Limited (“RP47”) entered into an agreement to loan MNK up to 10,000 South African Rand (the “RP47 Loan”). The principal balance and accrued interest was 11,713 Rand or approximately $650 US Dollars. 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 Transaction Implementation Agreement ("TIA") between us and MNK, we became obligated to repay the RP47 Loan on MNK’s behalf. 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 Promissory Note. MNK’s only obligation is its loan to us and thus, we became the primary beneficiary of MNK on December 31 2024. In accordance with ASC 810, we consolidated MNK on December 31, 2024.
We consolidated MNK’s current assets ($85), current liabilities ($632) and long-term liabilities ($16). The Fifth Amended Promissory Note became an intercompany loan and was eliminated in consolidation. MNK’s investment of $10,178 in the Company is 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. On February 2, 2025, our Board of Directors approved the
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repayment of the RP47 Loan under the TIA and on March 5, 2025 we repaid the RP47 loan as required under the TIA. The amount repaid is included in the principal balance of the Fifth Amended Promissory Note described above.
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 and operating leases 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 to our audited consolidated financial statements for further information regarding the asset retirement obligations.
We have contractual obligations under our debt agreement, including interested payments and principal repayments. See Note 13 to our audited consolidated financial statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. During 2025, we had $2,571 of off-balance sheet arrangements of outstanding letters of credit. These letters of credit reduce the borrowing capacity of our revolving credit facility under our Amended Credit Agreement. Certain of our contracts require these letters of credit to be issued to provide additional performance assurances. There have been no usage against these outstanding letters of credit. During 2024, we did not have off-balance sheet arrangements other than outstanding letters of credit of approximately $2,185.
We have contractual obligations involving operating leases. See Note 19 to our audited consolidated financial statements for further information related to the lease obligations.
We have other contractual obligations associated with our fuel supply agreements. The expiration of these agreements range between 2-18 years. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,746.
Internal Control Over Financial Reporting
There were no changes during 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Critical Accounting Policies and Estimates
Our consolidated financial statements are prepared in conformity with GAAP and require our management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, costs and expenses and related disclosures. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and such estimates may change if the underlying conditions or assumptions change.
Revenue Recognition
Our revenues are comprised of renewable energy and the related Environmental Attribute sales provided under a variety of short-term and medium-term agreements with our customers. All revenue is recognized when we satisfy our performance obligation(s) under the contract (either implicit or explicit) by transferring the promised product to the customer either when (or as) the customer obtains control of the product. A performance obligation is a promise in a contract to transfer a distinct product or service to a 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 our contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of our influence as the variable consideration is dictated by the market. Therefore, the variable consideration associated with the long-term contracts is considered fully constrained. Refer to Item 7A for an estimate of the impact of decreases in the wholesale price of gas on our operating profit.
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RINs
We generate D3 RINs through our production and sale of RNG used for transportation purposes as prescribed under the RFS program. Our operating costs are associated with the production of RNG. The RINs are government incentives that are generated through our renewable operating projects and not a result of physical attributes of our RNG production. The RINs that we generate are able to be separated and sold as credits independently from the energy produced. Therefore, no cost is allocated to the RIN when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred. We enter into forward commitments to transfer RINs. These forward commitments are based on D3 RIN index prices at the time of the commitment. Realized prices for RINs monetized in a year may not correspond directly to index prices due to the forward selling of commitments. Refer to Item 7A for an estimate of the impact of decreases in the realized price per RIN on our operating profit.
RECs
We generate RECs through our production and conversion of landfill methane into Renewable Electricity in various states, including 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 NOLs, 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. Given our current level of pre-tax earnings and forecasted future pre-tax earnings, we expect to generate income before taxes in the United States in future periods at a level that would fully utilize our U.S. federal NOL carryforwards and the majority of its state NOL carryforwards prior to their expiration. See Note 14 to our audited consolidated financial statements for additional information.
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.
Indefinite-lived intangible assets are not amortized and include emission allowances and land use rights. Emission allowances consist of credits that need to be applied to nitrogen oxide (“NOx”) emissions from internal combustion engines. These engines emit levels of NOx for which environmental permits are required in certain regions in the United States. Except for permanent allocations of NOx credits, allowances available for use each year are capped at a level necessary for ozone attainment per the National Ambient Air Quality Standards. We assess the impairment of intangible assets that have indefinite lives at least on an annual basis or whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable.
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If finite-lived or indefinite-lived intangible assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. The fair value is determined based on the present value of expected future cash flows. We use our best estimates in making these evaluations, however, actual future pricing, operating costs and discount rates could vary from the assumptions used in our estimates and the impact of such variations could be material.
Our assessment of the recoverability of finite-lived and indefinite-lived intangible assets is determined by performing monitoring assessment of the future cash flows associated with the underlying gas rights agreements. The cash flows estimates are performed at the operating unit level and based on the average remaining length of the gas rights agreements. Based on our analysis, we concluded the cashflows generated to be well in excess of the carrying amounts. Changes in market conditions related to the various price indexes used in estimating these cash flows could adversely effect these estimates.
Finite-Lived Asset Impairment
In accordance with FASB ASC Topic 360, Property, Plant and Equipment and intangible assets with finite useful lives are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by comparing the carrying amount of an asset or asset group to future undiscounted cash flows expected to be generated by the asset or asset group. Such estimates are based on certain assumptions, which are subject to uncertainty and may materially differ from actual results, including considering project specific assumptions for long-term credit prices, escalated future project operating costs and expected site operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Fair value is generally determined by considering (i) internally developed discounted cash flows for the asset group, (ii) third-party valuations, and/or (iii) information available regarding the current market value for such assets. We use our best estimates in making these evaluations and consider various factors, including future pricing and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates and the impact of such variations could be material. Based on our annual cash flow assessment conduction for monitoring potential indicators of impairment, we concluded the cashflows to be generated are significantly in excess of their carrying value of our operating sites primarily due to the lengths of the underlying gas rights agreements.
As to the remaining long lived asset groups, the Company further concluded, based on our annual cashflow assessment conducted for monitoring potential indicators of impairment, that the cashflows to be generated are significantly in excess of their carrying values of our operating sites primarily due to the lengths of the underlying gas rights agreements and the Company did not record any other impairments related to its cash flows assessment. Separate from our cash flows assessment, we identified discrete events and recorded impairment of $3,231 and $1,586 for 2025 and 2024, respectively. See Note 3 to our audited 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. The JOBS Act allows emerging growth companies to delay the adoption of new or revised accounting standards until such time as those standards apply to private companies. We intend to utilize these transition periods, which may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the transition periods afforded under the JOBS Act.
Recent Accounting Pronouncements
For a description of our recently adopted accounting pronouncements and recently issued accounting standards not yet adopted, see Note 2 to our consolidated financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are exposed to market risks related to Environmental Attribute pricing, commodity pricing, changes in interest rates and credit risk with our contract counterparties. We currently have no foreign exchange risk and do not hold any derivatives or other financial instruments purely for trading or speculative purposes.
We employ various strategies to economically hedge these market risks, including derivative transactions relating to commodity pricing and interest rates. Any realized or unrealized gains or losses from our derivative transactions are reported within corporate revenue in our consolidated financial statements. For information about our realized or unrealized gains or losses with respect to our derivative transactions and the fair value of such financial instruments, see Note 10 and Note 11 to our audited consolidated financial statements.
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RIN and Environmental Attribute Pricing Risk
We attempt to negotiate the best prices for our Environmental Attributes and to competitively price our products to reflect the fluctuations in market prices. Reductions in the market prices of Environmental Attributes may have a material adverse effect on our revenues and profits as they directly reduce our revenues. To manage this market risk, we use a mix of short-, medium-, and long-term sales contracts and sell a portion of our Environmental Attributes at fixed-prices, through floor-price margin share agreements and pursuant to forward contracts with terms between one and two years. We also sell our Environmental Attributes bundled with RNG in contracts between two to five years.
We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to RIN prices. Our analysis, which may differ from actual results, was based on a 2026 estimated D3 RIN Index price of approximately $2.40 and our actual 2025 RINs sold. The estimated annual impact of a hypothetical 10% decrease in the average realized price per RIN would have a negative effect on our operating profit of approximately $8.5 million.
RNG and Renewable Electricity Pricing Risk
The price of RNG and Renewable Electricity changes in relation to the market prices of wholesale gas and wholesale electricity, respectively. Pricing for wholesale gas and wholesale electricity is volatile and we expect this volatility to continue in the future. Further, volatility of wholesale gas and electricity prices also creates volatility in the prices of Environmental Attributes.
We use a mix of short-, medium-, and long-term sales contracts and commodity hedging derivatives to manage our exposure to our pricing risk. We did not enter into a derivative contract to hedge a portion of our RNG production for 2025 or 2024.
We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to the market price of wholesale gas. Our analysis, which may differ from actual results, was based on a 2025 estimated NYMEX average Index Price of approximately $4.687/MMBtu and our actual 2025 gas production sold pursuant to contracts that do not provide for a fixed or floor price. The estimated annual impact of a hypothetical 10% decrease in the market price of wholesale gas would have a negative effect on our operating profit of approximately $1.4 million.
Interest Rate Risk
We previously utilized our Amended Credit Facility, which bore interest at a variable rate based on the Secured Overnight Financing Rate (“SOFR”) plus an applicable margin determined by our Total Leverage Ratio, as defined in the Amended Credit Agreement. To manage exposure to variability in cash flows associated with changes in interest rates, we entered into interest rate swap agreements that effectively converted variable-rate borrowings under the Amended Credit Facility to fixed-rate obligations.
As of December 31, 2025, we had $129.0 million outstanding under the Amended Credit Facility. The weighted average interest rate on our variable debt balances during the year ended December 31, 2025 was approximately 6.44%.
We performed a sensitivity analysis to estimate our exposure to market risk with respect to changes in interest rates. Based on our analysis, a hypothetical 10% increase in our effective borrowing rate as of December 31, 2025 would not have had a material impact on our annual interest expense or consolidated financial statements, primarily due to the effect of our interest rate swap agreements. This analysis is based on certain assumptions and does not represent a forecast of future results.
On March 9, 2026, we repaid in full all outstanding borrowings under the Amended Credit Facility in connection with entering into the Senior Credit Facility. As a result, we no longer have exposure to variable interest rate risk associated with the Amended Credit Facility. The Senior Credit Facility bears interest at a fixed rate, we do not expect material exposure to changes in market interest rates with respect to borrowings under this facility. Accordingly, our exposure to interest rate risk following the refinancing is expected to be significantly reduced compared to our prior variable-rate borrowings.
