Montauk Renewables, Inc. (MNTK) FY 2024 MD&A

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.

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 decided to not transfer all available D3 RINs generated and available for transfer during the fourth quarter of 2024. As a result, in the first quarter of 2025, we had approximately 9,885 RINs in inventory related to 2024 RNG production. We have entered into commitments to transfer all RINs generated and available for sale from 2024 RNG production. We have not entered into commitments to transfer future RINs generated from forecasted future 2025 RNG production. The average D3 RIN index price for the fourth quarter of 2024 and January 2025 through February 28, 2025 was approximately $2.80 and $2.42, respectively.

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Capital Development Summary

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

Pico Digestion Capacity Increase

In 2024, we successfully commissioned the expansion of our digestion capacity which is necessary to process the final tranche of increased feedstock expected to be received in the second quarter of 2025. Upon receipt of the final tranche, we will make the final contractual payment to the dairy host. As a result of the increased digestion capacity, we produced approximately 73.4% more MMBtu during 2024 as compared to 2023.

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. During 2024, we completed the initial site surveys related to locating the CO2 processing equipment, evaluated equipment suppliers, and started engineering design. We continue to target a commissioning start in 2027 and currently expect the capital investment to begin in the second quarter of 2025 for long lead equipment and design engineering.

Waste-stream Biogas Recovery

In 2024, a collaboration with Emvolon was announced to transform methane emissions from waste stream biogas into high-value carbon negative fuel. Leveraging Emvolon's patented technology, the initial pilot at our Atascocita facility in Houston, Texas is a small-scale demonstration of recovering and converting biogas into green methanol. The pilot is designed to provide proof of concept and we may eventually move to a commercial facility capable of producing up to 15 thousand gallons of green methanol per year. The ultimate goal is to lead to a full-scale, commercial system capable of producing up to 2,400 gallons of methanol annually at the same or similar sites. We do not expect any short term financial benefits from this demonstration nor a disruption to our operations.

REG Facility Sale

In 2024, we reached an agreement with the site host to sell the gas rights ahead of the fuel supply expiration of one of our existing REG operating facilities. We received proceeds of $1,000 and no longer have obligations to decommission or remove any machinery or equipment at the site. The proceeds received were in excess of the carrying value of the site. The PPA at this site expired during 2024 at which time we estimated that the revenues from this site would significantly decrease adversely impacting this sites future cash flows from operations. The effective date of the sale was October 1, 2024. In connection with the sale, we secured fuel supply agreement amendments to extend the terms of our existing RNG operating facilities, Atascocita and Coastal Plains.

RNG Facility Sale

In December 2024, we entered into an asset purchase agreement to sell an RNG site for a purchase price of $1,000. We entered into the agreement regarding this immaterial site in advance of the expiration of the gas rights agreement at this site. The proceeds received were in excess of the carrying value of the site.

Tulsa REG Conversion to RNG

In 2025, we began an initiative to convert our Tulsa, Oklahoma Renewable Electric Generation facility project through the design and construction of an RNG facility. The project will offer a variable inlet capacity providing production capacity of approximately 1,500 MMBtu per day and designed to beneficially process all of the available inlet gas feedstock from its landfill host.

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We expect the capital investment to range from approximately $25,000 to $35,000 and be commissioned during the first quarter of 2027.

Second Apex RNG Facility

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

Montauk Ag Asset Acquisition

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

Regulatory update

Our progress with regulatory agencies in North Carolina related to the resulting power generation derived from swine waste to confirm its eligibility for RECs under North Carolina’s Renewable Energy Portfolio Standards in anticipation of commercial production remains ongoing. The Turkey location was approved to participate in the Piedmont Natural Gas Renewable Gas Pilot Program which is a step towards obtaining the NREF designation under the NCUC. In January 2024, we received notification from the NCUC that the Turkey, NC location was approved for an NREF and Certificate of Public Convenience and Necessity. In October 2024, our amended NREF application was approved. In December 2024, as part of a broader North Carolina omnibus bill package, the State of North Carolina approved a change in the laws governing the generation of RECs from swine waste under its renewable energy portfolio standards. For qualifying projects in qualifying locations, qualifying swine REC generators have the ability to generate 3:1 RECs for a period of 8 years, followed by 2:1 RECs for a period of 6 years, with normal 1:1 REC generation thereafter. The implementation of this law is ongoing with the NCUC and is subject to limitations, including but not limited to, the annual generation of swine RECs under the change in law.

