MNTK 10-K & 10-Q changes, risk factors and insider trading

Landfills contain organic material whose decomposition causes the generation of gas consisting primarily of methane, which our RNG projects use to generate power or renewable natural gas, and carbon dioxide. The estimation of landfill gas production volume is an inexact process and dependent on many site-specific conditions, including the estimated annual waste volume, composition of waste, regional climate and the capacity and construction of the landfill. Production levels are subject to a number of additional risks, including a failure or wearing out of our or our landfill operators’, customers’ or utilities’ equipment; an inability to find suitable replacement equipment or parts; less than expected supply or quality of the project’s source of biogas and faster than expected diminishment of such biogas supply; or volume disruption in our fuel supply collection system. Any extended interruption and/or volume disruption in the project’s operation, or failure of the project for any reason to generate the expected amount of output, could adversely affect our business and operating results. For example, certain of our Houston-based operating sites were impacted by severe weather events during the first nine month of 2024 including multiple day extended outages from Hurricane Beryl in July 2024. Furthermore, we produced fewer MMBTuMMBtu and MWh in the third quarter of 2023 compared with the third quarter of 2022 due to dry weather conditions and higher ambient temperatures. In addition, we have in the past, and may in the future, incur material asset impairment charges if any of our renewable energy projects incurshas operational issues that indicate our expected future cash flows from the project are less than the project’s carrying value. Any such impairment charge could adversely affect our operating results in the period in which the charge is recorded.

In addition, in order to maximize collection of LFG, we will need to take various measures, such as drilling additional gas wells in the landfill to increase LFG collection, balancing the pressure on the gas field based on the data collected by the landfill operator from the gas wells to ensure optimum landfill gas utilization and ensuring that we match availability of engines and related equipment to availability of LFG. There can be no guarantee that we will be able to take all necessary measures to maximize collection. For example, we do not operate the wellfields at all sites. In addition, the LFG available to our projects is dependent in part on the actions of other persons, such as landfill operators. We may not be able to ensure the responsible management of the landfill site by owners and operators,operators whichor maythere could be a change in operations and maintenance providers that results in less effective operations. This could result in less than optimalless-than-optimal gas generation or increase the likelihood of “hot spots” occurring. Hot spots can temporarily reduce the volume of gas which may be collected from a landfill site, resulting in a lower gas yield. Landfill owner negligence such as covering gas wells with landfill material and breaking gas lines could also result in decreased output. Other events that can result in a reduction in LFG output include: extreme hot or cold temperatures or drought or excessive rainfall; liquid levels within a landfill increasing; oxidation within a landfill, which can kill the anaerobic microbes that produce landfill gas; and the buildup of sludge. The occurrence of thesesludge or anyinorganic othermaterials changes(such withinas anyconstruction ofmaterials) thethat landfillsdo wherenot ourproduce projectsgases operateas couldthey lead to a reduction in the amount of LFG available to operate our projects, which could have a material adverse effect on our business, financial condition and results of operations.decompose.

A substantial portion of our revenues are generated from five project sites. For the years ended December 31, 20242025 and 2023,2024, excluding the effect of derivative instruments, approximately 69.1%67.7% and 68.4%,69.1%, respectively, of operating revenues were derived from these locations. During 2024,2025, RNG production at our Rumpke, Atascocita, Rumpke, McCarty and GalvestonApex facilities accounted for approximately 20.7%, 20.3%, 18.9%, 16.4%16.0% and 11.0%7.7% of our RNG revenues, respectively, and 18.7%,20.7%, 21.4%,20.3%, 15.0%16.0% and 8.7%7.7% of the RNG we produced, respectively. During 2024,2025, Renewable Electricity production at our Bowerman Power LFG, LLC (“Bowerman”) facility accounted for approximately 92.2%94.9% of our Renewable Electricity Generation revenues and 82.6%85.5% of the Renewable Electricity we produced during 2024.2025. A lengthy interruption of production or transmission of renewable energy from one or more of these projects, asdue a result ofto a severe weather event, failure or degradation of our or a landfill operator’s equipment or interconnection transmission problems could have a disproportionate effect on our revenues and cash flow.

Our Atascocita, McCarty, Galveston and Coastal Plains projects are located within 20 miles of each other near Houston, Texas and six of our other RNG projects are located in relatively close proximity to each other in Pennsylvania and Ohio. Regional events, such as gas transmission interruptions, regional availability of replacement parts and service in the event of equipment failures and severe weather events in either of those geographic regions have previously adversely affected, and if the future could adversely affect, our RNG production and transmission. These impacts are greater than would be if our business was more geographically diverse.

We have insurance policies covering certain risks associated with our business. Our insurance policies do not, however, cover all losses, including, in some situations, those as a resultbecause of force majeure, which is generally defined as events that are beyond the control of the parties. For example, we did not receive any insurance recovery from the shutdowns in Houston in February 2021 due to the extreme cold or from the Bowerman shutdown in October 2020 due to wildfires. Even if insurance policies for some of our projects cover losses as a result of certain types of force majeure events, such coverage is subject to important limitations. Furthermore, insurance liabilities are difficult to assess and quantify due to unknown factors, including the severity of an injury, the determination of our liability in proportion to other parties, the number of incidents not reported and the effectiveness of our safety program. Insurance coverage is not always available on commercially reasonable terms (if at all) and is often capped at predetermined limits. In addition, our insurance policies are subject to annual review by our insurers and may not be renewed on similar or favorable terms or at all. A serious uninsured loss or a loss significantly exceeding the limits of our insurance policies could adversely affect our business, financial condition and results of operations.

Our success will dependdepends on our ability to create and maintain a competitive position in the renewable energy industry. Other than the patented technology acquired through the Montauk Ag Renewables Acquisition, our internally developed condensate neutralization technology and an RNG processing skid we developed, weWe do not have any exclusive rights to anymany of the technologies that we utilize, and our competitors may currently use and may be planning to use identical, similar or superior technologies. While significant to the development associated with our emerging North Carolina Montauk Ag Renewables business, we do not currently consider patented technology material to the total business. In addition, theour technologies thatmay weultimately useprove ineffective, may be hampered by frequent mechanical breakdowns, or rendered obsolete or uneconomical by technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of our competitors or others.