Credit Risk
We have certain financial and derivative instruments that subject us to credit risk. These consist of our commodity hedging derivatives and interest rate swaps contracts. We are exposed to credit losses in the event of non-performance by the counterparties to our financial and derivative instruments.
We are also subject to credit risk due to concentration of our RNG receivables with a limited number of significant customers. This concentration increases our exposure to credit risk on our receivables, since the financial insolvency of these customers could have a significant impact on our results of operations.
-55-
Table of Contents
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
|
Page |
Montauk Renewables, Inc. |
|
Audited Consolidated Financial Statements |
|
Report of Independent Registered Public Accounting Firm (PCAOB ID Number |
57 |
Consolidated Balance Sheets as of December 31, 2025 and 2024 |
58 |
Consolidated Statements of Operations for the years ended December 31, 2025, 2024 and 2023 |
59 |
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2025, 2024 and 2023 |
60 |
Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023 |
61 |
Notes to Consolidated Financial Statements |
63 |
-56-
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Montauk Renewables, Inc.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Montauk Renewables, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis for opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/
We have served as the Company’s auditor since 2007.
March 11, 2026
-57-
Table of Contents
MONTAUK RENEWABLES, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data) |
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as of December 31, |
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|||||
ASSETS |
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2025 |
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2024 |
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||
Current assets: |
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|
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Cash and cash equivalents |
|
$ |
|
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$ |
|
||
Accounts and other receivables |
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||
Current restricted cash |
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Income tax receivable |
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Current portion of derivative instruments |
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Prepaid insurance and other current assets |
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Total current assets |
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$ |
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$ |
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||
Non-current restricted cash |
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$ |
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$ |
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||
Property, plant and equipment, net |
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||
Goodwill and intangible assets, net |
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Deferred tax assets |
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Non-current portion of derivative instruments |
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Operating lease right-of-use assets |
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Finance lease right-of-use assets |
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||
Equity method investment |
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|||
Other assets |
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||
Total assets |
|
$ |
|
|
$ |
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||
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|
|
|
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|
||
LIABILITIES AND STOCKHOLDERS' EQUITY |
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||
Current liabilities: |
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||
Accounts payable |
|
$ |
|
|
$ |
|
||
Accrued liabilities |
|
|
|
|
|
|
||
Related party payable |
|
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|||
Current portion of operating lease liability |
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||
Current portion of finance lease liability |
|
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||
Current portion of long-term debt |
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||
Total current liabilities |
|
$ |
|
|
$ |
|
||
Long-term debt, less current portion |
|
$ |
|
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$ |
|
||
Non-current portion of operating lease liability |
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||
Non-current portion of finance lease liability |
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Asset retirement obligations |
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||
Other liabilities |
|
|
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||
|
|
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||
Total liabilities |
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$ |
|
|
$ |
|
||
|
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||
(Note 20) |
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||
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||
STOCKHOLDERS’ EQUITY |
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||
|
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||
Common stock, $ |
|
$ |
|
|
$ |
|
||
Treasury stock, at cost, |
|
|
( |
) |
|
|
( |
) |
Additional paid-in capital |
|
|
|
|
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|
||
Retained earnings |
|
|
|
|
|
|
||
Total stockholders' equity |
|
$ |
|
|
$ |
|
||
Total liabilities and stockholders' equity |
|
$ |
|
|
$ |
|
||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
-58-
Table of Contents
MONTAUK RENEWABLES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
For The Year Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Total operating revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating expenses: |
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|
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|||
Operating and maintenance expenses |
|
|
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|
|||
General and administrative expenses |
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|
|||
Royalties, transportation, gathering and production fuel |
|
|
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|
|||
Depreciation, depletion and amortization |
|
|
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|
|||
Impairment loss |
|
|
|
|
|
|
|
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|
|||
Transaction costs |
|
|
|
|
|
|
|
|
|
|||
Total operating expenses |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Operating income |
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Other expenses (income): |
|
|
|
|
|
|
|
|
|
|||
Interest expense |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Income from equity investment |
|
|
( |
) |
|
|
|
|
||||
Other expense (income) |
|
|
|
|
|
( |
) |
|
|
( |
) |
|
Total other expenses |
|
$ |
|
|
$ |
|
|
$ |
|
|||
(Loss) income before income taxes |
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
|
|
|
|
|
|
|
|
|
|
|||
Income tax (benefit) expense |
|
|
( |
) |
|
|
|
|
|
|
||
Net income |
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Income per share: |
|
|
|
|
|
|
|
|
|
|||
Basic |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Diluted |
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Weighted-average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|||
Basic |
|
|
|
|
|
|
|
|
|
|||
Diluted |
|
|
|
|
|
|
|
|
|
|||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
-59-
Table of Contents
MONTAUK RENEWABLES, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
|
|
Common stock |
|
|
Treasury stock |
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
|
Shares |
|
|
Amount |
|
|
Shares |
|
|
Amount |
|
|
Additional paid-in capital |
|
|
Retained earnings |
|
|
Total equity |
|
|||||||
Balance at December 31, 2022 |
|
|
|
|
$ |
|
|
|
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
|
$ |
|
||||||
Vesting of stock awards |
|
|
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|||
Treasury stock |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
( |
) |
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
Net income |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
Stock-based compensation |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
||
Balance at December 31, 2023 |
|
|
|
|
$ |
|
|
|
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
|
$ |
|
||||||
Vesting of stock awards |
|
|
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|||
Treasury stock |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
( |
) |
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
Consolidation of VIE |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
Net income |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
Stock-based compensation |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
||
Balance at December 31, 2024 |
|
|
|
|
$ |
|
|
|
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
|
$ |
|
||||||
Vesting of stock awards |
|
|
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|||
Treasury stock |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
( |
) |
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
Consolidation of VIE |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
Net income |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
Stock-based compensation |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
||
Balance at December 31, 2025 |
|
|
|
|
$ |
|
|
|
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
|
$ |
|
||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
-60-
Table of Contents
MONTAUK RENEWABLES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands): |
|
For The Year Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|||
Net income |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Adjustments to reconcile net income to net cash provided by operating |
|
|
|
|
|
|
|
|
|
|||
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
|
|||
(Benefit) provision for deferred income taxes |
|
|
( |
) |
|
|
|
|
|
|
||
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|||
Derivative mark-to-market adjustments and settlements |
|
|
|
|
|
|
|
|
|
|||
Net loss on disposal of assets |
|
|
|
|
|
|
|
|
||||
(Decrease) increase in earn-out liability |
|
|
|
|
|
( |
) |
|
|
|
||
Accretion of asset retirement obligations |
|
|
|
|
|
|
|
|
|
|||
Liabilities associated with properties sold |
|
|
|
|
( |
) |
|
|
|
|||
Amortization of debt issuance costs |
|
|
|
|
|
|
|
|
|
|||
Impairment loss |
|
|
|
|
|
|
|
|
|
|||
Non cash expense - RINs sold from equity method investment |
|
|
|
|
|
|
|
|||||
Income from equity method investment |
|
|
( |
) |
|
|
|
|
||||
Cash provided (used) by changes in assets and labilities: |
|
|
|
|
|
|
|
|
|
|||
Accounts receivable |
|
|
( |
) |
|
|
|
|
|
( |
) |
|
Royalty offset long term receivable |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Income tax receivable |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Critical spare inventory |
|
|
( |
) |
|
|
|
|
|
( |
) |
|
Accounts payable and Accrued liabilities |
|
|
|
|
|
( |
) |
|
|
|
||
Other |
|
|
|
|
|
( |
) |
|
|
( |
) |
|
Net cash provided by operating activities |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|||
Capital expenditures |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
Asset acquisition |
|
|
|
|
|
( |
) |
|
|
|
||
Capital contributions to equity method investments |
|
|
( |
) |
|
|
|
|
|
|
||
Cash collateral deposits |
|
|
|
|
|
( |
) |
|
|
|
||
Proceeds from sale of assets |
|
|
|
|
|
|
|
|
|
|||
Net cash used in investing activities |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|||
Repayments of long-term debt |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
Borrowings on revolver |
|
|
|
|
|
|
|
|
|
|||
Repayments on revolver |
|
|
( |
) |
|
|
|
|
|
|
||
Contingent consideration payments |
|
|
( |
) |
|
|
|
|
|
|
||
Common stock issuance |
|
|
|
|
|
|
|
|
|
|||
Treasury stock purchase |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Related party receivable |
|
|
|
|
|
|
|
|
( |
) |
||
Finance lease payments |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Net cash provided (used) in financing activities |
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
Net decrease in cash and cash equivalents and restricted cash |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
Cash and cash equivalents and restricted cash at beginning of period |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Cash and cash equivalents and restricted cash at end of period |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Reconciliation of cash, cash equivalents, and restricted cash at end of period: |
|
|
|
|
|
|
|
|
|
|||
Cash and cash equivalents |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Restricted cash and cash equivalents - current |
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|||
Restricted cash and cash equivalents - non-current |
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|
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|
|
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|||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
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MONTAUK RENEWABLES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
For The Year Ended December 31, |
|
|||||||||
|
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2025 |
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2024 |
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2023 |
|
|||
Supplemental cash flow information: |
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|
|||
Cash paid for interest, net of $ |
|
$ |
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|
$ |
|
|
$ |
|
|||
Cash paid for income taxes |
|
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|
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|
|||
Accrual for purchase of property, plant and equipment included in accounts payable and accrued liabilities |
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|||
Non-cash purchase of Treasury stock |
|
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|||
Non-cash RIN distribution from equity method investment |
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The accompanying notes to the consolidated financial statements are an integral part of these statements.
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MONTAUK RENEWABLES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1—DESCRIPTION OF BUSINESS
Operations and organization
Montauk Renewables’ Business
Montauk Renewables, Inc. (the “Company” or “Montauk Renewables”) is a renewable energy company specializing in the management, recovery and conversion of biogas into Renewable Natural Gas (“RNG”). The Company captures methane, preventing it from being released into the atmosphere, and converts it into either RNG or electrical power for the electrical grid (“Renewable Electricity”). The Company, headquartered in Pittsburgh, Pennsylvania, has more than
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
An additional program utilized by the Company is the Low Carbon Fuel Standard (“LCFS”). This is state specific and is designed to stimulate the use of low-carbon fuels. To the extent that RNG from the Company’s facilities is used as a transportation fuel in states that have adopted an LCFS program, it is eligible to receive an Environmental Attribute additional to the RIN value under the federal RFS.
