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.
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:
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:
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Regulatory or policy initiatives, including the federal RFS program and state-level low-carbon fuel programs in states such as California and Oregon, that drive demand for RNG and its derivative Environmental Attributes (as further described below).
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Efficiency, mobility and capital cost flexibility in RNG operations enable it to compete successfully in multiple markets. Our operating model is nimble, as we commonly use modular equipment; our RNG processing equipment is more efficient than its fossil-fuel equivalents.
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Demand for compressed natural gas (“CNG”) from natural gas-fueled vehicles. The RNG we create is pipeline-quality and can be used for transportation fuel when converted to CNG. CNG is commonly used by medium-duty fleets that are close to fueling stations, such as city fleets, local delivery trucks and waste haulers.
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Regulatory requirements, market pressure and public relations challenges increase the time, cost and difficulty of permitting new fossil fuel-fired facilities.
Factors Affecting Our Future Operating Results:
Acquisition and Development Pipeline
The timing and extent of our development pipeline affects our operating results due to:
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Impact of Higher Selling, General and Administrative Expenses Prior to the Commencement of a Project’s Operation: We incur significant expenses in the development of new RNG projects.
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Shifts in Revenue Composition for Projects from New Fuel Sources: As we expand into livestock farm projects, our revenue composition from Environmental Attributes will change. We believe that livestock farms offer us a lucrative opportunity, as the value of LCFS credits for dairy farm projects, for example, are a multiple of those realized from landfill projects due to the significantly more attractive CI score of livestock farms.
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Incurrence of Expenses Associated with Pursuing Prospective Projects That Do Not Come to Fruition: We incur expenses to pursue prospective projects with the goal of a site host accepting our proposal or being awarded a project in a competitive bidding process. Historically, we have evaluated opportunities which we decided not to pursue further due to the prospective project not meeting our internal investment thresholds or a lack of success in a competitive bidding process. To the extent we seek to pursue a greater number of projects or bidding for projects becomes more competitive, our expenses may increase.
Regulatory, Environmental and Social Trends
Regulatory, environmental and social factors are key drivers that incentivize the development of RNG and Renewable
Electricity projects and influence the economics of these projects. We are subject to the possibility of legislative and regulatory
changes to certain incentives, such as RINs, RECs and GHG initiatives. On July 12, 2023, the EPA issued final rules in the Federal
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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.
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Renewable Natural Gas Revenues: We record revenues from the production and sale of RNG and the generation and sale of the EnvironmentalAttributes derived from RNG, such as RINs and LCFS credits. Our RNG revenues from Environmental Attributes are recorded net of a portion of Environmental Attributes shared with off-take counterparties as consideration for such counterparties using the RNG as a transportation fuel. We had certain pathway provider sharing arrangements expiring throughout 2024 and 2025. We have entered into pathway renewals in the third quarter of 2025 for certain volumes at percentages consistent with our historical percentages. Historically, we have monetized less than 25% of our RNG volumes under these fixed-price agreements.
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Renewable Electricity Generation Revenues: We record revenues from the production and sale of Renewable Electricity and the generation andsale of the Environmental Attributes, such as RECs, derived from Renewable Electricity. All of our Renewable Electricity production is monetized under fixed-price PPAs from our existing operating projects.
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Corporate Revenues: Corporate reports realized and unrealized gains or losses under our gas hedge programs. We do not have any active gas hedge programs. Corporate also relates to additionaldiscrete financial information for the corporate function; primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering and other operations functions not otherwise allocated to a segment. Revenues from RINs distributed from GreenWave, not included in our operating metrics table.
Our operating revenues are priced based on published index prices which can be influenced by factors outside our control, such as market impacts on commodity pricing and regulatory developments. With our royalty payments structured as a percentage of revenue, royalty payments fluctuate with changes in revenues. We place a primary focus on managing production volumes and operating and maintenance expenses as these factors are more controllable by us.
RNG Production
Our RNG production levels are subject to fluctuations based on numerous factors, including:
Disruptions to Production: Disruptions to waste placement operations at our active landfill sites, severe weather events, or failure or degradation ofour 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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In 2024, we began to experience trends with several of our landfill hosts delaying their installation of or delaying our ability to install wellfield collection infrastructure in active waste placement areas, a practice historically common and critical to our projections of feedstock gas and, therefore, production. These landfill-driven delays impact the timing of collection system enhancement installations and the resulting timing of our production increases. We expect these trends to continue throughout 2026.