We may also face competition based on technological developments that reduce demand for electricity, increase power supplies through existing infrastructure or that otherwise compete with our projects. We also encounter competition in the form of potential customers electing to develop solutions or perform services internally rather than engaging an outside provider such as us.

Our projects generally are, and any of our future projects are likely to be, located on land occupied pursuant to long-term easements, leases and rights of way. The ownership interests in the land subject to these easements, leases and rights-of-way may be subject to mortgages securing loans or other liens (such as tax liens) and other easement,easements, lease rights and rights-of-way of third parties (such as leases of oil or mineral rights) that were created prior to our projects’ easements, leases and rights-of-way. As a result, certain of our projects’ rights under these easements, leases or rights-of-way may be subject, and subordinate, to the rights of those third parties. In the future, our existing projects may need new easements or rights-of-way and there is no guaranty that we will be able to secure these. For example, our Shade facility in Johnstown needs a change in the easement due to road construction. We may not be able to protect our operating projects against all risks of loss of our rights to use the land on which our projects are located, and any such loss or curtailment of our rights to use the land on which our projects are located and any increase in rent due on such lands could adversely affect our business, financial condition and results of operations.

We aim to maintain and grow our position as a leading producer of RNG in the United States. Our specific focus on the renewable energy sector exposes us to risks related to the supply of, demand for and the ultimate price of energy commodities and Environmental Attributes, inflation, taxes, tariffs, dutiesduties, or other assessments on necessary equipment, the cost of capital expenditures, government regulation, world and regional events and economic conditions, labor market conditions and the acceptance of alternative power sources. As a renewable energy producer, we may also be negatively affected by lower energy output resulting from variable inputs, mechanical breakdowns, faulty technology, competitive electricity markets or changes to the laws and regulations that mandate the use of renewable energy sources by refiners and importers of gasoline and diesel fuel and electric utilities.

regulatory changes,changes whetherand asstatements aand resultpolicies of the newcurrent presidential administration orthat otherwise,make thatit more difficult and expensive for us to borrow and raise capital, reduce investment in the infrastructure we rely on and affect the demand for orand supply of our RNG, REG, and the Environmental Attributes and the prices thereof, which could have a significant effect on the financial performance of our projects and the number of potential projects with attractive economics;

substantial construction risks, including the risk of delay,delay that may arise due to forces outside of our control, including those related to reduced parts supply, delays in parts supply, increased costs of parts, engineering and environmental problems, aslabor ashortages resultand ofdisruptions inclementand adverse weather or labor disruptionsconditions;

a decrease in the availability and timeliness of delivery of raw materials and components necessary for the projects to functiondevelop and function, such as our collaboration with European Energy which relies on parts from Denmark, or an increase in the costs of raw materials and components due to, among other reasons, inflation, tariffs, duties, taxes or assessments;

penalties, including potential termination, under short-term and long-term contracts for failing to deliver RNGRNG, RECs, or REG in accordance with our contractual obligations;

unknown regulatory changes with respect to RECs, RINs, REG, or RNG which may increase the transportation cost for delivering under contracts in place;

In addition, new projects have no operating history and may employ recently developed technology and equipment. The technology may not be successful or our use of intellectual property may be challenged for infringement. A new project may be unable to fund principal and interest payments under its debt service obligations or may operate at a loss, which may adversely affect our business, financial condition or results of operations. This may also make it more difficult to obtain capital for new projects.

If there is not sufficient demand for renewable energy, or the associated Environmental Attributes, or if renewable energy projects do not develop or take longer to develop than we anticipate, we may be unable to achieve our investment objectives.

If demand for renewable energy or Environmental Attributes fails to grow sufficiently, we may be unable to achieve our business objectives. In addition, demand for renewable energy projects and Environmental Attributes in the markets and geographic regions that we target may not develop or may develop more slowly than we anticipate. Many factors will influence the widespread adoption of renewable energy and demand for renewable energy projects, including:

We plan to expand our business in part through developing RNG recovery projects at landfills and livestock farms, including our Turkey, North Carolina location, but we may not be able to identify suitable locations or complete development of new projects.successful.

We plan to continue to develop new RNG projects at landfills and livestock farms but we may be unable to implement this growth strategystrategy. ifWe wemay cannotnot be able to identify suitable landfills and livestock farms on which to develop projects, reach agreements with landfill or livestock farm owners to develop RNG projects or arrange required financing for new projects. While the EPA has identified an additional 463444 landfills as candidates for biogas projects, we believe that approximately 3832 of these sites produce sufficient quantities of LFG to support commercial-scale projects, with 2524 of the approximately 3832 sites being operated by Waste Management or Republic Waste, with whom we would need to negotiate with to secure sufficient LFG rights to support an RNG project. In the future, additional candidate landfills may become economically viable as their growth increases LFG production and requires installation of LFG collection systems. However, the time and effort involved in attempting to identify suitable sites and development of new projects may divert members of our management from our operations.

Our Pico dairy farm project produces significantly less RNG than our landfill facilities. As a result, we will beare even more dependent on the LCFS credits and RINs produced at our dairy farm project than on the RINs produced at our landfill facilities for the project’s commercial viability. InAs a result of the event2025 thatAFPR CARBreview, worsens theour CI score thatworsened. itThe worsening CI score is primarily due to increased biogas upgrading and fugitive emissions from the biogas upgrading process. We are currently conducting an analysis to determine the benefit of installing a combustion device to eliminate fugitive emissions. As a result of this, we may be subject to a claw back of LCFS credits related to the overgeneration of LCFS credits using the old CI Score. While we do not believe the penalty applies to wasteus, conversionthe projects,legislation suchdoes allow for a penalty of four times the number of LCFS credits to be taken away from a producer as dairya digesters,penalty if its score is lowered. As a result, the number of LCFS credits for RNG generated at our dairy farm project will decline. Additionally, revenue from LCFS credits also depends on the price per LCFS credit, which is driven by various market forces, including the supply of and demand for LCFS credits, which in turn depends on the demand for traditional transportation fuel and the supply of renewable fuel from other renewable energy sources, and mandated CI targets, which determine the number of LCFS credits required to offset LCFS deficits, and which increase over time. Fluctuations in the price of LCFS credits or the number of LCFS credits assigned will have a significantly greater impact on the success of our dairy farm project than the value that RINs have on our landfill facilities. A significant decline in the value of LCFS credits could require us to incur an impairment charge on our dairy farm project and could adversely affect our business, financial condition and results of operations.