Another key revenue driver is the sale of captured electricity and the associated environmental premiums related to renewable sales. The Company’s electric facilities are designed to conform to and monetize various state renewable portfolio standards requiring a percentage of the electricity produced in that state to come from a renewable resource. Such premiums are in the form of Renewable Energy Credits (“RECs”). The Company’s largest electric facility, located in California, receives revenue for the monetization of RECs as a part of a purchase power agreement.
Collectively, the Company benefits from federal and state government incentives in the United States, provided in the form of RINs, RECs, LCFS credits, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects, that promote the use of renewable energy, as Environmental Attributes.
Background and Reorganization Transactions
On January 4, 2021, the Company, Montauk Holdings Limited (“MNK”) and Montauk Holdings USA, LLC (a direct wholly-owned subsidiary of MNK at the time, “Montauk USA”) entered into a series of transactions, including an equity exchange and a distribution collectively referred to as the “Reorganization Transactions,” that resulted in the Company owning all of the assets and entities (other than Montauk USA) previously owned by Montauk USA, and Montauk Renewables became a direct wholly-owned subsidiary of MNK. Prior to the Reorganization Transactions, MNK’s business and operations were conducted entirely through Montauk USA and its U.S. subsidiaries, and MNK held no substantial assets other than equity of Montauk USA. The Company had no significant operations or assets prior to January 4, 2021 when it engaged in the equity exchange with Montauk USA and MNK.
After completion of the Reorganization Transactions, (i) Montauk USA ceased to own any substantial assets and (ii) all entities through which MNK’s business and operations were conducted became owned, directly or indirectly, by the Company. MNK adopted a plan contemporaneously with the completion of the Reorganization Transactions that authorized the liquidation and dissolution of MNK.
On January 15, 2021, MNK sold the membership interest of Montauk USA to a third party. On January 26, 2021, MNK distributed all of the outstanding shares of the Company’s common stock as a pro rata dividend to the holders of MNK’s ordinary shares (the “Distribution”), subject to any tax withholding obligations under applicable South African law. Each ordinary share of MNK outstanding on January 21, 2021, the record date for the Distribution (the “Record Date”), entitled the holder thereof to receive one share of the Company’s common stock.
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On January 26, 2021, the Company closed the initial public offering of its common stock on the Nasdaq Capital Market (the “IPO”) with the shares traded under the symbol “MNTK”. Montauk Renewables issued
On January 26, 2021, the Company entered into a Loan Agreement and Secured Promissory Note (as amended on February 22, 2021, December 22, 2021, December 22, 2022, December 27, 2023 and March 5, 2025) with MNK pursuant to which the Company advanced a cash loan to MNK for MNK to pay its dividends tax liability arising from the Reorganization Transactions under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended. The terms of the loan following the amendments are substantially similar to the initial loan agreement and were primarily entered into to (1) increase the principal amount outstanding under the loan to $
MNK was delisted from the JSE on January 26, 2021. The MNK Board of Directors and Shareholders held its annual general meeting in March 2023 and voted to take MNK private.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The historical consolidated financial information included reflects the historical results of operations and financial position of Montauk USA through January 4, 2021 when MNK sold the membership interest of Montauk USA. The consolidated financial statements of Montauk USA became the Company’s historical financial statements following the IPO. Certain historical financial information included relates to periods prior to the Reorganization Transactions. On December 31, 2024, the Company re-assessed its determination of the primary beneficiary of the Variable Interest Entity ("VIE") MNK under the guidance in ASC 810, Consolidation. Refer to Note 17 – Related Parties for further information. All intercompany balances and transactions have been eliminated in consolidation.
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
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
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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.
Cash, Cash Equivalents and Restricted Cash
Accounts and Other Receivables
Property, Plant and Equipment
Property, plant and equipment purchases are stated at cost, except for asset retirement obligations, which are recorded at estimated fair value at inception date. Depreciation and amortization are based on costs less estimated salvage values, primarily using the straight-line method over the estimated useful lives or, if applicable, the term of the related gas rights agreements or power purchase agreements, whichever is shorter. Maintenance and repairs are expensed as incurred. Major improvements that extend the useful lives of property are capitalized.
The estimated useful lives of the Company’s property, plant and equipment reflect the expected consumption of the economic benefit of these assets as noted in the following table:
Buildings and improvements |
|
Machinery and equipment |
|
Gas mineral rights |
Goodwill and Intangible Assets
Goodwill is the cost of an acquisition less the fair value of the identified net assets of the acquired business.
Separately identifiable intangible assets are recorded at their fair values upon acquisition. The Company accounts for its intangible assets in accordance with ASC 350, Intangibles—Goodwill and Other (“ASC 350”). Finite-lived intangible assets include interconnections, customer contracts and trade names & trademarks. The interconnection intangible asset is the exclusive right to utilize an interconnection line between the operating plant and a utility substation to transmit produced natural gas and 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 as depicted in the chart below. Indefinite intangible assets are not amortized and include emission allowances and land use rights.
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The estimated useful lives of separately identified intangible assets are as follows:
Interconnection |
|
Customer contracts |
|
Emissions allowances |
|
Land use rights |
Leases
The Company assesses leases in accordance with ASU 2016-02, Leases, (“ASU 2016-02”). This ASU requires lessees to recognize a right-of-use asset and lease liability on the Consolidated Balance Sheet for leases classified as either operating or finance leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize a right-of-use asset and lease liability. Additionally, when measuring assets and liabilities arising from a lease, optional payments should be included only if the lessee is reasonably certain to exercise an option to extend the lease, exercise a purchase option, or not exercise an option to terminate the lease. A right-of-use asset represents an entity’s right to use the underlying asset for the lease term, and a lease liability represents an entity’s obligation to make lease payments. The measurement, recognition and presentation of expenses and cash flows arising from leases by a lessee remains the same. The Company has included further lease disclosures in Note 19.
Long-lived Asset Impairment
In accordance with ASC 360, Property, plant, 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. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets.
A summary of impairment losses on tangible and intangible assets for the year ended December 31, 2025, 2024 and 2023 is included in Note 3.
Indefinite-Lived Asset Impairment
Indefinite-lived intangible assets are required to be evaluated for impairment at least annually or whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable. The evaluation of impairment under ASC 350 requires the use of projections, estimates and assumptions as to the future performance of the Company’s operations, including anticipated future revenues, expected operating costs and the discount factor used. Actual results may differ from projections. If such indefinite-lived 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.
Asset Retirement Obligations
The Company accounts for asset retirement obligations as required under ASC 410, Asset Retirement and Environmental Obligations, (“ASC 410”). ASC 410 requires the fair value of a liability for an asset retirement obligation be recognized in the period in which the legal obligation arises, with the associated discounted asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset and the annual accretion expense recorded in operations. The Company has recorded in the consolidated financial statements estimates for asset retirement obligations related to the decommissioning and removal requirements for specific gas processing and distribution assets, as required by their associated gas rights agreements.
Revenue
The Company recognizes revenue in accordance with ASC 606, Revenue from Contracts with Customers (“ASC 606”). Revenue from the Company’s point in time product sales is recognized when products are transferred, or services are invoiced and control transferred. Revenue from the Company’s product and service sales provided under long-term agreements is recognized as the Company transfers control of the product or renders service to its customers, which approximates the time when the customer is invoiced. The Company has presented the disclosures required by ASC 606 in Note 4.
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Income Taxes
The Company is treated as a corporation for income tax purposes. Therefore, income taxes are accounted for under the liability method on a consolidated basis by the Company and its consolidated subsidiaries in accordance with ASC 740, Income Taxes (“ASC 740”). Deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws. The provision for income taxes includes federal and state income taxes.
The Company recognizes the financial statement benefit of a tax position only after determining the relevant tax authority would more-likely-than-not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the consolidated financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company recognizes accrued interest and penalties related to unrecognized tax benefits in income tax expense.
Derivative Instruments
Fair Value of Financial Instruments
The Company employs varying methods and assumptions in estimating the fair value of each class of financial instruments for which it is practical to estimate fair value. For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value due to the short maturity of these instruments. For long-term debt, the carrying amounts approximate fair value as the interest rates obtained by the Company approximate the prevailing interest rates available to the Company for similar instruments.
In accordance with ASC 820, Fair Value Measurement (“ASC 820”), a hierarchy is established which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:
Level 1—Unadjusted quoted prices in active markets for identical unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
Level 2—Inputs other than quoted prices included within Level 1 that are observable for the assets and liabilities or can be corroborated with observable market data for substantially the entire contractual term of the assets or liabilities.
Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the assets or liabilities and are consequently not based on market activity but rather through particular valuation techniques. The Company uses the fair value methodology to value the assets and liabilities recorded at fair value, including the Company’s asset retirement obligations and earn out liability.
The values of the Level 2 interest rate derivatives were determined using a model, which incorporates market inputs including the implied forward interest rate yield curve for the same period as the future interest rate swap settlement. The Company has also considered both its own credit risk and counterparty credit risk in determining fair value and determined these adjustments were insignificant for the years ended December 31, 2025 and 2024. The Company’s asset retirement obligations are recorded at fair value at the time the liability is incurred if a reasonable estimate of fair value can be made. Fair value is determined by calculating the estimated present value of the cost to retire the asset as determined by qualified engineers, based on currently available information and inflation estimates and is considered a Level 3 measurement. The Company’s earn-out liability fair value is determined by calculating the estimated present value of future obligations based on currently available information and the discount factor used and is considered a Level 3 measurement.
A summary of changes in the fair values of the Company’s Level 3 instruments, attributable to asset retirement obligations and the earn out liability, for the years ended December 31, 2025 and 2024 is included in Note 11.
Renewable Identification Numbers (“RINs”)
The Company generates D3 RINs through its production and sale of RNG used for transportation purposes as prescribed under the Federal Renewable Fuel Standard. The RINs that the Company generates as government incentives through its renewable operating projects can be separated and sold as credits independent from the energy produced and not a result of physical attributes of the Company’s production. Therefore, no cost is allocated to the RIN when it is generated. Revenue is recognized on these
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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. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The Company had
Renewable Energy Credits (“RECs”)
The Company generates RECs through its production and sale of landfill methane into renewable electric energy as prescribed by the State of California Renewables Portfolio Standard or the EPA. The RECs that the Company generates as government incentives through its renewable operating projects are able to be separated and sold as credits independent from the electricity produced and not a result of physical attributes of the Company’s production. 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.
Equity-Based Compensation
The Company accounts for equity-based compensation under the provisions of ASC 718, Compensation—Stock Compensation, (“ASC 718”). ASC 718 requires compensation costs related to share-based payment transactions, measured based on the fair value of the instruments issued, be recognized in the consolidated financial statements over the requisite service period of the award. Stock options are initially measured on the grant date using the Black-Scholes valuation model, which requires the use of subjective assumptions related to the expected stock price volatility, term, risk-free interest rate and dividend yield. For restricted stock shares, the Company determines the grant date fair value based on the closing market price of the stock on the date of the grant. Forfeitures are recognized when they occur.