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Similar wellfield extraction environmental factors continue to impact gas extraction at our Apex site. We are collaborating with the landfill to mitigate these impacts and these mitigation efforts have continued in 2025. These wellfield extraction environmental factors could impact and lengthen the period during which we have excess available combined production capacity at our Apex site.
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Changes made by the landfill host to the wellfield collection system at the McCarty facility have contributed to elevated nitrogen in the feedstock received by our facility. Additionally, the landfill host modified the wellfield bifurcation approach which has reduced the quantity of feedstock received at our facility. We are working with the landfill host but continue to have lower volumes of feedstock available to be processed at the McCarty facility. We expect these trends to continue through 2026.
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Quality of Biogas: We are reliant upon the quality and availability of biogas from our site partners. The quality of the waste at our landfill projectsites is subject to change based on the volume and type of waste accepted. Variations in the quality of the biogas could affect our RNG production levels. At three of our projects, we operate the wellfield collection system, which allows greater control over the quality and consistency of the collected biogas. At our McCarty projects, we have operating and management agreements by which we earn revenue for managing the wellfield collection systems. Additionally, our dairy farm project benefits from the consistency of feedstock and controlled environment of collection of waste to improve biogas quality.
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RNG Production from Our Growth Projects: We anticipate increased production at certain of our existing projects as open landfills continue totake in additional waste and the amount of gas available for collection increases. Delays in commencement of production or extended commissioning issues at a new project or a conversion project, such as those
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we are currently experiencing at Blue Granite as described above, would delay any realization of production from that project.
Pricing
Our Renewable Natural Gas and Renewable Electricity Generation segments’ revenues are primarily driven by the prices under our off-take agreements and PPAs and the amount of RNG and Renewable Electricity that we produce. We sell the RNG produced from our projects under a variety of short-term and medium-term agreements to counterparties, with contract terms varying from three years to five years. Our contracts with counterparties are typically structured to be based on varying natural gas price indices for the RNG produced. All of the Renewable Electricity produced at our biogas-to-electricity projects is sold under long-term contracts to creditworthy counterparties, typically under a fixed price arrangement with escalators.
The pricing of Environmental Attributes, which accounts for a substantial portion of our revenues, is subject to volatility based on a variety of factors, including regulatory and administrative actions and commodity pricing.
The sale of RINs, which is subject to market price fluctuations, accounts for a substantial portion of our revenues. We manage against the risk of these fluctuations through forward sales of RINs, although currently we only sell RINs in the calendar year they are generated. We have 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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Operating and Maintenance Expenses: Operating and maintenance expenses primarily consist of expenses related to the collection and processing of biogas, including biogas collection system operating and maintenance expenses, biogas processing, operating and maintenance expenses, and related labor and overhead expenses. At the project level, this includes all labor and benefit costs, ongoing corrective and proactive maintenance, project level utility charges, rent, health and safety, employee communication, and other general project level expenses. Unanticipated feedstock processing or gas conditioning equipment failures occurring outside our planned preventative maintenance program can increase project operating and maintenance expenses and reduce production volumes. The timing of gas conditioning and process equipment preventative maintenance intervals could impact the timing and amount of our operating and maintenance expenses within a given quarter. Expenses from RINs distributed from GreenWave and the costs related to pathway dispensing are not included in our operating metrics table.
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Royalties, Transportation, Gathering and Production Fuel Expenses: Royalties represent payments made to our facility hosts, typically structuredas a percentage of revenue. Transportation and gathering expenses include capacity and metering expenses representing the costs of delivering our RNG and Renewable Electricity production to our customers. These expenses include payments to pipeline operators and other agencies that allow for the transmission of our gas and electricity commodities to end users. Production fuel expenses generally represent alternative royalty payments based on quantity usage of biogas feedstock.
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General and Administrative Expenses: General and administrative expenses primarily consist of corporate expenses and unallocated support functions for our operating facilities, including personnel costs for executive, finance, accounting, investor relations, legal, human resources, operations, engineering, environmental registration and reporting, health and safety, IT and other administrative personnel and professional fees and general corporate expenses. From time to time, we may be parties to legal proceedings arising in the normal course of business which could increase our legal expenses. We continue to see increased general and administrative expenses associated with our ongoing development of Montauk Ag Renewables in 2025. We account for share-based compensation related to grants made through our equity and incentive compensation plan under FASB ASC 718. In 2025, we recognized $1,550 of onetime non-cash stock compensation expense within general and administration expenses as a result of the termination which we do not anticipate will recur in 2026. For more information, see Note 15 to our audited consolidated financial statements.