Our business is currently focused on converting methane into renewable energy. In the future, we may expand our strategy to include other types of projects. For example, we have entered into an agreement with European Energy North America under which we supply biogenic carbon dioxide for the creation of e-methanol and have announced a pilot project with Emvolon in which we will recover and convert biogas into green methanol. We cannot assure you that we will be able to identify attractive opportunities outside of our current area of focus or acquire or develop such projects at a price and on terms that are attractive or that, once acquired or developed, such projects will operate profitably. Risks include a lack of supply offtake, lower than expected prices for generated supplies, malfunctioning equipment, unsuccessful new technologies, and intellectual property challenges. In addition, these projects could expose us to increased operating costs, unforeseen liabilities or risks, and regulatory and environmental concerns associated with entering into new sectors of the energy industry, including requiring a disproportionate amount of our management’s attention and resources, which could adversely affect our business, as well as place us at a competitive disadvantage relative to more established market participants. A failure to successfully integrate such new projects into our existing project portfolio as a result of unforeseen operational difficulties or otherwise, could adversely affect our business, financial condition and results of operations.

OurThe profitability of our renewable fuel projects may be exposedlimited by our ability to dispense fuel to separate RINs and the volatility of the price of RINs.

TheFurthermore, the price of RINsEnvironmental Attributes, including RINs, is driven by various market forces, including regulatory action, gasoline prices and the availability of renewable fuel from other renewable energy sources and conventional energy sources. For example, following the EPAsEPA’s releaseissuance of theannual 2023Renewable RVOVolume Obligations in Decemberrecent 2022, theyears, market priceprices offor a D3certain RIN declinedcategories fromhave $2.43experienced onsignificant thevolatility datein of the releaseresponse to $1.88changes in Februarymandated 2023.volumes, Furthermore,compliance flexibility, and market expectations. In addition, refiners are permitted to carry-overcarry over up to 20% of RINs generated for one calendar year after the RINs are generated to satisfy their RVOs.RVOs for the following year. As a result, we are generally only able to sell RINs on a forward basis for the year in which the RINs are generated and the followingsubsequent year. We may be unable to manage the risk of volatility in RIN pricing for all or a portion of our revenues from RINs, which would expose us to the volatility of commodity prices with respect to all or the portion of RINs that we are unable to sell through forward contracts, including risks resulting from changes in regulations, general economic conditions and changes in the level of renewable energy generation. We expect to have quarterly variations in the revenues from the projects in which we generate revenue from the sale of RINs that we are unable to sell through forward contracts.

The operations and financial performance of projects in the renewable energy sectors may be affected by the prices of energy commodities, such as natural gas, wholesale electricity and other energy-related products. For example, the price of renewable energy resources changes in relation to the market prices of natural gas and electricity. The market price for natural gas is sensitive to cyclical demand and capacity supply, changes in weather patterns,patterns (including extreme temperatures spells), natural gas storage levels, natural gas production levels, general economic and geopolitical conditions (including the current conflictsconflict in the Middle East and Ukraine) and the volume of natural gas imports and exports. The market price of electricity is sensitive to cyclical changes in demand and capacity supply,supply (including both cyclical demand and increased long term demand due to, among others, data storage centers and artificial intelligence), and in the economy and geopolitical conditions (including the current conflicts in the Middle East and Ukraine),conditions, as well as to regulatory trends and developments impacting electricity market rules and pricing, transmission development and investment to power markets within the United States and in other jurisdictions through interconnects and other external factors outside of the control of renewable energy power-producing projects. Volatility of commodity prices also creates volatility in the prices of Environmental Attributes, which are inversely related to the wholesale price of unleaded gasoline. In addition, volatility of commodity prices, such as the market price of gas and electricity, may also make it more difficult for us to raise any additional capital for our renewable energy projects that may be necessary to operate, to the extent that market participants perceive that a project’s performance may be tied directly or indirectly to commodity prices. Accordingly, the potential revenues and cash flows of these projects may be volatile and adversely affect the value of our investments.

Our off-take agreements for the sale of RNG are typically shorter in duration than our fuel supply agreements. Accordingly, if we are unable to renew or replace an off-take agreement for a project for which we continue to produce RNG, we would be subject to the risks associated with selling the RNG produced at that project at then-current market prices. We may be required to make such sales at a time when the market price for natural gas as a whole or in the region where that project is located,located is depressed. If this were to occur, we would be subject to the volatility of gas prices and be unable to predict our revenues from such project, and the sales prices for such RNG may be lower than what we could sell the RNG for under an off-take agreement.