Employee Benefits
Leave entitlement
Employee entitlements to annual leave are recognized when they accrue to employees. An accrual is made for the estimated liability to the employees for annual leave up to the financial year end date. This liability is included in “Accrued liabilities” in the Consolidated Balance Sheets.
Bonus Plans
The Company recognizes a liability and an expense for incentive compensation bonuses awarded based on the achievement of Company and personnel goals where contractually obliged or where there is a past practice that has created a constructive obligation. An accrual is maintained for the appropriate proportion of the expected bonuses which would become payable at year end.
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 Note 14.
Recently Issued Accounting Standards
In November 2024, the FASB issued ASU 2024-03, Income Statement — Reporting Comprehensive Income — Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. This ASU requires public business entities to disclose, on an annual and interim basis, disaggregated information about certain income statement expense line items. The ASU also requires disclosure of the total amount of selling expenses recognized in continuing operations on an annual and interim basis and disclosure of a public business entity’s definition of selling expenses on an annual basis (or in interim reporting periods if the definition is changed). Public business entities are required to apply the guidance prospectively but are permitted to apply it retrospectively. The ASU is effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. The Company is currently evaluating the impact of this standard on its consolidated financial statements.
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NOTE 3—ASSET IMPAIRMENT
The Company recorded $
Impairment loss was recorded under Operating expenses within the Consolidated Statements of Operations for the years ended December 31, 2025, 2024, and 2023.
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
The Company’s performance obligations related to the sale of Environmental Attributes are generally satisfied at a point in time and were
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The following tables display the Company’s disaggregated revenue by major source, based on product type and timing of transfer of goods and services for the years ended December 31, 2025, 2024 and 2023:
|
|
Year Ended December 31, 2025 |
|
|||||||||
|
|
Goods transferred at a point in time |
|
|
Goods transferred over time |
|
|
Total |
|
|||
Major goods/Service line: |
|
|
|
|
|
|
|
|
|
|||
Natural gas commodity |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Natural gas environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
Electric commodity |
|
|
— |
|
|
|
|
|
|
|
||
Electric environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
Operating segment: |
|
|
|
|
|
|
|
|
|
|||
RNG |
|
$ |
|
|
$ |
|
|
$ |
|
|||
REG |
|
|
|
|
|
|
|
|
|
|||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
Year Ended December 31, 2024 |
|
|||||||||
|
|
Goods transferred at a point in time |
|
|
Goods transferred over time |
|
|
Total |
|
|||
Major goods/Service line: |
|
|
|
|
|
|
|
|
|
|||
Natural gas commodity |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Natural gas environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
Electric commodity |
|
|
— |
|
|
|
|
|
|
|
||
Electric environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
Operating segment: |
|
|
|
|
|
|
|
|
|
|||
RNG |
|
$ |
|
|
$ |
|
|
$ |
|
|||
REG |
|
|
|
|
|
|
|
|
|
|||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
Year Ended December 31, 2023 |
|
|||||||||
|
|
Goods transferred at a point in time |
|
|
Goods transferred over time |
|
|
Total |
|
|||
Major goods/Service line: |
|
|
|
|
|
|
|
|
|
|||
Natural gas commodity |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Natural gas environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
Electric commodity |
|
|
— |
|
|
|
|
|
|
|
||
Electric environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
Operating segment: |
|
|
|
|
|
|
|
|
|
|||
RNG |
|
$ |
|
|
$ |
|
|
$ |
|
|||
REG |
|
|
|
|
|
|
|
|
|
|||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
Practical expedients and remaining performance obligations
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
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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 December 31, 2025, the Company has contributed $
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. Credit terms are consistent with industry standards and practices. Accounts Receivable consist of sales to large creditworthy energy and utility companies. Reserves for uncollectible accounts, if any, are recorded as part of general and administrative expenses in the Consolidated Statements of Operations.
Accounts and other receivables consist of the following as of December 31, 2025, 2024 and 2023:
|
December 31, 2025 |
|
December 31, 2024 |
|
December 31, 2023 |
|
|||
Accounts receivables |
$ |
|
$ |
|
$ |
|
|||
Other receivables |
|
|
|
|
|
|
|||
Reimbursable expenses |
|
|
|
|
|
||||
Accounts and other receivables, net |
$ |
|
$ |
|
$ |
|
|||
NOTE 7—PROPERTY, PLANT AND EQUIPMENT, NET
Property, plant and equipment consists of the following as of December 31, 2025 and 2024:
|
December 31, 2025 |
|
December 31, 2024 |
|
||
Land |
$ |
|
$ |
|
||
Buildings and improvements |
|
|
|
|
||
Machinery and equipment |
|
|
|
|
||
Gas mineral rights |
|
|
|
|
||
Construction work in progress |
|
|
|
|
||
Total |
$ |
|
$ |
|
||
Less: Accumulated depreciation and amortization |
|
( |
) |
|
( |
) |
Property, plant & equipment, net |
$ |
|
$ |
|
||
Depreciation expense for Property, plant and equipment was $
Construction work in progress consists of RNG and REG capital expenditures on developmental projects and improvements to existing sites. Projects, on average, last between
In February 2024, the Company completed an Asset acquisition with a privately-held entity. The Company paid $
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Combinations, and the purchase price has been allocated all to land within Property, plant and equipment, net on the Company's consolidated balance sheet.
In February 2024, for one of its REG sites, the Company entered into a bill of sale, assignment and assumption agreement to sell its rights to the existing fuel supply agreement and property back to the site host in advance of the fuel supply agreement termination date and received $
In October 2024, the Company entered into an asset purchase agreement to sell one of its immaterial RNG sites for a purchase price of $
NOTE 8—GOODWILL AND INTANGIBLE ASSETS, NET
Goodwill and Intangible assets consist of the following as of December 31, 2025 and December 31, 2024:
|
|
December 31, 2025 |
|
|
December 31, 2024 |
|
||
Goodwill |
|
$ |
|
|
$ |
|
||
Intangible assets with indefinite lives: |
|
|
|
|
|
|
||
Land use rights |
|
|
|
|
|
|
||
Total intangible assets with indefinite lives: |
|
$ |
|
|
$ |
|
||
Intangible assets with finite lives: |
|
|
|
|
|
|
||
Interconnection, net of accumulated amortization |
|
$ |
|
|
$ |
|
||
Customer contracts, net of accumulated |
|
|
|
|
|
|
||
Total intangible assets with finite lives: |
|
$ |
|
|
$ |
|
||
Total Goodwill and Intangible assets |
|
$ |
|
|
$ |
|
||
The weighted average remaining useful life of the customer contracts and interconnections are approximately
Amortization expense for customer contracts and interconnections for the next five years is as follows:
|
|
Customer |
|
|
Inter- |
|
||
Year ending |
|
Contracts |
|
|
connections |
|
||
2026 |
|
$ |
|
|
$ |
|
||
2027 |
|
|
|
|
|
|
||
2028 |
|
|
|
|
|
|
||
2029 |
|
|
|
|
|
|
||
2030 |
|
|
|
|
|
|
||
Thereafter |
|
|
|
|
|
|
||
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 political environments can affect the fair value of the obligations. As such, asset retirement obligations are considered a level 3 financial instrument.
The 2025 $
-72-
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The following table summarizes the activity associated with asset retirement obligations of the Company for the years ended December 31, 2025, 2024 and 2023:
|
For The Year Ended December 31, |
|
|||||||||
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Asset retirement obligations—beginning of period |
$ |
|
|
$ |
|
|
$ |
|
|||
Accretion expense |
|
|
|
|
|
|
|
|
|||
New asset retirement obligation |
|
|
|
|
|
|
|
|
|||
Changes in estimate |
|
|
|
|
|
|
|||||
Liabilities associated with properties sold |
|
|
|
( |
) |
|
|
||||
Asset retirement obligations—end of period |
$ |
|
|
$ |
|
|
$ |
|
|||
NOTE 10—DERIVATIVE INSTRUMENTS
To mitigate market risk associated with fluctuations in interest rates, the Company utilizes various derivative contracts to secure interest rates 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.
|
|
For The Year Ended December 31, |
|
|
|
|||||
Derivative Instrument |
Location |
2025 |
|
2024 |
|
2023 |
|
|||
Interest rate swaps |
Interest expense |
|
( |
) |
|
( |
) |
|
( |
) |
loss |
|
$ |
( |
) |
$ |
( |
) |
$ |
( |
) |
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 December 31, 2025 and 2024, set forth by level, within the fair value hierarchy:
|
December 31, 2025 |
|
||||||||||
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
||||
Interest rate swap derivative asset |
$ |
|
$ |
|
$ |
|
$ |
|
||||
Asset retirement obligations |
|
|
|
|
|
( |
) |
|
( |
) |
||
|
$ |
|
$ |
|
$ |
( |
) |
$ |
( |
) |
||
|
December 31, 2024 |
|
||||||||||
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
||||
Interest rate swap derivative asset |
$ |
|
$ |
|
$ |
|
$ |
|
||||
Asset retirement obligations |
|
|
|
|
|
( |
) |
|
( |
) |
||
Pico earn-out liability |
|
|
|
|
|
( |
) |
|
( |
) |
||
|
$ |
|
$ |
|
$ |
( |
) |
$ |
( |
) |
||
Interest rate swap derivatives are classified as Level 2 financial instruments and are valued utilizing Secured Overnight Financing Rates. In addition, certain assets are measured at fair value on a non-recurring basis when an indicator of impairment is identified and the assets’ fair values are determined to be less than its carrying value. See Note 3 for additional information.
A summary of changes in the fair value of the Company’s Level 3 instrument, attributable to asset retirement obligations, for the years ended December 31, 2025, 2024 and 2023 is included in Note 9. The Company’s earn-out fair value liability at its Idaho agricultural digester site was determined by calculating the estimated present value of the future obligation. The present value was assessed quarterly and was based on macro-economic factors such as inflation and risk free US Treasury rates. Company specific estimates utilized included current and future interest rates, digester inlet gas flow and projected EBITDA. A weighted average probability approach was utilized for the variables discussed above. The undiscounted maximum payout of the earn-out ranged between
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Table of Contents
the balance are recorded in Accrued liabilities and Other liabilities within the Consolidated Balance Sheets and in Royalties, transportation, gathering and production fuel within the Consolidated Statements of Operations.