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Depreciation, Depletion and Amortization: Expenses related to the recognition of the useful lives of our intangible and fixed assets. We spend significantcapital to build and own our facilities. In addition to development capital, we annually reinvest to maintain these facilities.
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Impairment Loss: Expenses related to reductions in the carrying value(s) of fixed and/or intangible assets based on periodic evaluations wheneverevents or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
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Transaction Costs: Transaction costs primarily consist of expenses incurred for due diligence and other activities related to potential acquisitionsand other strategic transactions.
Key Operating Metrics
Total operating revenues reflect both sales of renewable energy and sales of related Environmental Attributes. As a result, our revenues are primarily affected by unit production of RNG and Renewable Electricity, production of Environmental Attributes, and the prices at which we monetize such production. Set forth below is an overview of these key metrics:
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Production Volumes: We review performance by site based on unit of production calculations for RNG and Renewable Electricity, measured interms of MMBtu and MWh, respectively. While unit of production measurements can be influenced by schedule facility maintenance schedules, the metric is used to measure the efficiency of operations and the impact of optimization improvement initiatives. We monetize a majority of our RNG commodity production under variable-price agreements, based on indices. A portion of our Renewable Natural Gas segment commodity production is monetized under fixed-priced contracts. Our Renewable Electricity Generation segment commodity production is primarily monetized under fixed-priced PPAs.
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Production of Environmental Attributes: We monetize Environmental Attributes derived from our production of RNG and Renewable Electricity.We may carry-over a portion of the RINs generated from RNG production to the following year and monetize the carried over RINs in such following calendar year. A majority of our Renewable Natural Gas segment Environmental Attributes are self-monetized. A majority of our Renewable Electricity Generation segment Environmental Attributes are monetized as a component of our fixed-price PPAs.
•
Average realized price per unit of production: Our profitability is highly dependent on the commodity prices for natural gas and electricity, and theEnvironmental Attribute prices for RINs, LCFS credits, and RECs. Realized prices for Environmental Attributes monetized in a year may not correspond directly with that year’s production as attributes may be carried over and subsequently monetized. We may elect to not commit to transfer all available RINs in a given period which could impact our revenue and operating profit. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.
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Comparison of 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 December 31, Change
(in thousands, unless otherwise indicated)
Revenues
RNG Metrics
Total RNG volumes available for RIN generation (1) 3,674 4,108 (434 ) (10.6 %)
RIN Metrics
Less: RINs generated but unseparated (190 ) — (190 ) 0.0 %
Less: CY RINs carried into next CY — (6,822 ) 6,822 (100.0 %)
RIN Inventory — — — 0.0 %
RNG Inventory (volumes not dispensed for RINs) (4) 354 291 63 21.6 %
Operating Expenses
Operating Expenses per MMBtu (actual) $ 15.96 $ 14.84 $ 1.12 7.5 %
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 %
(1)
RINs are generated in the month that the gas is dispensed to generate RINs, which occurs the month after the gas is produced. Volumes under fixed/floor-price arrangements generate RINs which we do not self-market. K3 RIN separation occurs after the gas is dispensed (RINs generated but unseparated).
(2)
One MMBtu of RNG has the same energy content as 11.6935 gallons of ethanol, and thus may generate 11.6935 RINs under the RFS program.
(3)
Represents RINs available to be self-marketed by us during the reporting period.
(4)
Represents gas production on which RINs are not generated.
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 December 31, Change
Operating expenses:
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 December 31,
Depreciation, depletion and amortization 29,972 23,515
Income tax (benefit) expense (4,235 ) 2,443
Net loss on sale of assets 36 —
Transaction costs — 61
(1)
For the year ended December 31, 2025, we recorded impairments of $3,231 for costs related to a development project RNG interconnection for which the local utility is no longer accepting RNG into its distribution system, identified assets deemed obsolete or non-operable. For the year ended December 31, 2024, we recorded impairments of $1,586 for specifically related 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.