We depend on Environmental Attributes, which are federal, state and local government incentives in the United States, provided in the form of RINs, RECs, LCFS credits, rebates, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects, that promote the use of renewable energy. RINs are created through the RFS program administered by the EPA, which requires transportation fuel sold in the United States to contain a minimum volume of renewable fuel and has historically permitted refineries and importers of transportation fuel to satisfy their RVOs by purchasing either (i) D5 RINs and cellulosic waiver credits (“CWCs”) or (ii) D3 RINs. In a December 1, 2022 proposed rule, EPA proposed to not utilize its cellulosic waiver authority for the years 2023-2025. However, if actual production is lower than the RVO, the EPA will have discretion to utilize CWC. This rule was finalized inon July 12, 2023. On December 12, 2024, EPA proposed a partial waiver of 2024 Cellulosic Biofuel Volume Requirements due to the projected shortfall of D3 RINs available to meet the 2024 RVO. This proposal is still pending and, with a new presidential administration, it is unknown when this proposed rule will bewas finalized (ifon atJuly all) in7, 2025. InEPA addition,made CWCs available for purchase under the RFS, EPA was required to finalize RVO volumes for 2026 by November 1, 2024 but did not meet that deadline. According to the White House Office of Management and Budget’s Fall Unified Agenda and Regulatory Plan, published on December 13, 2024, EPA indicates that it expects in March 2025 to (i) publish afinal rule finalizingalong itswith December 12, 2024 proposedthe partial waiver of the 2024 cellulosic biofuel volume requirement. The final rule also requires the use of a new data source for the average wholesale price of gasoline to be used in the calculation of the CWC price. The EPA proposed the 2026 and 2027 RVOs and a Partial Waiver of the 2025 Cellulosic Biofuel Volume RequirementsRequirement andon June 17, 2025. On August 22, 2025, the EPA issued decisions on 175 Small Refinery Exemptions (iiSREs) proposefor RVOthe years 2023-2025. EPA subsequently proposed a Supplemental Rule (referred to as the SRE reallocation volume) on September 18, 2025, which would account for the for 2023-2025 exempted RVOs. EPA co-proposed SRE reallocation volumes that would account for 2026100 (whichpercent or 50 percent of the exemptions granted for the 2023-2025 compliance years. EPA expectsis aiming to finalize innew Decemberbiofuel 2025). There can be no assurance that EPA will meet its proposed timelinesmandates for these2025, actions.2026 and 2027 along with the Supplemental Rule in late March 2026. RECs are created through state law requirements for utilities to purchase a portion of their energy from renewable energy sources. 74%Approximately, 67% and 76%74% of our operating revenues for 20242025 and 2023,2024, respectively, were generated from the sale of Environmental Attributes. These government economic incentives could be reduced or eliminated altogether,altogether or interpretations of existing regulations or the categories of renewable energy qualifying for such government economic incentives could be changed. These renewable energy program incentives are subject to regulatory oversight and could be administratively or legislatively changed in a manner that could adversely affect our operations. Further, the generation of LCFS credits on our dairy farm project is expected to increase the percentage of our revenues generated from Environmental Attributes. Reductions in, changes to, or eliminations or expirations of governmental incentives could result in decreased demand for, and lower revenues from, our projects. Changes in the level or structure of the RPS of a state for electricity could also result in a decline in our revenues or decreased demand for, and lower revenues from, our electricity projects.

Our operations inherently risk incurring significant environmental costs and liabilities due to the need to manage waste from our processing facilities. Spills or other releases of regulated substances, including spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws, rules and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damagesdamage to persons or property, including natural resources, may result from the EHS impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.

New laws, changes to existing laws, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments could require us to make significant additional expenditures. Continued governmentexpenditures and publicthese emphasisadditional onexpenditures environmental issues can be expected tomay result in increasedus futureterminating investmentsnew for environmental controls at our plants under federalprojects or stateceasing law.operations of existing projects. Present and future federal and state environmental laws and regulations, and interpretations of those laws and regulations, applicable to our operations, more vigorous enforcement policies and discovery of currently unknown conditions may require substantial expenditures that could have a material adverse effect on our results of operations and financial condition. InOn January 2025,7, 2026, President Trump’sTrump Puttingsigned Americaa Firstpresidential inmemorandum Internationalto Environmental Agreements executive order withdrew the United States fromexit the United Nations Framework Convention on Climate Change’sChange (UNFCCC) Parisalong Agreement, which aims to reduce net greenhouse gas emissions by 61% below 2005 levels by 2030. This order also withdrewwith the UnitedIntergovernmental StatesPanel fromon anyClimate similarChange climate-related agreements made under the UNFCCC. The stated purpose of Trump’s Initial Rescissions of Harmful Executive Orders(IPCC) and Actionsover executive60 orderother isinternational toorganizations, retractarguing certainthey practicesdid ofnot Presidentserve Biden,U.S. includinginterests. thoseWhile addressingfederal publicsupport healthfor renewable projects may decline, states and the environment,private thesector climateare crisis and climate-related financial risks. The order rescinds identified initiatives relatedexpected to environmentalcontinue justice,driving clean energy and electric vehicles, and energy and infrastructure. These executive orders present risks to federal incentives available to promote renewable energy, as can be seen in the Unleashing American Energy executive order signed by President Trump that explicitly calls for an immediate pause of the disbursement of funds under the IRA and the Infrastructure Investment and Jobs Act, both of which contain renewable energy incentives.development.

Our ability to generate revenue from sales of RECs, RINs and LCFS credits depends on our strict compliance with these federal and state programs, which are complex and can involve a significant degree of judgment. If the agencies that administer and enforce these programs disagree with our judgments, otherwise determine that we are not in compliance, conduct reviews of our activities or make changes to the programs, then our ability to generate or sell these credits could be temporarily restricted pending completion of reviews or as a penalty, permanently limited or lost entirely, and we could also be subject to fines or other sanctions. Moreover, the inability to sell RINs and LCFS credits could adversely affect our business.

Parties with an interest in other energy sources, including lawmakers, regulators, policymakers, environmental and advocacy organizations or other activists may invest significant time and money in efforts to delay, repeal or otherwise negatively influence regulations and programs that promote renewable energy. Many of these parties have substantially greater resources and influence than we have. Further, changes in U.S. federal, state or local political, social or economic conditions, including a lack of legislative focus on these programs and regulations, could result in their modification, delayed adoption or repeal. Any failure to adopt, delay in implementing, expiration, repeal or modification of these programs and regulations, or the adoption of any programs or regulations that encourage the use of other energy sources (such as coal) over renewable energy, could adversely affect our business, financial condition and results of operations. The current presidential administration’s focus on maximizing coal, oil, and gas production primarily hurts the renewable energy sector by reducing and eliminating financial incentives, pausing wind/solar projects on public lands, and creating regulatory uncertainty. Policies aimed at reversing climate change progress and prioritizing fossil fuels have slowed investment, though market forces and state-level actions continue to drive clean energy growth.

The market for renewable energy is influenced by U.S. federal, state and local government regulations and policies concerning renewable energy. These regulations and policies are continuously being modified, which could result in a significant future reduction in the potential demand for renewable energy, including RINs, RECs and LCFS credits, renewable energy project development and investments. For example, on December 12, 2024, EPA proposed a partial waiver of 2024 Cellulosic Biofuel Volume Requirements due to the projected shortfall of D3 RINs available to meet the 2024 RVO. This proposalrule iswas stillfinalized pending,on and,July 7, 2025. EPA made CWCs available for purchase under the final rule along with athe newpartial presidentialwaiver administration,of itthe is2024 unknowncellulosic whenbiofuel thisvolume proposed rule will be finalized (if at all) in 2025.requirement. Any new government regulations applicable to our renewable energy projects or markets for renewable energy may result in significant additional expenses or related development costs and, as a result, could cause a significant reduction in demand for our renewable energy. For additional information on regulatory developments, see “Item 7A.—Management’s Discussion and Analysis of Financial Condition and Results of Operations —Key Trends—Regulatory, Environmental and Social Trends.”