There were
NOTE 12—ACCRUED LIABILITIES
The Company’s accrued liabilities consists of the following as of December 31, 2025 and December 31, 2024:
|
December 31, 2025 |
|
December 31, 2024 |
|
||
Accrued expenses |
$ |
|
$ |
|
||
Payroll and related benefits |
|
|
|
|
||
Royalty |
|
|
|
|
||
Utility |
|
|
|
|
||
Accrued interest |
|
|
|
|
||
Other |
|
|
|
|
||
Accrued liabilities |
$ |
|
$ |
|
||
NOTE 13—DEBT
On March 9, 2026, the Company refinanced its entire debt maturing in December 2026 with a New Senior Credit Facility with a new lender. Under ASC 470-10-45-14 guidance, the Company classified its existing debt as $
The Company’s debt consists of the following as of December 31, 2025 and December 31, 2024:
|
December 31, 2025 |
|
December 31, 2024 |
|
||
Term loans |
$ |
|
$ |
|
||
Revolver |
|
|
— |
|
||
Less: current principal maturities |
|
( |
) |
|
( |
) |
Less: debt issuance costs (on long-term debt) |
— |
|
|
( |
) |
|
Long-term debt |
$ |
|
$ |
|
||
Current portion of long-term debt |
|
|
|
|
||
Total debt |
$ |
|
$ |
|
||
Amended Credit Agreement
On December 12, 2018, Montauk Energy Holdings LLC (“MEH”) entered into the Second Amended and Restated Revolving Credit and Term Loan Agreement (as amended, “Credit Agreement”), by and among MEH, the financial institutions from time to time party thereto as lenders and Comerica Bank, as the administrative agent, sole lead arranger and sole bookrunner (“Comerica”). The Credit Agreement (i) amended and restated in its entirety MEH’s prior revolving credit and term loan facility, dated as of August 4, 2017, as amended, with Comerica and certain other financial institutions and (ii) replaced in its entirety the prior credit agreement, dated as of August 4, 2017, as amended, between Comerica and Bowerman Power LFG, LLC, a wholly-owned subsidiary of MEH.
On March 21, 2019, MEH entered into the first amendment to the Credit Agreement which clarified a variety of terms, definitions and calculations in the Credit Agreement. The Credit Agreement requires the Company to maintain customary affirmative and negative covenants, including certain financial covenants, which are measured at the end of each fiscal quarter.
On August 28, 2019, the Company received a temporary waiver for an anticipated Event of Default (as defined in the Credit Agreement) for the consecutive three-month period ended on August 31, 2019 (the “Specified Event of Default”). The Specified Event of Default was waived through October 1, 2019.
On September 12, 2019, the Company entered into the second amendment to the Credit Agreement (the "Second Amendment"). Among other matters, the Second Amendment redefined the Fixed Charge Coverage Ratio (as defined in the Credit Agreement), reduced the commitments under the revolving credit facility to $
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Table of Contents
Second Amendment, the Company paid down the outstanding term loan by $
On January 4, 2021, the Company, Montauk Holdings Limited (“MNK”) and Montauk Holdings USA, LLC (a direct wholly-owned subsidiary of MNK at the time, “Montauk USA”) entered into a series of transactions, including an equity exchange and a distribution collectively referred to as the “Reorganization Transactions,” that resulted in the Company owning all of the assets and entities (other than Montauk USA) previously owned by Montauk USA, and Montauk Renewables became a direct wholly-owned subsidiary of MNK. In connection with the completion of the Reorganization Transactions and the IPO, the Company entered into the third amendment to the Credit Agreement (the “Third Amendment”). This amendment permitted the change of control provisions, as defined in the underlying agreement, to permit the Reorganization Transactions and the IPO to be completed.
On December 21, 2021, MEH entered into the Fourth Amendment to the Second Amended and Restated Revolving Credit and Term Loan Agreement. The current credit agreement, which is secured by a lien on substantially all assets of the Company and certain of its subsidiaries, provides for a $
The Company accounted for the Fourth amendment as both a debt modification and debt extinguishment in accordance with ASC 470, Debt (“ASC 470”). In connection with the Credit Agreement, the Company paid $
On November 8, 2024, MEH entered into the Fifth Amendment to the Second Amended and Restated Revolving Credit and Term Loan Agreement. The Fifth amendment replaced the Bloomberg Short-Term Bank Yield Index Rate utilized for interest rates with the Secured Overnight Financing Rate Index ("SOFR"), plus applicable margin.
On December 31, 2025, MEH entered into the Sixth Amendment to the Second Amended and Restated Revolving Credit and Term Loan Agreement. The Sixth Amendment redefined the Total Net Leverage Ratio and accelerated the presentment of monthly unaudited financial statements to Comerica, along with the requirement of an engineering study and independent engineer's certificate as it relates to operations in North Carolina by June 3, 2026. As part of the Sixth Amendment, the Company was required to pay $
As of December 31, 2025, $
As of December 31, 2025, the Company was in compliance with all applicable debt covenants related to the Credit Agreement with Comerica Bank. Please refer to Note 22 – Subsequent Events for discussion of the New Senior Credit Facility that the Company entered into on March 9, 2026.
Annual Maturities of Long-Term Debt
The following is a summary of annual principal maturities of long-term debt as of December 31, 2025:
Year ending |
Amount |
|
|
2026 |
|
|
|
Total |
$ |
|
|
NOTE 14—INCOME TAXES
The Company is 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.
-75-
Table of Contents
|
|
Year Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
(Loss) income before income taxes: |
|
|
|
|
|
|
|
|
|
|||
Domestic |
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
Foreign |
|
|
( |
) |
|
|
|
|
|
|
||
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
The following table details the components of the Company’s income tax provision for the years ended December 31, 2025, 2024 and 2023:
|
|
Year Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Current expense: |
|
|
|
|
|
|
|
|
|
|||
Federal |
|
$ |
|
|
$ |
|
|
$ |
|
|||
State |
|
|
|
|
|
|
|
|
|
|||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Deferred (benefit) expense: |
|
|
|
|
|
|
|
|
|
|||
Federal |
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
State |
|
|
|
|
|
|
|
|
|
|||
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
|
|
|
|
|
|
|
|
|
|
|||
Income tax (benefit) expense |
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
The following table illustrates the deferred tax assets and liabilities as of December 31, 2025 and December 31, 2024:
|
|
December 31, 2025 |
|
|
December 31, 2024 |
|
||
Deferred tax assets: |
|
|
|
|
|
|
||
Net operating loss carry forwards |
|
$ |
|
|
$ |
|
||
Federal tax credits |
|
|
|
|
|
|
||
Book reserves |
|
|
|
|
|
|
||
Intangible asset amortization |
|
|
|
|
|
|
||
Stock compensation |
|
|
|
|
|
|
||
Impairment |
|
|
|
|
|
|
||
Lease liabilities |
|
|
|
|
|
|
||
VIE Loss on investment |
|
|
|
|
|
|
||
Total deferred tax assets |
|
|
|
|
|
|
||
Less: valuation analysis |
|
|
( |
) |
|
|
( |
) |
Net deferred tax assets |
|
$ |
|
|
$ |
|
||
|
|
|
|
|
|
|
||
Deferred tax liabilities: |
|
|
|
|
|
|
||
Property depreciation |
|
$ |
( |
) |
|
$ |
( |
) |
Right of use assets |
|
|
( |
) |
|
|
( |
) |
Total deferred tax liabilities |
|
|
( |
) |
|
|
( |
) |
Net deferred tax assets |
|
|
|
|
|
|
||
As of December 31, 2025, the Company has $
The following table details the components of the Company’s income tax provision for the years ended December 31, 2025, 2024 and 2023:
-76-
Table of Contents
|
|
Year Ended December 31, |
|
||||||||||||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
||||||||||||
U.S. federal tax at statutory rate |
|
$ |
( |
) |
|
% |
|
$ |
|
|
% |
|
$ |
|
|
% |
|||||
State and local income taxes, net of federal income tax effect |
|
|
|
|
- |
% |
|
|
|
|
% |
|
|
|
|
% |
|||||
Tax credits: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Energy-related tax credits |
|
|
( |
) |
|
% |
|
|
( |
) |
|
- |
% |
|
|
( |
) |
|
- |
% |
|
Changes in valuation allowances |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Nontaxable or nondeductible items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Share-based payment awards |
|
|
|
|
- |
% |
|
|
|
|
% |
|
|
( |
) |
|
- |
% |
|||
Limitation on executive compensation |
|
|
( |
) |
|
% |
|
|
|
|
% |
|
|
|
|
% |
|||||
Other |
|
|
|
|
- |
% |
|
|
|
|
% |
|
|
|
|
% |
|||||
Changes in unrecognized tax benefits |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Other adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
% |
|||||
Total income tax (benefit) expense and effective rate |
|
$ |
( |
) |
|
% |
|
$ |
|
|
% |
|
$ |
|
|
% |
|||||
State taxes in Pennsylvania and Texas comprise the majority of the state and local income taxes, net of federal effect category in all presented years.
As of December 31, 2025, the tax years are open for examination by the IRS.
|
|
Year Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Federal: |
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
State: |
|
|
|
|
|
|
|
|
|
|||
California |
|
|
|
|
|
|
|
|
|
|||
Idaho |
|
|
|
|
|
|
|
|
|
|||
Pennsylvania |
|
|
|
|
|
|
|
|
|
|||
Texas |
|
|
|
|
|
|
|
|
|
|||
Other |
|
|
|
|
|
|
|
|
|
|||
Net cash paid for income taxes |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Valuation Allowance
The Company annually reviews its deferred tax assets for the possibility they will not be realized. A valuation allowance will be recorded if it is determined more than a 50% likelihood exists that a deferred tax asset will not be realized. A $
Uncertain Tax Position
The calculation of the Company’s tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in both federal and state jurisdictions. ASC 740 states that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, on the basis of each situation’s technical merits.
-77-
Table of Contents
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
In connection with a May 2021 asset acquisition,
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 $
The restricted shares, restricted stock units and option awards are subject to vesting schedules and are subject to the terms and conditions of the MRI EICP and related award agreements including, in the case of the restricted share awards, each officer having made an election under Section 83(b) of the Code.
Options granted under the MRI EICP allow the recipient to receive the Company’s common stock equal to the appreciation in the fair market value of the Company’s common stock between the grant date and the exercise and settlement of options into shares as of the exercise date(s).
|
|
|
|
|
|
|
April 2023 Awards |
|
|
Options awarded |
|
|
|
|
Risk-free interest rate |
|
|
||
Expected volatility |
|
|
||
Expected option life (in years) |
|
|
||
Grant-date fair value |
|
$ |
|
|
|
|
|
|
|
|
|
January 2021 Awards |
|
|
Options awarded |
|
|
|
|
Risk-free interest rate |
|
|
||
Expected volatility |
|
|
||
Expected option life (in years) |
|
|
|
|
Grant-date fair value |
|
$ |
|
|
-78-
Table of Contents
The following table summarizes the restricted shares, restricted stock units and options outstanding under the MRI EICP for the years ended December 31, 2025, 2024 and 2023:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
Restricted Shares |
|
|
Restricted Stock Units |
|
|
Options |
|
|||||||||||||||
|
|
Number of |
|
|
Weighted |
|
|
Number of |
|
|
Weighted |
|
|
Number of |
|
|
Weighted |
|
||||||
End of period - December 31, 2023 |
|
|
|
|
$ |
|
|
|
|
|
$ |
|
|
|
|
|
$ |
|
||||||
Beginning of period - January 1, 2024 |
|
|
|
|
$ |
|
|
|
|
|
$ |
|
|
|
|
|
$ |
|
||||||
Granted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Vested |
|
|
( |
) |
|
|
|
|
|
( |
) |
|
|
|
|
|
|
|
|
|
||||
End of period - Balance at December 31, 2024 |
|
|
|
|
$ |
|
|
|
|
|
$ |
|
|
|
|
|
$ |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
End of period - December 31, 2024 |
|
|
|
|
$ |
|
|
|
|
|
$ |
|
|
|
|
|
$ |
|
||||||
Beginning of period - January 1, 2025 |
|
|
|
|
$ |
|
|
|
|
|
$ |
|
|
|
|
|
$ |
|
||||||
Granted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Vested |
|
|
( |
) |
|
|
|
|
|
( |
) |
|
|
|
|
|
|
|
|
|
||||
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||||
End of period - December 31, 2025 |
|
|
|
|
$ |
|
|
|
|
|
$ |
|
|
|
|
|
$ |
|
||||||
|
|
|||||||||||||||||||||||
Unrecognized MRI EICP compensation expense for awards the Company expects to vest as of December 31, 2025, was $
NOTE 16—DEFINED CONTRIBUTION PLAN
The Company maintains a 401(k) defined contribution plan for eligible employees. The Company matches
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 currently an affiliate of the Company and certain of the Company’s directors are also directors of MNK. Pursuant to the Initial Promissory Note, the Company advanced a cash loan of $
-79-
Table of Contents
The "Third Amended and Restated Loan Agreement and Secured Promissory Note" increased the security interest of the Company from
In December 2021, Rivetprops 47 Proprietary Limited (“RP47”) entered into an agreement to loan MNK up to
Variable Interest Entities
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
Employment Transactions
The Company signed a long-term immaterial lease in December 2023 with a landowner in North Carolina. This lease enabled the Company to construct a feedstock collection system on the property which is owned by the Company. In September 2024, the Company hired the landowner as an employee to assist in the procuring of additional long-term leases on farms for additional collection system installations related to feedstock in North Carolina.
NOTE 18—SEGMENT INFORMATION
The Company’s reportable segments for the years ended December 31, 2025, 2024 and 2023 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 , who is the Company's chief operating decision maker ("CODM"), evaluates the performance of each segment and allocates the Company's resources.
-80-
Table of Contents
amounts are regularly reviewed by the CODM. “RNG” refers to Renewable Natural Gas and “REG” refers to Renewable Electricity Generation.
For The Year Ended December 31, 2025 |
|
|||||||||||
|
|
RNG |
|
|
REG |
|
|
Total |
|
|||
Operating segment revenue |
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Corporate and other revenue |
|
|
|
|
|
|
|
|
|
|||
Total consolidated revenue |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Less (1) |
|
|
|
|
|
|
|
|
|
|||
Payroll and related expenses |
|
|
|
|
|
|
|
|
|
|||
Wellfield operating and maintenance |
|
|
|
|
|
|
|
|
|
|||
Plant expense |
|
|
|
|
|
|
|
|
|
|||
Waste disposal |
|
|
|
|
|
|
|
|
|
|||
Preventative maintenance |
|
|
|
|
|
|
|
|
|
|||
Breakdown expenses |
|
|
|
|
|
|
|
|
|
|||
Utility expense |
|
|
|
|
|
|
|
|
|
|||
Royalties, transportation, gathering and production fuel |
|
|
|
|
|
|
|
|
|
|||
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
|
|||
Impairment |
|
|
|
|
|
|
|
|
|
|||
Other operating expenses (2) |
|
|
|
|
|
|
|
|
|
|||
Operating segment expenses |
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Corporate and other operating expenses (3) |
|
|
|
|
|
|
|
|
|
|||
Total consolidated operating expenses |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment income (loss) |
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||
|
|
|
|
|
|
|
|
|
|
|||
Corporate and other operating loss |
|
|
|
|
|
|
|
|
( |
) |
||
Total consolidated operating income |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment other expenses |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Corporate and other expenses (4) |
|
|
|
|
|
|
|
|
|
|||
Total consolidated other expenses |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment income (loss) before income taxes |
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||
|
|
|
|
|
|
|
|
|
|
|||
Corporate and other loss before income taxes |
|
|
|
|
|
|
|
|
( |
) |
||
Total consolidated loss before income taxes |
|
|
|
|
|
|
|
$ |
( |
) |
||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment assets |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Corporate and other assets |
|
|
|
|
|
|
|
|
|
|||
Total consolidated assets |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment capital expenditures |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Corporate and other capital expenditures |
|
|
|
|
|
|
|
|
|
|||
Total consolidated capital expenditures |
|
|
|
|
|
|
|
$ |
|
|||
(1)
(2)
(3)
(4)
-81-
Table of Contents
For The Year Ended December 31, 2024 |
|
|||||||||||
|
|
RNG |
|
|
REG |
|
|
Total |
|
|||
Operating segment revenue |
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Corporate and other revenue |
|
|
|
|
|
|
|
|
|
|||
Total consolidated revenue |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Less (1) |
|
|
|
|
|
|
|
|
|
|||
Payroll and related expenses |
|
|
|
|
|
|
|
|
|
|||
Wellfield operating and maintenance |
|
|
|
|
|
|
|
|
|
|||
Plant expense |
|
|
|
|
|
|
|
|
|
|||
Waste disposal |
|
|
|
|
|
|
|
|
|
|||
Preventative maintenance |
|
|
|
|
|
|
|
|
|
|||
Breakdown expenses |
|
|
|
|
|
|
|
|
|
|||
Utility expense |
|
|
|
|
|
|
|
|
|
|||
Royalties, transportation, gathering and production fuel |
|
|
|
|
|
|
|
|
|
|||
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
|
|||
Impairment |
|
|
|
|
|
|
|
|
|
|||
Other operating expenses (2) |
|
|
|
|
|
|
|
|
|
|||
Operating segment expenses |
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Corporate and other operating expenses (3) |
|
|
|
|
|
|
|
|
|
|||
Total consolidated operating expenses |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment income (loss) |
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||
|
|
|
|
|
|
|
|
|
|
|||
Corporate and other operating loss |
|
|
|
|
|
|
|
|
( |
) |
||
Total consolidated operating income |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment other income |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
Corporate and other expenses (4) |
|
|
|
|
|
|
|
|
|
|||
Total consolidated other expenses |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment income (loss) before income taxes |
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||
|
|
|
|
|
|
|
|
|
|
|||
Corporate and other loss before income taxes |
|
|
|
|
|
|
|
|
( |
) |
||
Total consolidated income before income taxes |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment assets |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Corporate and other assets |
|
|
|
|
|
|
|
|
|
|||
Total consolidated assets |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment capital expenditures |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Corporate and other capital expenditures |
|
|
|
|
|
|
|
|
|
|||
Total consolidated capital expenditures |
|
|
|
|
|
|
|
$ |
|
|||
(1)
(2)
(3)
(4)
-82-
Table of Contents
For The Year Ended December 31, 2023 |
|
|||||||||||
|
|
RNG |
|
|
REG |
|
|
Total |
|
|||
Operating segment revenue |
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Corporate and other revenue |
|
|
|
|
|
|
|
|
|
|||
Total consolidated revenue |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Less (1) |
|
|
|
|
|
|
|
|
|
|||
Payroll and related expenses |
|
|
|
|
|
|
|
|
|
|||
Wellfield operating and maintenance |
|
|
|
|
|
|
|
|
|
|||
Plant expense |
|
|
|
|
|
|
|
|
|
|||
Waste disposal |
|
|
|
|
|
|
|
|
|
|||
Preventative maintenance |
|
|
|
|
|
|
|
|
|
|||
Breakdown expenses |
|
|
|
|
|
|
|
|
|
|||
Utility expense |
|
|
|
|
|
|
|
|
|
|||
Royalties, transportation, gathering and production fuel |
|
|
|
|
|
|
|
|
|
|||
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
|
|||
Impairment |
|
|
|
|
|
|
|
|
|
|||
Other operating expenses (2) |
|
|
|
|
|
|
|
|
|
|||
Operating segment expenses |
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Corporate and other operating expenses (3) |
|
|
|
|
|
|
|
|
|
|||
Total consolidated operating expenses |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment income (loss) |
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||
|
|
|
|
|
|
|
|
|
|
|||
Corporate and other operating loss |
|
|
|
|
|
|
|
|
( |
) |
||
Total consolidated operating income |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment other expenses (income) |
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
Corporate and other expenses (4) |
|
|
|
|
|
|
|
|
|
|||
Total consolidated other expenses |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment income (loss) before income taxes |
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||
|
|
|
|
|
|
|
|
|
|
|||
Corporate and other loss before income taxes |
|
|
|
|
|
|
|
|
( |
) |
||
Total consolidated income before income taxes |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment assets |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Corporate and other assets |
|
|
|
|
|
|
|
|
|
|||
Total consolidated assets |
|
|
|
|
|
|
|
$ |
|
|||
|
|
|
|
|
|
|
|
|
|
|||
Operating segment capital expenditures |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Corporate and other capital expenditures |
|
|
|
|
|
|
|
|
|
|||
Total consolidated capital expenditures |
|
|
|
|
|
|
|
$ |
|
|||
(1)
(2)
(3)
(4)
-83-
Table of Contents
For the years ended December 31, 2025, 2024 and 2023, two, four and three customers, respectively, made up greater than 10% of our total revenues.
|
|
Year Ended December 31, 2025 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Customer A |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer B |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
Year Ended December 31, 2024 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Customer A |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer B |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer C |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer D |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
Year Ended December 31, 2023 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Customer A |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer B |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer C |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
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.
As of December 31, 2025, there were no leases entered into which have not yet commenced and that would entitle the Company to significant rights or create additional obligations. The total lease cost included in our consolidated financial statements of operations for the years ended December 31, 2025, 2024 and 2023 were $
Leases with an initial term of 12 months or less are not recorded on the Consolidated Balance Sheet and the lease expense for those leases is recognized on a straight-line basis. The short-term lease expense for the years ended December 31, 2025, 2024 and 2023 were $
-84-
Table of Contents
Supplemental information related to operating lease arrangements was as follows as of and for the year ended December 31, 2025, 2024 and 2023:
|
|
For The Year Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Cash paid for amounts included in the measurement of |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Weighted average remaining lease term (in years) |
|
|
|
|
|
|
|
|
|
|||
Weighted average discount rate |
|
|
|
|
|
|
% |
|||||
|
|
|
|
|
|
|
|
|
|
|||
Future minimum operating lease payments for the years ending December 31, are as follows:
Year Ending |
|
|
|
|
2026 |
|
$ |
|
|
2027 |
|
|
|
|
2028 |
|
|
|
|
2029 |
|
|
|
|
2030 |
|
|
|
|
Thereafter |
|
|
|
|
Imputed interest |
|
|
( |
) |
Total |
|
$ |
|
|
Supplemental information related to finance lease arrangements was as follows:
|
|
For The Year Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Cash paid for amounts included in the measurement of |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Weighted average remaining lease term (in years) |
|
|
|
|
|
|
|
|
|
|||
Weighted average discount rate |
|
|
|
|
|
|
% |
|||||
|
|
|
|
|
|
|
|
|
|
|||
Future minimum finance lease payments are as follows:
Year Ending |
|
|
|
|
2026 |
|
$ |
|
|
2027 |
|
|
|
|
2028 |
|
|
|
|
2029 |
|
|
|
|
2030 |
|
|
|
|
Thereafter |
|
|
|
|
Imputed interest |
|
|
( |
) |
Total |
|
$ |
|
|
NOTE 20—COMMITMENTS AND CONTINGENCIES
Concentrations
A substantial portion of the Company’s revenues are generated from five locations in 2025, 2024, and 2023, each in separate areas of the country. For the years ended December 31, 2025, 2024 and 2023,
Environmental
The Company is subject to a variety of environmental laws and regulations governing discharges to the air and water, as well as the handling, storage and disposing of hazardous or waste materials. The Company believes its operations currently comply in all material respects with all environmental laws and regulations applicable to its business. However, there can be no assurance that environmental requirements will not change in the future or that the Company will not incur significant costs to comply with such requirements.
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Contingencies
The Company, from time to time, may be involved in litigation. At December 31, 2025, management does not believe there are any matters outstanding that would have a material adverse effect on the Company’s financial position or results of operations.
Note 21—INCOME PER SHARE
Basic and diluted income per share was computed using the following common share data for the years ended December 31, 2025, 2024 and 2023, respectively:
|
|
For The Year Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Net income |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Basic weighted-average shares outstanding |
|
|
|
|
|
|
|
|
|
|||
Dilutive effect of share-based awards |
|
|
|
|
|
|
|
|
|
|||
Diluted weighted-average shares outstanding |
|
|
|
|
|
|
|
|
|
|||
Basic income per share |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Diluted income per share |
|
$ |
|
|
$ |
|
|
$ |
|
|||
NOTE 22—SUBSEQUENT EVENTS
The Company evaluated subsequent events related to its December 31, 2025 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 financial statements, except for the matters discussed below.
On March 9, 2026, the Company entered into a new,
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 $
The New Senior Credit Facility has a 24 month availability period during which only interest is payable
In accordance with ASC 470-10-45-12 through 45, the Company classified $
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES.
Management’s Evaluation of Disclosure Controls and Procedures.
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. The Company, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, concluded that, as of December 31, 2025 (the end of the period covered by this Annual Report on Form 10-K), the Company’s disclosure controls and procedures were effective, pursuant to Rule 13a-15 and Rule 15d-15 of the Exchange Act.
Management’s Annual Report on Internal Control Over Financial Reporting.
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with appropriate authorizations; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.
Our management has conducted an evaluation of the effectiveness of our internal control over financial reporting, using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2013) (“COSO”). Based on the results of this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2025.
This Annual Report on Form 10-K does not include an attestation report of internal controls from our independent registered public accounting firm due to our status as an emerging growth company under the JOBS Act.
Changes in Internal Control over Financial Reporting.
In March 2025, we implemented a new Enterprise Resource Planning ("ERP") system. In conjunction with the ERP implementation, we updated the design of key internal controls over financial reporting.
Except as discussed above, there have been no changes during the quarter ended December 31, 2025, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting
ITEM 9B. OTHER INFORMATION.
Item 1.01 Entry into a Material Definitive Agreement.
On March 9, 2026, Montauk Renewables, Inc., a Delaware corporation (the “Company”) entered into a Senior Secured Term Loan Credit Agreement (“Credit Agreement”), dated as of March 9, 2026, by and among the Company, as the parent guarantor, Montauk Energy Holdings, LLC, a Delaware limited liability company (the “Borrower”), and CCH1 MEH Lender LLC, a Delaware limited liability company (the “Lender”).
The Credit Agreement establishes a term loan facility in an aggregate principal amount of $200,000 (the “Credit Facility”). The maturity date of the Credit Facility is March 9, 2031.
On March 9, 2026, the Company borrowed $155,000 under the Credit Facility, and the proceeds were used to repay $146,000 of outstanding principal indebtedness and terminate all commitments under the Second Amended and Restated Credit Agreement, dated as December 18, 2018, as amended, by and among the Company, the Borrower, the lenders from time to time party thereto, Comerica
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Bank, as administrative agent for the lenders, sole lead arranger and sole bookrunner, and the other parties party thereto (the “Prior Credit Facility”).
Term Loan Advances (as defined in the Credit Agreement) under the Credit Agreement bear interest at a rate equal to 10.25%, calculated on the basis of a three hundred and sixty (360) day year and actual days elapsed per annum.
The Borrower is required to repay borrowings under the Credit Facility in quarterly installments in an amount equal to 1.25% of the highest aggregate principal amount of term loans that has been outstanding at any point from the effective date through such payment date, commencing on March 31, 2028. The Borrower may also be required to make mandatory prepayments, in certain circumstances, including in connection with the termination of a Material Project, as more fully provided in the Credit Agreement.
The obligations of the Borrower under the Credit Facility are (i) guaranteed by the Company and each of the Borrower’s existing and future subsidiaries and (ii) secured by first-priority liens on substantially all of the assets of the Company, the Borrower, and the Borrower’s existing and future subsidiaries, in each case subject to certain customary exceptions set forth in the Credit Agreement, including certain excluded subsidiaries.
The Credit Agreement contains customary affirmative and negative covenants including limitations on the ability of the Company, the Borrower, and the Borrower’s existing and future subsidiaries to, amongst other things, grant additional liens, incur additional debt, purchase or otherwise acquire assets or interests of another Person, merge or consolidate, dispose of assets, make restricted payments, make certain investments, engage in certain transactions with affiliates, and enter into certain sale and leaseback transactions, in each case, with certain exceptions carved out, including for the additional debt covenant, the ability to enter into an unsecured revolving credit facility with a bank acceptable to the Lender, which shall include Fifth Third Bank, as successor by merger to Comerica Bank, not to exceed $5,000 at any time outstanding.
The Credit Agreement also requires the Borrower to maintain, as of the end of each fiscal quarter commencing June 30, 2026, (i) a Fixed Charge Coverage Ratio (as defined in the Credit Agreement) of not less than 1.20 to 1.00, (ii) a Total Leverage Ratio (as defined in the Credit Agreement) of not more than 4.00 to 1.00, (iii) minimum Liquidity (as defined in the Credit Agreement) of at least $10,000, and (iv) minimum Consolidated EBITDA (as defined in the Credit Agreement) of at least $10,000. The Credit Agreement includes customary events of default, the occurrence of which could permit the Lender to, amongst other things, declare all amounts owing under the Credit Facility to be immediately due and payable and to exercise remedies with respect to the collateral.
The foregoing summary and description of the Credit Agreement is qualified in its entirety by reference to the full text of the Credit Agreement, a copy of which is filed as Exhibit 10.14 to this Annual Report on Form 10-K and is incorporated herein by reference.
Item 1.02 Termination of a Material Definitive Agreement.
In connection with the Company’s entry into the Credit Agreement, on March 9, 2026, the Company terminated the Prior Credit Agreement, which was scheduled to mature on December 21, 2026. There were no prepayment penalties in connection with the termination of the Prior Credit Agreement.
Item 2.03 Creation of a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement of a Registrant.
The information set forth in Item 1.01 above is incorporated into this Item 2.03 by reference.
ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.
None.
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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding our executive officers is included in Part I of this Report under the header “Information About Our Executive Officers.”
The information otherwise required by this item is set forth in our Proxy Statement in the section entitled “Proposal No. 1—Election of Directors” under the headings “—Nominees for Election for a Term Expiring at the 2029 Annual Meeting,” and “Information Regarding our Board of Directors and Corporate Governance” under the sub-headings “Code of Business Conduct and Ethics,” “Communications with the Board,” “Board Committees,” “Committee Functions,” “Insider Trading/No Hedging and Pledging Policy,” and “Audit Committee” and in the section entitled “Delinquent Section 16(a) Reports.” The information in these sections is incorporated by reference into this Annual Report on Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth in our Proxy Statement under the headings “Proposal No. 1—Election of Directors—Information Regarding our Board of Directors and Corporate Governance—Compensation Committee Interlocks and Insider Participation” and “Executive Compensation” and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Except as set forth herein, the information required by this item is set forth in our Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
As of December 31, 2025, our securities authorized for issuance under equity compensation plans were as follows:
Plan Category |
|
Number of |
|
|
Weighted- |
|
|
Number of |
|
|||
|
|
(a) (1) |
|
|
(b) (2) |
|
|
(c) (3) |
|
|||
Equity compensation plan approved by security |
|
|
3,275,214 |
|
|
$ |
8.30 |
|
|
|
12,826,975 |
|
Equity compensation plan not approved by security |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Total |
|
|
3,275,214 |
|
|
|
8.30 |
|
|
|
12,826,975 |
|
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The information required by this item is set forth in our Proxy Statement under the headings “Proposal No. 1—Election of Directors—Information Regarding the Board of Directors and Corporate Governance—Director Independence and Controlled Company Exemption” and “Certain Relationships and Related Party Transactions” under the subheadings “Certain Transactions” and “Policies and Procedures for Related Party Transactions” and is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item is set forth in our Proxy Statement under the heading “Proposal No. 2—Ratification of the Appointment of Grant Thornton LLP as Independent Auditor” under the subheadings “Principal Accountant Fees and Services” and “Pre-Approval Policies and Procedures” and is incorporated herein by reference.