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:
Revolving credit facility 85,000 —
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:
•
a Total Net Leverage Ratio (as defined in the Amended Credit Agreement) of not more than 3.50 to 1.00 as of the end December 31, 2025; stepping down to 3.00 to 1.00 on March 31, 2026 and thereafter; and
•
as of the end of each fiscal quarter, a Fixed Charge Coverage Ratio (as defined in the Amended Credit Agreement) of not less than 1.2 to 1.0.
•
requires that MEH provide additional financial information and analysis to the lenders within fifteen business days of the end of each month
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:
•
Total Net Leverage Ratio of not more than 4.00 to 1.00,
•
As of the end of each fiscal quarter, a Fixed Charge Coverage Ratio of not less than 1.20 to 1.00, and
•
Various other financial covenants or mandatory prepayments .
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 December 31,
Net cash provided by (used in):
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.
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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 248) 57
Consolidated Balance Sheets as of December 31, 2025 and 2024 58
Notes to Consolidated Financial Statements 63
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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/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2007.
Pittsburgh, Pennsylvania
March 11, 2026
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MONTAUK RENEWABLES, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data)
as of December 31,
Current assets:
Accounts and other receivables 9,167 8,172
Current restricted cash 8 8
Income tax receivable 702 41
Current portion of derivative instruments 220 471
Prepaid insurance and other current assets 3,306 2,911
Non-current restricted cash $ 430 $ 375
Non-current portion of derivative instruments — 298
Operating lease right-of-use assets 9,082 7,064
Finance lease right-of-use assets 39 110
Equity method investment 3,824 —
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Related party payable — 625
Current portion of operating lease liability 3,287 2,049
Current portion of finance lease liability 32 76
Current portion of long-term debt 2,733 11,853
Non-current portion of operating lease liability 5,880 5,138
Non-current portion of finance lease liability 8 36
Commitments and contingencies (Note 20)
STOCKHOLDERS’ EQUITY
Total liabilities and stockholders' equity $ 435,460 $ 349,015
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 OPERATIONS
For The Year Ended December 31,
Operating expenses:
Royalties, transportation, gathering and production fuel 32,945 31,502 34,861
Transaction costs — 61 178
Other expenses (income):
Income from equity investment (1,485 ) — —
Income per share:
Weighted-average common shares outstanding:
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 STOCKHOLDERS’ EQUITY
Common stock Treasury stock
Vesting of stock awards 352,772 4 — — — — 4
Stock-based compensation — — — — 8,318 — 8,318
Vesting of stock awards 725,608 6 — — — — 6
Consolidation of VIE — — — — (2,432 ) — (2,432 )
Stock-based compensation — — — — 9,959 — 9,959
Vesting of stock awards 532,747 5 — — — — 5
Consolidation of VIE — — — — (47 ) — (47 )
Stock-based compensation — — — — 4,444 — 4,444
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
(in thousands): For The Year Ended December 31,
Cash flows from operating activities:
(Benefit) provision for deferred income taxes (4,278 ) 804 1,876
Derivative mark-to-market adjustments and settlements 549 486 560
Net loss on disposal of assets 36 — 94
(Decrease) increase in earn-out liability 594 (1,703 ) 1,266
Accretion of asset retirement obligations 485 445 407
Liabilities associated with properties sold — (225 ) —
Amortization of debt issuance costs 391 360 367
Non cash expense - RINs sold from equity method investment 1,661 — —
Income from equity method investment (1,485 ) — —
Cash provided (used) by changes in assets and labilities:
Royalty offset long term receivable (4,595 ) (3,089 ) (3,515 )
Income tax receivable (661 ) (354 ) (89 )
Accounts payable and Accrued liabilities 735 (2,298 ) 1,326
Cash flows from investing activities:
Asset acquisition — (820 ) —
Capital contributions to equity method investments (4,000 ) — —
Cash collateral deposits 55 (48 ) 2
Proceeds from sale of assets — 1,000 2
Cash flows from financing activities:
Borrowings on revolver 105,000 — —
Repayments on revolver (20,000 ) — —
Contingent consideration payments (4,176 ) — —
Common stock issuance 5 6 4
Related party receivable — — (1,138 )
Finance lease payments (71 ) (68 ) (74 )
Net cash provided (used) in financing activities $ 68,339 $ (9,842 ) $ (9,330 )
Reconciliation of cash, cash equivalents, and restricted cash at end of period:
Restricted cash and cash equivalents - current 8 8 8
Restricted cash and cash equivalents - non-current 430 375 423
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,
Supplemental cash flow information:
Non-cash purchase of Treasury stock — 8,309 —
Non-cash RIN distribution from equity method investment 1,661 — —
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 30 years of experience in the development, operation and management of landfill methane-fueled renewable energy projects. The Company has current operations at 13 operating projects located in California, Idaho, Ohio, Oklahoma, Pennsylvania, North Carolina and Texas. The Company sells RNG and Renewable Electricity, taking advantage of Environmental Attribute premiums available under federal and state policies that incentivize their use.