We are required to register an RNG project with the EPA and relevant state regulatory agencies to generate Environmental Attributes. As a participant of the EPA's RFS program, we qualify our RINs through a voluntary Quality Assurance Plan, which typically takes from three to five months from first injection of RNG into the commercial pipeline system. The Biogas Regulatory Reform Rule ("BRRR") implemented changes to the RFS program effective January 1, 2025. The BRRR requires that all unseparated K3 RINs generated by the RNG producer on RNG volumes injected into the commercial pipeline distribution system only become valid for sale once they are separated with the support of dispensing statements by a registered dispenser or RIN separator. This process couldhas proven to result in delays to the RNG producer's receipt of the separated K2 RINs from the dispenser. This rule change could also result in a RNG producer's failure to generate K3 RINs for a given gas flow month if the registered biogas producer negligently fails to generate the necessary biogas tokens before the end of the subsequent gas flow month. Furthermore, although no similar qualification process currently exists for LCFS credits, we expect such a process to be implemented and would expect to seek qualification on a state-by-state basis under such future programs. Changes to the LCFS program require annual verification of the CI score assigned to a project. Annual verification could significantly affect the profitability of a project, particularly in the case of a livestock farm project. Delays in obtaining registration, RIN qualification, and any future LCFS credit qualification, or change in CI rescoringscores through CARB annual audits, of a new project could delay future revenues from the project and could adversely affect our cash flow. Further, we typically make a large investment in the project prior to receiving the regulatory approval and RIN qualification. BRRR now requires that all RNG producers register their projects and use a Quality Assurance Plan (QAP). QAPs required third-party audits and semi-annual on-site visits of projects to validate generated RINs and overall compliance with the RFS program. We are also subject to a separate third party’s annual attestation review. The QAP provides a process for RIN owners to follow, for an affirmative defense to civil liability, if used or transferred QAP verified RINs were invalidly generated. A project’s failure to comply could result in remedial action by the EPA, including penalties, fines, retirement of RINs, or termination of the project’s registration, any of which could adversely affect our business, financial condition and results of operations. For additional information on recent developments in this area, including the Pico facility’s CI score, see “Item 7A.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Trends—Regulatory, Environmental and Social Trends.”

Furthermore, extreme weather events, such as lightning strikes, ice storms, tornados, extreme wind, hurricanes and other severe storms, wildfires and other unfavorable weather conditions or natural disasters, such as droughts, floods, fires, earthquakes, and rising sea-levels, could adversely affect the input and output commodities associated with the renewable energy sector. Such weather events or natural disasters could also require us to temporarily or permanently shut down the equipment associated with our renewable energy projects, such as our access to power and our power to biogas collection, separation and transmission systems, which would impede the ability of our projects to operate and decrease production levels and our revenue. Operational problems, such as degradation of our project’s equipment due to wear or weather or capacity limitations or outages on the electrical transmission network, could also affect the amount of energy that our projects are able to deliver. Any of these events, to the extent not fully covered by insurance, could adversely affect our business, financial condition and results of operations.

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.

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. For discussion and analysis of our results for the year ended December 31, 2023 compared to the year ended December 31, 2022 ,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, 2024.2025.

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 decidedexpect tothe nottiming transfer all available D3between RINs generated and unseparated and RINs available for transfersale duringto only impact 2025 which is the fourthyear quarterBRRR ofbecame 2024. As a result, in the first quarter of 2025, we had approximately 9,885 RINs in inventory related to 2024 RNG production.effective. We have entered into commitments to transfer all RINs generated and available for sale from 20242025 RNG production. We had approximately 190 RINs generated and unseparated at December 31, 2025. We have not entered into commitments to transfer futureapproximately 2,500 RINs generated and available for sale from forecasted future 20252026 RNG production. The average D3 RIN index price for the fourth quarter of 20242025 and January 20252026 through February 28, 20252026 was approximately $2.80$2.39 and $2.42,$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.

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

In 2024,2025, we successfullybegan commissioned the expansion of our digestion capacity which is necessary to processprocessing the final tranche of increased feedstock expected to be received in the second quarter of 2025.feedstock. Upon receipt of the final tranche, we will makemade the final contractual payment to the dairy host. As a result of the increased digestion capacity, we produced approximately 73.4%31.8% more MMBtu during 20242025 as compared to 2023.2024. 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.

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. DuringIn 2024,2025, 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 locatinglocation 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 targetmatch a commissioning start in 2027 and currently expect theour capital investment toin beginthese inproject opportunities with the seconddevelopment quartertimeline of 2025EENA’s for long lead equipment and design engineering.facility.

In 2021, through a wholly-owned subsidiary Montauk Ag Renewables,Renewables we completed an asset purchase related to developingpurchased technology and aassets centralized(the processing“Montauk locationAg Renewables Acquisition”) to recover residual natural resources from theswine waste streams of modern agriculture and to refine and recycle such waste products through proprietary and other processes in order to produce high quality renewable naturalelectricity, gasNorth andCarolina recaptureswine nitrogen, phosphorus,RECs, and micronutrient organic fertilizer alternativesalternatives. (Upon completion of the “Montaukfirst Agphase Renewablesof Acquisition”).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 updateDevelopments

Offtake updateDevelopments

Feedstock collection updateCollection

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 200 thousand300 hog spaces to support our expected processing needs under our first phase for the Turkey, NCTurkey location. We continue to install collection equipment at these separate farms to access the waste. We currently estimate capital investment of up to 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.

In 2023, we announced a planned development of a renewable natural gas landfill project in Irvine, CA at the Frank R. Bowerman Landfill to process the large and growing volumes of biogas in excess of the existing capacity of the REG facility. We expect facility commissioning in 2027 and expect the capital investment to range between $85,000 - $95,000. As part of the agreement to develop the RNG plant, we agreed to work with the landfill host on the landfill's management of its wellfield and flare facility permit requirements.requirements Theand landfill has proposed corresponding changes to our agreement, which could impact our existing commissioning schedule. We continue tothis work withremains the landfill on these proposed changes to assess what, if any, impacts these changes could have on receipt of required regional regulatory construction permits.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 approximately 4,100 scfm of averaged unprocessed gas which is more than the anticipated inlet of the RNG facility currently under development.