Offtake update

In July 2023 we signed a REC agreement with Duke Energy (“Duke”). At full first phase capacity, we anticipate the ability to process feedstock from over 200 hog spaces per day, which equates to over two hundred tons of daily waste collection. We currently estimate the first phase of the project will annually produce approximately 45 to 50 MWh equivalents through the combination of 190 to 200 MMBtu and 25 to 30 MWh. We also estimate that at full processing capabilities, the first phase of the project will additionally produce annually 17 to 20 tons of organic fertilizer alternatives. Once the first phase and the facility has been fully commissioned, the project will provide sufficient capacity to satisfy the Duke REC agreement through the deployment of up to eight operational processing lines at the Turkey Creek facility.

With the change in REC generation passed by the state of North Carolina, we are in various other negotiations with other utility users to provide swine RECs from our expected first phase production of MWh.

Feedstock collection update

We have entered into agreements with over forty separate farming locations to provide access to waste from at least 200 thousand hog spaces to support our expected processing needs under our first phase for the Turkey, NC 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 continue to test the most efficient methods of transporting the swine feedstock from the collection farms to the centralized process location. Currently, we are testing a waste palletization process on the mobile equipment. This palletization will capture the energy content in the waste preventing energy decay from time as well as enabling more efficient processing through the reactor. We currently estimate that each mobile collection and transportation unit could range up to approximately $300.

Interconnection update

Our electricity interconnection is ongoing and expected to be completed in the fourth quarter of 2025. This timeline meets our expectations for the commissioning of our reactors and to begin revenue generating activities. Additionally, and to provide future optionality, the gas interconnection is expected to be commissioned in the second quarter of 2025. While the production of RNG is currently secondary to the generation of MWh and swine RECs, this gas interconnection could provide future revenue opportunities to the Turkey, NC location through either production on site or through the injection of gas from other providers.

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Production construction update

Including the original equipment acquired in the Montauk Ag Renewables Acquisition, the Turkey, North Carolina asset acquisition, and the relocation of the Magnolia, NC site reactor to Turkey, NC, we currently expect the first phase capital investment to range between $140,000 and $160,000. We continue to use the pilot reactor that was relocated in 2023 and previously operated prior to the 2021 Montauk Ag Renewables Acquisition. The pilot reactor testing includes refining feedstock conveyance, equipment processing, product gas composition, and the composition of the solid output. We have processed and tested both the biogas and micronutrient organic fertilizer alternatives. We are also continuing to staff the Turkey, North Carolina location. With the engineering of the Turkey, NC location being substantively completed, we have finalized an EPC contract to complete the site construction.

Excluding capital expenditures related to feedstock processing but including the original 2021 Montauk Ag Asset Acquisition, we have incurred the following significant capital expenditures at the Turkey, NC site:

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$16,856 related to the site including land and improvements

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$15,891 associated with electrical and engineering related matters

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$8,369 related to production processing equipment

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$4,415 related to interconnection

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$1,841 related to the reactors

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

Bowerman RNG Project

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

Blue Granite RNG Project

In 2023, we announced the planned entrance into South Carolina with the development of a new landfill gas-to-RNG facility. The planned project was expected to contribute approximately 900 MMBtu per day of production capacity upon commissioning.

We experienced delays with our interconnection, most recently due to the utility informing us of their near-term prioritization of remediation efforts from the impacts of Hurricane Helene. In February 2025, we received notice from the utility that it will no longer be honoring a letter of intent secured when we won the development rights to this location and will no longer accept RNG into its distribution system. 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, included but not limited to physical and virtual and fixed interconnections. We are also reviewing alternatives for this site around producing energy other than RNG. We have paused further capital expenditures related to this site while we consider all alternatives.