Two of the Company’s key revenue drivers are sales of captured gas and sales of Renewable Identification Numbers (“RINs”) to fuel blenders. The Renewable Fuel Standard (“RFS”) is an Environmental Protection Agency (“EPA”) administered federal law that requires transportation fuel to contain a minimum volume of renewable fuel. RNG derived from landfill methane, agricultural digesters and wastewater treatment facilities used as a vehicle fuel qualifies as a D3 (cellulosic biofuel with a 60% greenhouse gas reduction requirement) RIN. The RINs are compliance units for fuel blenders that were created by the RFS program in order to reduce greenhouse gases and imported petroleum into the United States.
An additional program utilized by the Company is the Low Carbon Fuel Standard (“LCFS”). This is state specific and is designed to stimulate the use of low-carbon fuels. To the extent that RNG from the Company’s facilities is used as a transportation fuel in states that have adopted an LCFS program, it is eligible to receive an Environmental Attribute additional to the RIN value under the federal RFS.
Another key revenue driver is the sale of captured electricity and the associated environmental premiums related to renewable sales. The Company’s electric facilities are designed to conform to and monetize various state renewable portfolio standards requiring a percentage of the electricity produced in that state to come from a renewable resource. Such premiums are in the form of Renewable Energy Credits (“RECs”). The Company’s largest electric facility, located in California, receives revenue for the monetization of RECs as a part of a purchase power agreement.
Collectively, the Company benefits from federal and state government incentives in the United States, provided in the form of RINs, RECs, LCFS credits, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects, that promote the use of renewable energy, as Environmental Attributes.
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 2,702,500 shares at $8.50 per share and received gross proceeds of $22,971. The Company’s common stock was also secondarily listed on the Johannesburg Stock Exchange (“JSE”) under the trading symbol “MKR”.
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 $10,690 in the aggregate (2) extended the maturity date to December 31, 2033 also, in accordance with Montauk Renewables’ obligations set forth in the Transaction Implementation Agreement ("TIA"). This loan became due on December 31, 2024 (“Maturity Date”) when MNK and RP47 did not extend the maturity of the loan agreement. Associated with a modification on December 31, 2024 of the TIA between us and MNK, we became obligated to repay the RP47 Loan on MNK’s behalf as MNK did not have sufficient funds to repay the RP47 Loan. On February 2, 2025, our Board of Directors approved the repayment of the RP47 Loan under the TIA. On March 5, 2025 and in connection with the Fifth Amended and Restated Loan Agreement and Secured Promissory Note", the Company repaid the RP47 loan as required under the TIA. In connection with the modification under the TIA, RP47 retained its power over MNK but no longer held significant benefits in MNK. Substantially all of MNK’s activities are conducted on our behalf as MNK’s only asset is the 976,623 shares of our common stock held as security for the Fifth Amended and Restated Loan Agreement and Secured Promissory Note. MNK’s only obligation was its loan to us and thus, we became the primary beneficiary of MNK on December 31, 2024. The Fifth Amended Promissory Note became an intercompany loan and was eliminated in consolidation. MNK’s investment of $10,178 in the Company was also eliminated in consolidation. There was no gain or loss on the initial consolidation of MNK as the transaction was 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. MNK is currently an affiliate of the Company and certain of the Company’s directors are also directors of MNK. See Note 17 for more information.
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.
The Company utilizes the equity method of accounting for companies where its ownership is greater than 50% and significant but controlling interest does not exist.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These
reclassifications had no effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash
flows.