Blue GraniteRumpke RNG Relocation Project

Regulatory, environmental and social factors are key drivers that incentivize the development of RNG and Renewable Electricity projects and influence the economics of these projects. We are subject to the possibility of legislative and regulatory changes to certain incentives, such as RINs, RECs and GHG initiatives. On July 12, 2023, the EPA issued final rules in the Federal Register for the RFS volume requirements for 2023-2025. Final volumes for cellulosic biofuel were set at 838, 1,090 and 1,376 million RINs for the three years 2023, 2024 and 2025, respectively. The EPA did not finalize the eRIN program in this ruling, however, it indicated that it will continue to work on potential paths forward for the eRIN program. However, the EPA did not set a new date for a revised eRIN program. The cellulosic biofuel volumes in the final rule for 2024 and 2025 are lower than the proposed volume as they do not include cellulosic biofuel from eRINs. The final rule also included significant changes to the existing RFS program, referred to as BRRR, that will requirerequired the RNG industry to modify how all RINs are generated.generated Onas of January 1, 2025, all RFS participants must comply with BRRR provisions.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.

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 create90% aby 2045 target of 90%.2045. This reduction would have the potential impact of reducing the number of net credits in the program. CARBOn approvedJuly these1, new2025, CARB’s amended LCFS rules inofficially Novembertook 2024,effect however in February 2025,setting the Californiaaggressive Officecarbon ofintensity Administrativereduction Lawtargets disapprovedlisted the changes because the regulations were not written in a way that persons directly affected by them could easily understand. CARB believes this disapproval to be routine and indicated its intention to resubmit the rules, which it has until June 2025 to do. Any substantive changes would be subject to a public comment period.above. The industry may seesee3 pricinggradual volatilityincreases including potential decreases toin LCFS credit prices whereasover the amendmentsnext asyear. originally approved were expected to increase LCFS credit prices. Also in theThe rules is aalso phase out of avoided methane crediting for dairy and swine manure pathways by 2040 for CNG usage and through 2045 for RNG used to produce hydrogen. The RNG deliverability/book and claim provisions for out-of-region projects will beare 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.

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,Statements” and elsewhere in this report, “Item 1A.–Risk Factors” of our 2025 Annual Report, and elsewhere in thisour report.other SEC filings.

Our profitability is highly dependent on the market price of Environmental Attributes, including the market price for RINs. As we self-market a significant portion of our RINs and as the RFS is based on annual compliance, a decision not to commit to transfer and monetize available RINs during a period will impact the timing of our operating revenues and operating profit recognized during a period. We sold all 3,903 D3 RINs generated and available for sale from our 2025 RNG production in the first quarter of 2026. We had approximately 165137 RINs generated but unseparated at MarchJune 31,30, 2026. The average D3 RIN index price for the firstsecond quarter of 2026 was approximately $2.41.$2.54. The following table summarizes select historical data related to RINs generated, RINs sold, and RINs generated but unsold.unsold from our RNG operations. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The results related to our GreenWave joint venture are excluded from the table below. The timing of RIN transfers can vary year over year and by period within a year and is contingent on various factors including, but not limited to: (a) the Company’s expectations on RIN index price, (b) operational needs of the Company, (c) obligated parties purchase needs, or (d) the type of customer among other matters.

Through our wholly-owned subsidiary Pesta Energy, LLC, we entered into an agreement with Pioneer Renewables Energy Marketing, LLC to form a joint venture, GreenWave Energy Partners, LLC. The primary goal of the joint venture is to help address the limited capacity of RNG utilization for transportation by offering third party RNG volumes access to exclusive unique and proprietary pathways. We recorded income from GreenWave of approximately $3,320$7,092 in the first quartersix months of 2026. We also received 1,3982,909 in separated RINs distributed from GreenWave of which we have 425 available for sale as of March 31, 2026.GreenWave. 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.

Atascocita Carbon Dioxide Beneficial Use Opportunity

In April 2026, we sent a letter confirming termination of our contract with European Energy North America (“EENA”) for the delivery of biogenic carbon dioxide (“CO2”). The termination was due to EENA’s failure to provide certain contractual assurances and notices related to the construction of their Texas-based e-methanol facility. We arecontinue currentlyto exploringexplore alternative offtake arrangements with interested parties at our Atascocita location. The timing of capital expenditures will be synchronous with the finalization of replacement offtake agreements. We continue to anticipate a capital investment between $30,000 and $40,000.$40,000, however our 2026 development capital range does not include additional capital outlay for this CO2 project.

Shifts in Revenue Composition for Projects from New Fuel Sources: As we expand into agriculture projects, our revenue composition from Environmental Attributes will change. We believe that agriculture offers us a lucrative opportunity,opportunity asFor example, the value of LCFS credits for dairy farm projects, for example, are a multiple of those realized from landfill projects due to the significantly more attractive CI scoring. Additionally, we believe that REC generation from swine farm projects, increases revenues from regulatory frameworks other than the RFS. As we expand into agriculture projects, our revenue composition from Environmental Attributes will change.

On March 15, 2025, the Full-Year Continuing Appropriations and Extensions Act, 2025 was signed into law. In May 2025, we were informed that the law eliminated the United States Department of Agriculture Advanced Biofuel Payment Program. We received approximately $200 annually since 2021 under this program. In 2025, we received notice that the program was reinstated and that retroactive payments would be issued for the missed quarters while the program was closed. In the first quarter of 2026, we recorded approximately $265$327 related to the quartersAdvanced forBiofuel whichPayment the program was closed.Program.

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

The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in our financial statements or tax returns and forecasting future profitability by tax jurisdiction. We complete a full analysis annually of our deferred tax assets and liabilities. We expect our New Senior Credit Facility could generate additional tax attributes related to interest expense limitations under applicable IRC code sectionSection 163(j). We continue to review our future tax planning including but not limited to the ability to stack tax attributes, limitation on deductibility and expiration, but we do not currently expect to transfer, as applicable, any tax attributes generated.

Renewable Natural Gas Revenues: We record revenues from the production and sale of RNG and the generation and sale of the Environmental Attributes derived from RNG, such as RINs and LCFS credits. Our RNG revenues from Environmental Attributes are recorded net of a portion of Environmental Attributes shared with off-take counterparties as consideration for such counterparties using the RNG as a transportation fuel. We entered into pathway renewals in the third quarter of 2025 for certain volumes at percentages consistent with our historical percentages. Historically, we have monetized less than 25% of our RNG volumes under these fixed-price agreements.

RNG Production from Our Growth Projects: We anticipate increased production at certain of our existing projects as open landfills continue to take in additional waste and the amount of gas available for collection increases. Delays in commencement of production or extended commissioning issues at a new project or a conversion project, such as those we are currently experiencing at Blue Granite,project would delay any realization of production from that project.

The sale of RINs, which is subject to market price fluctuations, accounts for a substantial portion of our revenues. We manage against the risk of these fluctuations through forward sales of RINs, although currently we only sell RINs in the calendar year they are separated. We have entered into commitments to transfer athe significant portionmajority of RINs generated and available for sale from our expected 2026 third quarter RNG production at an average price of $2.42.$2.66. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.

General and Administrative Expenses: General and administrative expenses primarily consist of corporate expenses and unallocated support functions for our operating facilities, including personnel costs for executive, finance, accounting, investor relations, legal, human resources, operations, engineering, environmental registration and reporting, health and safety, IT and other administrative personnel and professional fees and general corporate expenses. From time to time, we may be parties to legal proceedings arising in the normal course of business which could increase our legal expenses. We continue to expect increased general and administrative expenses associated with our ongoing development of Montauk Ag Renewables in 2026. We account for share-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. We do not believe the May 2026 restricted stock unit awards granted by the Board of Directors will significantly increase share-based compensation expense for the second half of 2026. For more information, see Note 15 to our unaudited condensed consolidated financial statements related to share-based compensation.

Comparison of Three Months Ended MarchJune 31,30, 2026 and 2025

Revenues for the Three Months Ended MarchJune 31,30, 2026 and 2025

Total revenues in the firstsecond quarter of 2026 were $46,428,$54,020, an increase of $3,825$8,893 (9.0%19.7%) compared to $42,603$45,127 in the firstsecond quarter of 2025. The increase is primarily related to environmental attribute revenues of approximately $4,236$8,402 from RINs sold related to the distribution of RINs from our GreenWave joint venture which had no RINs distributed and sold in the firstsecond quarter of 2025. Our firstsecond quarter of 2026 RNG volumes sold under fixed/floor-price contracts decreased approximately 82.1%80.0% as compared to firstsecond quarter of 2025 as a result of the expiration of fixed price pathway contract expiration.contracts. Our RNG commodity revenue decreased approximately 49.3%63.7% which was offset by an increase in RINs sold of 25.5%.29.1%. Also, our RINs generated and unseparated decreased approximately 95.4% as a result of the transition to BRRR in 2025.

Revenues from the Renewable Natural Gas segment in the firstsecond quarter of 2026 were $38,075,$40,936, aan decreaseincrease of $376$107 (1.0%0.3%) compared to $38,451$40,829 in the firstsecond quarter of 2025. Average commodity pricing for natural gas for the firstsecond quarter of 2026 was $5.04$2.90 per MMBtu, 38.1%15.7% higherlower than the firstsecond quarter of 2025. During the firstsecond quarter of 2026, we self-marketed 12,40314,265 RINs, representing a 2,5183,215 increase (25.5%29.1%) compared to 9,88511,050 in the firstsecond quarter of 2025. Average pricing realized on RIN sales during the firstsecond quarter of 2026 was $2.42$2.45 as compared to $2.46$2.42 in the firstsecond quarter of 2025, aan decreaseincrease of 1.7%.1.2%. Average D3 RIN index price for the firstsecond quarter of 2026 was $2.41$2.54 compared to $2.43$2.36 in the firstsecond quarter of 2025, aan decreaseincrease of approximately 0.6%.7.6%. At MarchJune 31,30, 2026, we had approximately 431429 MMBtu available for RIN generation, 165137 RINs generated and unseparated, and 790 RINs generated and unsold. At MarchJune 31,30, 2025, we had approximately 336309 MMBtu available for RIN generation, 1,4823,009 RINs generated and unseparated, and 3,916108 RINs generated and unsold.

We produced approximately 4344 MWh in Renewable Electricity in the firstsecond quarter of 2026, aan decreaseincrease of 32 MWh (6.5%4.8%) from 4642 MWh in the firstsecond quarter of 2025. Our PicoBowerman facility produced approximately 23 MWh fewermore in the firstsecond quarter of 2026 compared to the firstsecond quarter of 2025. The decreaseincrease is primarily related to decommissioningincreased ofgas one our engines in the second quarter of 2025flows due to thelandfill shifthost towardswellfield boiler heat for our digestion process. Our Bowerman facility produced approximately 1 MWh fewer in the first quarter of 2026 compared to the first quarter of 2025. The decrease is primarily related to original equipment manufacturer required lifecycle maintenance on our engines, beginning in the first quarter of 2026.improvements.

Revenues from Renewable Electricity facilities in the firstsecond quarter of 2026 were $4,117,$4,505, aan decreaseincrease of $35$207 (0.8%4.8%) compared to $4,152$4,298 in the firstsecond quarter of 2025. The decreaseincrease was primarily driven by the decreaseincrease in production volumes.

In both the firstsecond quarter of 2026,2026 and 2025, 100.0% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices associated with underlying PPAs, as compared to 100.0% in the first quarter of 2025.PPAs. This provides us with certainty of price resulting from our Renewable Electricity sites.

Total general and administrative revenues in the second quarter of 2026 were $8,579. We recorded approximately $4,236$8,402 in the firstsecond quarter of 2026 related to RINs distributed from our joint venture, GreenWave. We sold approximately 1,7553,387 RINs distributed from GreenWave and the RINs related to pathway dispensing, which are not included within our operating metrics table. There were no such revenues incurred during the second quarter of 2025.