Key Trends

Market Trends Affecting the Renewable Fuel Market

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

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

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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:

Conversion of Electricity Projects to RNG Projects:

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

Acquisition and Development Pipeline

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

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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. Under the Biogas Regulatory Reform Rule, effective July 1, 2024, theoretical storage of RNG for future RIN generation prior to receiving EPA registration is no longer permitted and the receipt of RINs will no longer be delayed after injecting into a pipeline. We expect the elimination of theoretical storage, when combined with more timely EPA registration, to not materially impact the commencement of RIN revenue generation after pipeline injection.

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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 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

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program, referred to as BRRR, that will require the RNG industry to modify how all RINs are generated. On January 1, 2025, all RFS participants must comply with BRRR provisions. We have registered all of our facilities under the BRRR provisions and have obtained Q-RIN status for RIN generation starting January 1, 2025. Under the BRRR provisions, the EPA finalized a limitation that biogas from one facility has a single use under the RFS as proposed (i.e., biointermediate, RNG or CNG/LNG via biogas closed distribution system). The EPA clarified that this does not preclude non-RFS uses at same facility.

The EPA did not meet the statutorily required deadline of November 2024 to finalize 2026 obligations under the RFS. The EPA is still expected to target March 2025 to propose RFS obligations for 2026 unless the EPA is directed otherwise by the Trump administration.

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

Changes to the LCFS program require annual verification of the CI score assigned to a project. Annual verification could significantly affect the profitability of a project, particularly in the case of a livestock farm project.

Factors Affecting Revenue

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

We report revenues from two operating segments: Renewable Natural Gas and Renewable Electricity Generation. Corporate relates to additional discrete financial information for the corporate function; primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering, and other operations functions not otherwise allocated to a segment. As such, the corporate 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 Environmental Attributes derived from RNG, such as RINs and LCFS credits. Our RNG revenues from Environmental Attributes are recorded net of a portion of Environmental Attributes shared with off-take counterparties as consideration for such counterparties using the RNG as a transportation fuel. We had certain pathway provider sharing arrangements expiring throughout 2024. While we did not experience a significant increase in Environmental Attributes shared with pathway providers in our 2024 renewals, our most recent pathway renewals have been at higher percentages than our historical percentages and the currently proposed pathway renewals are for percentages significantly higher than our historical arrangements. Historically, we have monetized less than 25% of our RNG volumes under these fixed-price agreements. We are considering entry into multiple short term contracts throughout 2025, some potentially increasing our historical percentage of volumes monetized under fixed-price arrangements., to provide time for mitigation of these recent market trends.

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

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

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.

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RNG Production

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

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

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

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

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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 expect these mitigation efforts to continue into 2025.

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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.

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

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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 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 not entered into commitments to transfer significant RINs generated from 2025 production. 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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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.

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

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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 expect increased general and administrative expenses associated with our ongoing development of Montauk Ag Renewables in 2025. The Company accounts for stock-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. For more information, see Note 15 to our 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 significant capital to build and own our facilities. In addition to development capital, we annually reinvest to maintain these facilities.

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

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

Key Operating Metrics

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

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Production Volumes: We review performance by site based on unit of production calculations for RNG and Renewable Electricity, measured in terms of MMBtu and MWh, respectively. While unit of production measurements can be influenced by 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 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, though a portion are generated and monetized by third parties under counterparty sharing agreements. A majority of our Renewable Electricity Generation segment Environmental Attributes are monetized as a component of our fixed-price PPAs.

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Average realized price per unit of production: Our profitability is highly dependent on the commodity prices for natural gas and electricity, and the Environmental Attribute prices for RINs, LCFS credits, and RECs. Realized prices for

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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, 2024 and 2023

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

(1)
RINs are generated the month following the month gas is produced and dispensed. Volumes under fixed/floor arrangements generate RINs which we do not self-market.