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PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements
See Part II, Item 8. “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
(a)(2) Financial Statements
Schedules not filed with this Annual Report on Form 10-K are omitted because of the absence of conditions under which they are required or because the information called for is shown in the financial statements or related notes.
(a)(3) Exhibits
Exhibit Number |
|
Description |
|
|
|
2.1.1+ |
|
Transaction Implementation Agreement, dated as of November 6, 2020, between Montauk Renewables, Inc., Montauk Holdings Limited and Montauk Holdings USA, LLC (incorporated by reference to Exhibit 2.1 of our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020) |
|
|
|
2.1.2 |
|
Letter Agreement, dated as of January 3, 2021, to the Transaction Implementation Agreement, dated as of November 6, 2020, between Montauk Renewables, Inc., Montauk Holdings Limited and Montauk Holdings USA, LLC (incorporated by reference to Exhibit 2.2 of Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021) |
|
|
|
2.2.1+ |
|
Membership Interest and Asset Purchase Agreement, dated May 10, 2021, by and among J.P. Carroll & Co., LLC, Eagle Creek Ranch, L.L.C., NR Nutrient Recovery, LLC, Joseph P. Carroll, Jr., Martin A. Redeker and Montauk Swine Ag, LLC (incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K, filed on May 11, 2021) |
|
|
|
2.2.2 |
|
First Amendment to Membership Interest and Asset Purchase Agreement, dated May 26, 2022, by and among J.P. Carroll & Co., LLC, Eagle Creek Ranch, L.L.C., NR3 Nutrient Recovery, LLC, Joseph P. Carroll, Jr., Martin A. Redeker, Montauk Ag Renewables, LLC and Montauk Energy Holdings, LLC (incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K, filed on June 1, 2022) |
|
|
|
2.3+ |
|
Real Estate Purchase and Sale Agreement, dated May 10, 2021, by and among Greensboro Ecosystems, LLC and Montauk Swine Ag, LLC (incorporated by reference to Exhibit 2.2 of our Current Report on Form 8-K, filed on May 11, 2021) |
|
|
|
3.1 |
|
Amended and Restated Certificate of Incorporation of Montauk Renewables, Inc. (incorporated by reference to Exhibit 3.1 of Amendment No. 3 of our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021) |
|
|
|
3.2 |
|
Amended and Restated Bylaws of Montauk Renewables, Inc., as adopted on October 18, 2023 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K, filed October 19, 2023) |
|
|
|
4.1 |
|
Description of Securities (incorporated by reference to Exhibit 4.1 of our Annual Report on Form 10-K, filed March 31, 2021) |
|
|
|
10.1^ |
|
Montauk Renewables, Inc. Equity and Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021) |
|
|
|
10.2^ |
|
Form of Key Employee Separation Plan (incorporated by reference to Exhibit 10.2 of our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020) |
|
|
|
10.3^ |
|
Form of Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.3 of our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020) |
|
|
|
10.4^ |
|
Form of Restricted Stock Unit Award Agreement (Employees) (incorporated by reference to Exhibit 10.4 of our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020) |
|
|
|
10.5^ |
|
Form of Restricted Stock Unit Award Agreement (Non-Employee Directors) (incorporated by reference to Exhibit 10.5 of our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020) |
|
|
|
10.6^+ |
|
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.6 of our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020) |
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Exhibit Number |
|
Description |
|
|
|
10.7^ |
|
Form of Indemnification Agreement between Montauk Renewables, Inc. and each of its directors and executive officers (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, filed June 8, 2021) |
|
|
|
10.8^+ |
|
Employment Agreement, effective September 25, 2019, between Montauk Energy Holdings LLC and Sean F. McClain (incorporated by reference to Exhibit 10.9 to Annual Report on Form 10-K filed March 31, 2021) |
|
|
|
10.9^+ |
|
Employment Agreement, effective September 25, 2019, between Montauk Energy Holdings LLC and Kevin A. Van Asdalan (incorporated by reference to Exhibit 10.10 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020) |
|
|
|
10.10^+ |
|
Employment Agreement, effective September 24, 2019, between Montauk Energy Holdings LLC and James A. Shaw (incorporated by reference to Exhibit 10.11 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020) |
|
|
|
10.11^+ |
|
Employment Agreement, effective June 1, 2020, between Montauk Energy Holdings LLC and John Ciroli (incorporated by reference to Exhibit 10.42 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021) |
|
|
|
10.12^ |
|
Promotion Letter, dated October 15, 2021, between Montauk Renewables, Inc. and Sharon Frank (incorporated by reference to Exhibit 10.12 of Annual Report on Form 10-K filed on March 14, 2024) |
|
|
|
10.13^ |
|
Employment Understanding, dated January 23, 2023, and Promotion Letter, dated September 14, 2023, between Montauk Renewables, Inc. and Michael Barsch (incorporated by reference to Exhibit 10.13 of Annual Report on Form 10-K filed on March 14, 2024) |
|
|
|
10.14+ |
|
Senior Secured Term Loan Credit Agreement, dated as of March 9, 2026, by and among Montauk Renewables, Inc., Montauk Energy Holdings, LLC and CCH1 MEH Lender LLC, as lender |
|
|
|
10.15.1†+ |
|
Second Amended & Restated Landfill Gas Rights & Production Facilities Agreement, by and between County of Orange and Bowerman Power LFG, LLC (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021) |
|
|
|
10.15.2†+ |
|
First Amendment to the Second Amended & Restated Landfill Gas Rights & Production Facilities Agreement, by and between County of Orange and Bowerman Power LFG, LLC (incorporated by reference to Exhibit 10.18 to Amendment No. 2 to our Registration Statement on Form S-1(File No. 333-251312), filed December 31, 2021) |
|
|
|
10.15.3†+ |
|
Third Amendment to the Landfill Gas Rights and Production Facilities Agreement and Settlement Agreement, dated as of June 27, 2023, by and between the County of Orange and Bowerman Power LFG, LLC (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K, filed June 30, 2023) |
|
|
|
10.16+ |
|
Renewable Power Purchase and Sale Agreement by and between the City of Anaheim and Bowerman Power LFG, LLC (incorporated by reference to Exhibit 10.19 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021) |
|
|
|
10.17†+ |
|
Amended and Restated Gas Sale and Purchase Agreement, by and between McCarty Road Landfill TX, LP and GSF Energy, LLC (incorporated by reference to Exhibit 10.20 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021) |
|
|
|
10.18†+ |
|
Third Amended and Restated Gas Lease Agreement, dated January 1, 2018, by and between Rumpke Sanitary Landfill, Inc. and GSF Energy, LLC (incorporated by reference to Exhibit 10.24 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021) |
|
|
|
10.19†+ |
|
Amended and Restated Landfill Gas Purchase and Sale Agreement, dated October 17, 2016, by and between Waste Management of Texas, Inc. and TX LFG Energy, LP (incorporated by reference to Exhibit 10.35 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021) |
|
|
|
10.20 |
|
Fifth Amended and Restated Loan Agreement and Secured Promissory Note, dated as of March 5, 2025 by and between Montauk Holdings Limited and Montauk Renewables (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K, filed on March 7, 2025) |
|
|
|
19.1 |
|
Insider Trading Policy |
|
|
|
21.1 |
|
List of Subsidiaries of Montauk Renewables, Inc. |
|
|
|
23.1 |
|
Consent of Independent Registered Public Accounting Firm |
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Exhibit Number |
|
Description |
|
|
|
24.1 |
|
Power of Attorney |
|
|
|
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 |
|
|
|
97.1 |
|
Clawback Policy (incorporated by reference to Exhibit 97.1 of Annual Report on Form 10-K filed on March 14, 2024) |
|
|
|
99.2+ |
|
Consortium Agreement, dated as of January 24, 2021, by and among the stockholders named therein (incorporated by reference to Exhibit 99.2 of Annual Report on Form 10-K filed March 31, 2021) |
|
|
|
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 |
^ Exhibits marked with a (^) are management contracts or compensation plans or arrangements.
+ Exhibits marked with a (+) exclude certain immaterial schedules and exhibits pursuant to the provisions of Regulation S-K, Item 601(a)(5) or Item 601(a)(6). A copy of any of the omitted schedules and exhibits pursuant to Regulation S-K, Item 601(a)(5) will be furnished to the Securities and Exchange Commission upon request.
† Exhibits marked with a (†) exclude certain portions of the exhibit pursuant to Item 601(b)(10)(iv) of Regulation S-K. A copy of the omitted portions will be furnished to the Securities and Exchange Commission upon request.
ITEM 16. FORM 10-K SUMMARY
None.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
Date: March 11, 2026 |
|
Montauk Renewables, Inc. |
|
|
|
|
|
|
|
By: |
/s/ Sean F. McClain |
|
|
|
Name: Sean F. McClain |
|
|
|
Title: President and Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature |
|
Title |
|
Date |
|
|
|
|
|
|
|
|
|
|
/s/ Sean F. McClain |
|
President, Chief Executive Officer and Director |
|
March 11, 2026 |
Sean F. McClain |
|
(Principal Executive Officer) |
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Kevin A. Van Asdalan |
|
Chief Financial Officer and Treasurer |
|
March 11, 2026 |
Kevin A. Van Asdalan |
|
(Principal Financial and Accounting Officer) |
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Lead Director |
|
March 11, 2026 |
Mohamed H. Ahmed |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Chairman of the Board and Director |
|
March 11, 2026 |
John A. Copelyn |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Director |
|
March 11, 2026 |
Jennifer Cunningham |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Director |
|
March 11, 2026 |
Theventheran G. Govender |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Director |
|
March 11, 2026 |
Yunis Shaik |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* The undersigned, by signing his name hereto, does hereby sign this report on behalf of each of the above named and designated directors of the Company pursuant to Powers of Attorney executed by such persons and filed with the Securities and Exchange Commission.
|
|
|
|
By: |
/s/ Sean F. McClain |
|
Name: Sean F. McClain |
|
Title: Attorney-in-Fact |
FAQ
What does Montauk Renewables (MNTK) primarily do?
How large is Montauk Renewables’ (MNTK) operating portfolio?
What growth strategy does Montauk Renewables (MNTK) highlight?
Which regulatory programs most affect Montauk Renewables (MNTK)?
What key risks does Montauk Renewables (MNTK) identify?
Who are typical customers for Montauk Renewables’ (MNTK) products?
What is the Montauk Ag Renewables project mentioned by MNTK?