Expenses for the Three Months Ended MarchJune 31,30, 2026 and 2025

Total general and administrative expenses in the firstsecond quarter of 2026 were $8,019,$7,666, a decrease of $735$1,378 (8.4%15.2%) compared to $8,754$9,044 in the firstsecond quarter of 2025. The decrease is primarily related to thea one-time accelerated vesting of $1,550 from certain restricted share awards in 2025.the Our corporate insurance fees decreased approximately $261 in first quarter of 2026 as compared to firstsecond quarter of 2025 due to the termination of an employee.

Total operating and maintenance expenses in the firstsecond quarter of 2026 were $23,155,$29,061, an increase of $5,598$7,197 (31.9%32.9%) compared to $17,557$21,864 in the firstsecond quarter of 2025.

We recorded approximately $4,247$8,348 in the firstsecond quarter of 2026 related to the cost of RINs distributed from GreenWave and the costs related to pathway dispensing associated with our dispensing RNG in exclusive unique and proprietary pathways, which are not included within our operating metrics table. There were no such expenses incurred during the firstsecond quarter of 2025.

Operating and maintenance expenses for our RNG facilities in the firstsecond quarter of 2026 were $14,353,$15,568, ana increasedecrease of $263$1,387 (1.9%8.2%) as compared to $14,090$16,955 in the firstsecond quarter of 2025. Our RumpkeMcCarty facility operating and maintenance expenses increaseddecreased approximately $397$891 primarily related to preventativethe timing of maintenance mediarelated changes.to gas processing equipment. Our Apex facility operating and maintenance expenses increaseddecreased approximately $262$451 primarily related to increased utility expense which was partially offset by decreased preventative maintenance media changes. Our Atascocita facility operating and maintenance expenses increased approximately $246 primarily related to wellfield operational enhancements. Offsetting the increase was our Galveston facility operating and maintenance expenses which decreased approximately $580. The decrease is primarily due to the timing of maintenance of gas processing equipment and preventative maintenance media changes.maintenance.

Operating and maintenance expenses for our Renewable Electricity facilities in the firstsecond quarter of 2026 were $4,484,$5,062, an increase of $1,133$253 (33.8%5.3%) compared to $3,351$4,809 in the firstsecond quarter of 2025. The increase is primarily driven by an increase in non-capitalizable costs of approximately $808$1,162 at our Montauk Ag Renewables project. Our Bowerman facility operating and maintenance expenses increaseddecreased approximately $371$716 primarily related to decreased wellfield operational costs and timing of gas processing preventative maintenance.

Royalties, transportation, gathering, and production fuel expenses in the firstsecond quarter of 2026 were $8,037,$8,814, ana increasedecrease of $466$354 (6.2%3.9%) compared to $7,571$9,168 in the firstsecond quarter of 2025. We make royalty payments to our fuel supply site partners on the commodities we produce and the associated Environmental Attributes. These royalty payments are typically structured as a percentage of revenue subject to a cap, with fixed minimum payments when Environmental Attribute prices fall below a defined threshold. To the extent commodity and Environmental Attributes’ prices fluctuate, our royalty payments may fluctuate upon renewal or extension of a fuel supply agreement or in connection with new projects. Our fuel supply agreements are typically structured as 20-year contracts, providing long-term visibility into the margin impact of future royalty payments.

Royalties, transportation, gathering and production fuel expenses for our Renewable ElectricityRNG facilities for the firstsecond quarter of 2026 were $456,$8,293, a decrease of $1$375 (0.2%4.3%) compared to $457$8,668 in the firstsecond quarter of 2025. Royalties, transportation, gathering and production fuel expenses increaseddecreased as a percentage of Renewable ElectricityRNG revenues to 11.1 %20.3% for the firstsecond quarter of 2026 from 11.0%21.2% in the firstsecond quarter of 2025.

Depreciation and amortization in the firstsecond quarter of 2026 was $8,373,$7,904, an increase of $2,109$875 (33.7%12.4%) compared to $6,264$7,029 in the firstsecond quarter of 2025. The increase was primarily driven by the timing of wellfield and maintenance capital investments placed into service and our Second Apex RNG Facility project being placed into service.

We calculated and recorded impairment losses of $443$650 in the firstsecond quarter of 2026, aan decreaseincrease of $1,604$273 (78.4%72.4%) compared to $2,047$377 in the firstsecond quarter of 2025. The decrease primarilyincrease relates to the impairment of an RNG development project for which the local utility no longer accepted RNG into its distribution system in specifically identified assets deemed obsoletediscrete or non-operable.non-operable assets.

Other income in the firstsecond quarter of 2026 was $1,306,$2,291, an increase of $2,497$3,547 (209.7%282.4%) compared to other expenses of $1,191$1,256 in the firstsecond quarter of 2025. In the firstsecond quarter of 2026, we recorded approximately $3,320$3,772 in income related to our joint venture investment in GreenWave. There was no such income reportedfrom duringGreenWave in the firstsecond quarter of 2025. Also in the first quarter of 2026, we recorded approximately $944 in debt extinguishment costs from refinancing our credit agreement.

Income Tax BenefitExpense

Income tax benefitexpense for the three months ended MarchJune 31,30, 2026 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21.0% primarily related to the adjustment of Production Tax Credits as well as stock based compensation.

The effective tax rate of 101.4%89.8% for the three months ended MarchJune 31,30, 2026 was higher than the rate for the three months ended MarchJune 31,30, 2025 of 40.6%(52.0%) primarily due to the change in our pre-tax book loss for the three months ended MarchJune 31,30, 2026 as compared to the three months ended MarchJune 31,30, 2025.

Operating (Loss) Income for the Three Months Ended MarchJune 31,30, 2026 and 2025

Operating loss in the firstsecond quarter of 2026 was $1,599$75, a decrease of $2,280 (96.8%) compared to operating income of $410$2,355 in the firstsecond quarter of 2025. RNG operating income for the firstsecond quarter of 2026 was $8,745,$9,643, aan decreaseincrease of $1,624$415 (15.7%4.5%) compared to $10,369$9,228 in the firstsecond quarter of 2025. Renewable Electricity Generation operating loss for the firstsecond quarter of 2026 was $2,171,$2,132, ana increasedecrease of $1,150$216 (112.6%9.2%) compared to $1,021$2,348 for the firstsecond quarter of 2025.