(2)
One MMBtu of RNG has the same energy content as 11.727 gallons of ethanol, and thus may generate 11.727 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.

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Results of Operations

Comparison of Years Ended December 31, 2024 and 2023

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

Revenues for the Years Ended December 31, 2024 and 2023

Total revenues in 2024 were $175,736, an increase of $832 (0.5%) compared to $174,904 in 2023. The 2024 average realized RIN price of $3.28 increased approximately 21.0% compared to $2.71 in 2023. The natural gas index price decreased approximately 17.2% from $2.74 in 2023 to $2.27 in 2024. Also, there was a decrease in the number of RINs we self-marketed during 2024 due to a strategic decision to not self-market 6,822 RINs in the fourth quarter of 2024. We entered into margin sharing arrangements in 2024 which increased margin share revenues approximately $770 as compared to none in 2023. Offsetting this increase was a reduction of $1,758 in LCFS credit revenues primary related to 2022 RNG production volumes being released from storage and generating LCFS credit revenues in 2023.

Renewable Natural Gas Revenues

We produced 5,587 MMBtu of RNG during 2024, an increase of 88 MMBtu (1.6%) compared to 5,499 MMBtus in 2023. Wellfield optimization operational enhancements as well as plant processing equipment improvements contributed to the increase, notably with our Coastal facility producing 111 MMBtu more in 2024 compared to 2023. Our Pico facility produced 76 MMBtu more in 2024 compared to 2023 as a result of commissioning our dairy digestion expansion project. Our Galveston facility produced 59 MMBtu more in 2024 compared to 2023 as a result of previously disclosed 2023 dry weather conditions impacting gas feedstock availability. Offsetting these improvements were unrelated wellfield quality issues and weather anomalies which lowered production, led by our Rumpke facility producing 159 fewer MMBtu in 2024 compared to 2023.

Revenues from the Renewable Natural Gas segment in 2024 were $157,983, an increase of $1,528 (1.0%) compared to $156,455 in 2023. Average commodity pricing for natural gas for 2024 was 17.2% lower than the prior year. During 2024, we self-marketed 36,639 RINs, representing an 8,297 decrease (18.5%) compared to 44,936 in 2023. The decrease 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 2024 was $3.28 as compared to $2.71 in 2023, an increase of 21.0%. This compares to the average D3 RIN index price for 2024 of $3.12 being approximately 18.6% higher than the average D3 RIN index price in 2023 of $2.63. At December 31, 2024, we had approximately 291 MMBtus available for RIN generation and had approximately 6,822 RINs generated and unsold. We had approximately 358 MMBtus available for RIN generation and approximately 108 RINs generated and unsold at December 31, 2023. We have entered into commitments and transferred all of our RINs in inventory related to our 2024 RNG production.

Renewable Electricity Generation Revenues

We produced 186 MWh in Renewable Electricity in 2024, a decrease of approximately 8 MWh (4.1%) compared to 194 MWh in 2023. Our Security facility produced 9 MWh less in 2024 compared to 2023 as a result of us ceasing operations in connection with the first quarter of 2024 sale of the gas rights back to the landfill host.

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Revenues from Renewable Electricity facilities in 2024 were $17,753, a decrease of $696 (3.8%) compared to $18,449 in 2023. The decrease is primarily driven by the decrease in our Security facility production volumes.

Expenses for the Years Ended December 31, 2024 and 2023

General and Administrative Expenses

Total general and administrative expenses were $36,286 in 2024, an increase of $1,883 (5.5%) compared to $34,403 in 2023. Employee related costs, including stock-based compensation costs were $23,099 in 2024, an increase of $3,366 (17.1%) compared to $19,733 in 2023. The increase was primarily related to the accelerated vesting of certain restricted share awards as a result of the termination of an employee. Our professional fees decreased approximately $1,628 (35.3%) in 2024 compared to 2023.

Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in 2024 were $53,387, an increase of $5,501 (11.5%) compared to $47,886 in 2023. Our Rumpke facility operating and maintenance expenses increased approximately $1,839 as a result of increased media change outs and gas processing equipment maintenance costs. Our McCarty facility operating and maintenance expenses increased approximately $1,212 as a result of a wellfield operational enhancement program and increased gas compression system maintenance costs. Our Pico facility operating and maintenance expenses increased approximately $927 as a result of non-capitalizable costs associated with the digestion capacity increase project and efficiency improvements with the existing digestion capacity. Our Atascocita facility operating and maintenance expenses increased approximately $632 primarily driven by increased utility expense. Our Apex facility operating and maintenance expenses increased approximately $291 primarily related to increased gas processing equipment maintenance costs.

Royalties, transportation, gathering and production fuel expenses for our RNG facilities in 2024 were $29,529, a decrease of $3,347 (10.2%) compared to $32,876 in 2023. Our Pico facility earnout decreased approximately 33.3% during 2024 compared to 2023 based on our current estimate of the present value of the earnout. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of RNG revenues to 18.7% for 2024 from 21.0% in 2023.

Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in 2024 were $12,760, an increase of $1,015 (8.6%) compared to $11,745 in 2023. The primary driver of the increase were operating and maintenance expenses at our Magnolia facility, associated with feedstock collection for Montauk Ag Renewables, which increased approximately $1,136 as a result of non-capitalizable costs.

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for 2024 were $1,973, a decrease of $12 (0.6%) compared to $1,985 in 2023, and as a percentage of Renewable Electricity Generation segment revenues increased from 10.8% for 2023 to 11.1% for 2024.

Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in 2024 were $31,502, a decrease of 3,359 (9.6%) compared to $34,861 in 2023. 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 2024 was $23,515, an increase of $2,357 (11.1%) compared to $21,158 in 2023 . The increase is associated with the timing of capital investments placed into service in 2024, specifically our Pico digestion capacity increase and Raeger capital improvement projects.

Impairment loss

We calculated and recorded impairment losses of $1,586 for 2024, an increase of $684 (75.8%) compared to $902 for 2023. The impairment losses in 2024 primarily relate to the remaining book value of assets at the Security facility, various RNG equipment that

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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. The 2023 impairment losses relate to specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use.

Other Expenses

Other expenses in 2024 were $3,946, a decrease of $1,328 (25.2%) compared to $5,274 in 2023. The decrease was primarily related to proceeds of $1,000 received from the sale of gas rights ahead of the fuel supply agreement expiration of our Security facility and decreased interest expense of $476.

Income Tax Expense

As of December 31, 2024 and 2023, we utilized all of our non-limited NOLs. A wholly-owned subsidiary continues to carry from 2023 to 2024 approximately $12,986 of federal net operating losses that are not expected to be realizable due to loss limitation rules.

As of December 31, 2024 and 2023, we had approximately $12,274 and $13,042, 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 2024, we continue to carry state NOL balances in Pennsylvania and Florida from 2023.

For the year ended December 31, 2024 and 2023, income tax expense was $2,443 and $3,418, respectively. The 2024 effective tax rate was 20.1% and the 2023 effective tax rate was 18.6%.

Operating Profit (Loss) for the Years Ended December 31, 2024 and 2023

Operating profit in 2024 was $16,123, a decrease of $7,517 (31.8%) compared to $23,640 in 2023. RNG operating profit for 2024 was $56,032, a decrease of $3,254 (5.5%) compared to $59,286 in 2023. Renewable Electricity Generation operating loss for 2024 was $2,823, an increase of $2,228 (374.5%) compared to $595 in 2023.

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.

The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net income:

(1)
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. For the year ended

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December 31, 2023, we recorded an impairment of $902 for specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use.

Liquidity and Capital Resources

Sources of Liquidity

At December 31, 2024 and 2023, our cash and cash equivalents, net of restricted cash, was $45,621 and $73,811, respectively. We intend to fund development projects using cash flows from operations and borrowings under our revolving credit facility. We believe that we will have sufficient cash flows from operations and borrowing availability under our credit facility to meet our debt service obligations and anticipated required capital expenditures (including for projects under development) for the next 12 to 24 months. However, we are subject to business, operational, and political risks that could adversely affect our cash flows and liquidity.

At December 31, 2024, we had debt before debt issuance costs of $56,000, compared to debt before debt issuance costs of $64,000 at December 31, 2023.

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

Amended Credit Agreement

On December 21, 2021, the Company entered into the Fourth 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.

As of December 31, 2024, $56,000 was outstanding under the term loan and we had no outstanding borrowings under the revolving credit facility. The term loan amortizes in quarterly installments of $2,000 through December 2024, quarterly installments of $3,000 from 2025 through maturity, with a final payment of $32,000, on December 21, 2026. Interest rates were 6.01% and 6.11% at December 31, 2024 and 2023, 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 September 30, 2024. 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.

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

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

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

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

As of December 31, 2024, we were in compliance with all financial covenants related to the Amended Credit Agreement.

For additional information regarding the Amended Credit Agreement, see the sections entitled “Description of Indebtedness" and Note 13 to our audited consolidated financial statements.

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Capital Expenditures

We have historically funded our growth and capital expenditures with our working capital, cash flow from operations and debt financing. We expect our non-development 2025 capital expenditures to range between $14,000 and $17,000. Our 2025 non-development capital plans include preventative maintenance expenditures, wellfield expansion projects, critical spare expenditures, other specific facility improvements, and information technology improvements. Additionally, we currently estimate that our existing 2025 development capital expenditures will range between $100,000 and $150,000. The majority of our 2025 development capital expenditures relate to our ongoing development of Montauk Ag Renewables, the second Apex facility, Bowerman RNG project, and our EENA CO2 project. Our Amended Credit Agreement provides us with a $120,000 revolving credit facility, with a $75,000 accordion option, providing us with access to additional capital to implement our acquisition and development strategy. We are currently in various stages of discussions regarding a variety of development and strategic growth opportunities. Development opportunities include: LFG RNG sites, waste water treatment RNG locations, and CNG distribution opportunities. If we ultimately enter into definitive agreements for any of these opportunities, we expect to incur material capital expenditures related to either acquisitions costs or development costs, or both. As we continue to explore strategic growth opportunities and while we have entered into nonbinding letters of intent for certain of these opportunities, we provide no assurances that our plans related to any or all of these strategic opportunities will progress to definitive agreements. We believe that our existing cash and cash equivalents, cash generated from operations, and credit availability under our Amended Credit Agreement would allow us to pursue and close on our identified strategic growth opportunities in addition to the previously discussed non-development and development capital expenditures.

Cash Flow

The following table presents information regarding our cash flows and cash equivalents for years ended December 31, 2024 and 2023:

For the year ended December 31, 2024, we generated $43,795 of cash from operating activities, a 6.7% increase compared to $41,053 for the year ended December 31, 2023. For the year ended December 31, 2024, income and adjustments to income from operating activities provided $44,961 compared to $49,896 in 2023. Working capital and other assets and liabilities used $1,166 in 2024 compared to $8,843 in 2023.

Our net cash flows used in investing activities has historically focused on project development and facility maintenance. 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. For 2023, our capital expenditures were $63,091, of which $18,593, $13,655, and $13,092, were related to the ongoing development of the Montauk Ag Renewables, Pico facility digestion capacity increase and second Apex RNG facility, respectively.

Our net cash flows used in financing activities of $9,842 for 2024 increased by $512 compared to cash used in financing activities of $9,330 in 2023.

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 current principal balance and accrued interest is 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

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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 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. Refer to Note 22 – Subsequent Events for further information.

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 2024, we had $2,185 of off-balance sheet arrangements of outstanding letters of credit. These letters of credit reduce the borrowing capacity of our revolving credit facility under our Amended Credit Agreement. Certain of our contracts require these letters of credit to be issued to provide additional performance assurances. There have been no usage against these outstanding letters of credit. During 2023, we did not have off-balance sheet arrangements other than outstanding letters of credit of approximately $2,505.

We have contractual obligations involving operating leases. 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 3-19 years. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,695.