Segment Reporting
The Company reports segment information in two segments: RNG and Renewable Electricity Generation. This is consistent with the internal reporting provided to the chief operating decision maker who evaluates operating results and performance. The aforementioned business services and offerings described in Note 1 are defined by management as two distinct operating segments: RNG and Renewable Electricity Generation. Below is a description of the Company’s operating segments and other activities.
The RNG segment represents the sale of gas sold at fixed-price contracts, counterparty share RNG volumes and applicable Environmental Attributes. This business unit represents the majority of the revenues generated by the Company. The Renewable
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Electricity Generation segment represents the sale of captured electricity and applicable Environmental Attributes. Corporate & Other relates to additional discrete financial information for the corporate function. It is primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering and other operations functions not otherwise allocated to a segment. As such, the corporate entity is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation to the Company’s consolidated financial statements.
Use of Estimates
The preparation of financial statements, in conformity with accounting principles generally accepted in the United States (“GAAP”), requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash, Cash Equivalents and Restricted Cash
Cash and cash equivalents include highly liquid investments with maturity dates of three months or less from the date of purchase and are recorded at cost. The Company may hold cash in excess of federally insured limits. Restricted cash is classified as current or non-current based on the terms of the underlying agreements and represents cash held as deposits, cash held in escrow and cash collateral for financial letters of credit.
Accounts and Other Receivables
Accounts and other receivables on the Consolidated Balance Sheets represent outstanding billings for goods and services delivered to customers on an unsecured basis as well as reimbursable expenses. In evaluating its allowance for doubtful accounts for accounts receivable, the Company performs ongoing reviews of its outstanding receivables to determine if any amounts are uncollectible and adjusts the allowance for doubtful accounts accordingly.
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 5 - 30 years
Machinery and equipment 1 - 43 years
Gas mineral rights 15 - 25 years
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 10 - 25 years
Customer contracts 2 - 15 years
Emissions allowances Indefinite
Land use rights Indefinite
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
The Company applies the provisions of ASC 815, Derivatives and Hedging, (“ASC 815”). ASC 815 requires each derivative instrument to be recorded in the Consolidated Balance Sheets at its fair value. Changes in a derivative instrument’s fair value are recognized currently in earnings.
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 zero and 6.8 million RINs generated and unsold as of December 31, 2025 and 2024, respectively.
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 $3,231, $1,586 and $902 in impairment losses for the years ended December 31, 2025, 2024 and 2023, respectively. In 2025, $2,676 was impaired for costs related to an RNG development project for which the local utility is no longer accepting RNG into its distribution system. All associated costs other than a gas rights development payment related to the project were impaired. The remaining 2025 impairments of $555 were for specifically identified assets deemed obsolete or non-operable and consisted of $432 within the RNG segment, $120 within the REG segment and $3 within the Corporate segment. In 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 $1,000 in proceeds. The effective date of the sale, assignment and assumption agreement was October 1, 2024. The Company elected to cease operations prior to the assignment date and consequently the remaining book value of long lived assets and intangibles were impaired for $312. The $1,000 in proceeds received was recognized as Other income in the Consolidated Statement of Operations. In addition, $329 in REG impaired assets were due to initial startup testing failures for one of its REG construction work in progress sites. Remaining 2024 impairments, $843 in RNG assets and $102 in REG assets, were for various equipment that was deemed obsolete or inoperable for current operations. 2023 impairments included $777 for specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use and recorded in the Company's RNG segment. The remaining $125 in impairments were for specifically identified obsolete REG critical spares.
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 33%, 26% and 24% of revenue for the years ended December 31, 2025, 2024 and 2023, respectively.
The Company’s performance obligations related to the sale of Environmental Attributes are generally satisfied at a point in time and were 67%, 74% and 76% of revenue for the years ended December 31, 2025, 2024 and 2023, respectively. The Company recognizes Environmental Attribute revenue at the point in time in which the customer obtains control of the Environmental Attributes, which is generally when the title of the Environmental Attribute passes to the customer upon delivery. In limited cases, title does not transfer to the customer and revenue is not recognized until the customer has accepted the Environmental Attributes.
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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:
Goods transferred at a point in time Goods transferred over time Total
Major goods/Service line:
Electric environmental attributes 7,466 — 7,466
Operating segment:
Goods transferred at a point in time Goods transferred over time Total
Major goods/Service line:
Electric environmental attributes 7,586 — 7,586
Operating segment: