MNTK US Equity☆

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this Annual Report on Form 10-K.

In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A.–Risk Factors” and elsewhere in this report.

This section generally discusses our results of operations for the year ended December 31, 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 , 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.

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:

Blue Granite RNG Facility 900 Delayed TBD

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 EnvironmentalAttributes derived from RNG, such as RINs and LCFS credits. Our RNG revenues from Environmental Attributes are recorded net of a portion of Environmental Attributes shared with off-take counterparties as consideration for such counterparties using the RNG as a transportation fuel. We had certain pathway provider sharing arrangements expiring throughout 2024. 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 andsale of the Environmental Attributes, such as RECs, derived from Renewable Electricity. All of our Renewable Electricity production is monetized under fixed-price PPAs from our existing operating projects.

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

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 ofour or a landfill operator’s equipment or interconnection or transmission problems could result in a reduction of our RNG production. We strive to proactively address any issues that may arise through preventative maintenance, process improvement and flexible redeployment of equipment to maximize production and useful life.

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In 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 projectsites is subject to change based on the volume and type of waste accepted. Variations in the quality of the biogas could affect our RNG production levels. At three of our projects, we operate the wellfield collection system, which allows greater control over the quality and consistency of the collected biogas. At 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 totake in additional waste and the amount of gas available for collection increases. Delays in commencement of production or extended commissioning issues at a new project or a conversion project, such as those 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 structuredas a percentage of revenue. Transportation and gathering expenses include capacity and metering expenses representing the costs of delivering our RNG and Renewable Electricity production to our customers. These expenses include payments to pipeline operators and other agencies that allow for the transmission of our gas and electricity commodities to end users. Production fuel expenses generally represent alternative royalty payments based on quantity usage of biogas feedstock.

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General and Administrative Expenses: General and administrative expenses primarily consist of corporate expenses and unallocated support functions for our operating facilities, including personnel costs for executive, finance, accounting, investor relations, legal, human resources, operations, engineering, environmental registration and reporting, health and safety, IT and other administrative personnel and professional fees and general corporate expenses. From time to time, we may be parties to legal proceedings arising in the normal course of business which could increase our legal expenses. We continue to 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 significantcapital to build and own our facilities. In addition to development capital, we annually reinvest to maintain these facilities.

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

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

Key Operating Metrics

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

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Production Volumes: We review performance by site based on unit of production calculations for RNG and Renewable Electricity, measured interms of MMBtu and MWh, respectively. While unit of production measurements can be influenced by schedule facility maintenance schedules, the metric is used to measure the efficiency of operations and the impact of optimization improvement initiatives. We monetize a majority of our RNG commodity production under variable-price agreements, based on indices. A portion of our Renewable Natural Gas segment commodity production is monetized under fixed-priced contracts. Our Renewable Electricity Generation segment commodity production is primarily monetized under fixed-priced PPAs.

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Production of Environmental Attributes: We monetize Environmental Attributes derived from our production of RNG and Renewable Electricity.We 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 theEnvironmental 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.

For the year ended December 31, Change

(in thousands, unless otherwise indicated)

Revenues

RNG Metrics

Plus: Prior period RNG volumes dispensed in current period 358 368 (10 ) (2.7 %)

Total RNG volumes available for RIN generation (1) 4,108 4,222 (114 ) (2.7 %)

RIN Metrics

Plus: Prior period RINs carried into current period 108 739 (631 ) (85.4 %)

RIN Inventory — — — 0.0 %

RNG Inventory (volumes not dispensed for RINs) (4) 291 358 (67 ) (18.7 %)

Operating Expenses

Operating Expenses per MMBtu (actual) $ 14.84 $ 14.69 $ 0.15 1.1 %

Other Metrics

Renewable Electricity Generation Volumes Produced (MWh) 186 194 (8 ) (4.1 %)

Average Realized Price $/MWh (actual) $ 95.45 $ 95.10 $ 0.35 0.4 %

(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:

For the year ended December 31, Change

Operating expenses:

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:

For the year ended December 31,

Depreciation, depletion and amortization 23,515 21,158

Net loss of sale of assets — 94

(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:

Revolving credit facility — —

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,

Net cash provided by (used in):

Net decrease in cash and cash equivalents (28,238 ) (31,364 )

Restricted cash, end of the period 383 431

Cash and cash equivalents, end of period 46,004 74,242

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.

Internal Control Over Financial Reporting

There were no changes during 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Critical Accounting Policies and Estimates

Our consolidated financial statements are prepared in conformity with GAAP and require our management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, costs and expenses and related disclosures. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and such estimates may change if the underlying conditions or assumptions change.

Revenue Recognition

Our revenues are comprised of renewable energy and the related Environmental Attribute sales provided under a variety of short-term and medium-term agreements with our customers. All revenue is recognized when we satisfy our performance obligation(s)

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under the contract (either implicit or explicit) by transferring the promised product to the customer either when (or as) the customer obtains control of the product. A performance obligation is a promise in a contract to transfer a distinct product or service to a customer. A contract’s transaction price is allocated to each distinct performance obligation. We allocate the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract.

Revenue is measured as the amount of consideration we expect to receive in exchange for transferring our products. As such, revenue is recorded net of allowances and customer discounts as well as net of transportation and gathering costs incurred. To the extent applicable, sales, value add, and other taxes collected from customers and remitted to governmental authorities are accounted for on a net (excluded from revenues) basis.

The nature of our contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of our influence as the variable consideration is dictated by the market. Therefore, the variable consideration associated with the long-term contracts is considered fully constrained. Refer to Item 7A for an estimate of the impact of decreases in the wholesale price of gas on our operating profit.

RINs

We generate D3 RINs through our production and sale of RNG used for transportation purposes as prescribed under the RFS program. Our operating costs are associated with the production of RNG. The RINs are government incentives that are generated through our renewable operating projects and not a result of physical attributes of our RNG production. The RINs that we generate are able to be separated and sold as credits independently from the energy produced. Therefore, no cost is allocated to the RIN when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred. We enter into forward commitments to transfer RINs. These forward commitments are based on D3 RIN index prices at the time of the commitment. Realized prices for RINs monetized in a year may not correspond directly to index prices due to the forward selling of commitments. Refer to Item 7A for an estimate of the impact of decreases in the realized price per RIN on our operating profit.

RECs

We generate RECs through our production and conversion of landfill methane into Renewable Electricity in various states, including California and Oklahoma. These states have various laws requiring utilities to purchase a portion of their energy from renewable resources. Our operating costs are associated with the production of Renewable Electricity. The RECs are generated as an output of our renewable operating projects. The RECs that we generate are able to be separated and sold independently from the electricity produced. Therefore, no cost is allocated to the REC when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred.

Income Taxes

We are subject to income taxes in the U.S. federal jurisdiction and various state and local jurisdictions. Tax regulations within each jurisdiction are subject to the interpretation of the related tax laws and regulations and require significant judgment to apply.

Our net deferred tax asset position is a result of NOLs, fixed assets, intangibles, and tax credit carryforwards. The realization of deferred tax assets is dependent upon our ability to generate sufficient future taxable income during the periods in which those temporary differences become deductible, prior to the expiration of the tax attributes. The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in our financial statements or tax returns and forecasting future profitability by tax jurisdiction.

We evaluate our deferred tax assets at reporting periods on a jurisdictional basis to determine whether adjustments to the valuation allowance are appropriate considering changes in facts or circumstances. As of each reporting date, management considers new evidence, both positive and negative, when determining the future realization of our deferred tax assets. We account for uncertain tax positions using a “more-likely-than-not” threshold for recognizing and resolving uncertain tax positions. The evaluation of uncertain tax positions is based on factors that include, but are not limited to, changes in tax law, the measurement of tax positions taken or expected to be taken in tax returns, the effective settlement of matters subject to audit, new audit activity and changes in facts or circumstances related to a tax position. Given our current level of pre-tax earnings and forecasted future pre-tax earnings, we expect to generate income before taxes in the United States in future periods at a level that would fully utilize our U.S. federal NOL carryforwards and the majority of its state NOL carryforwards prior to their expiration. See Note 14 to our audited consolidated financial statements for additional information.

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Intangible Assets

Separately identifiable intangible assets are recorded at their fair values upon acquisition. We account for intangible assets in accordance with ASC 350, Intangibles—Goodwill and Other. Finite-lived intangible assets include interconnections, customer contracts, and trade names and trademarks. The interconnection intangible asset is the exclusive right to utilize an interconnection line between the operating project and a utility substation to transmit produced electricity. Included in that right is full maintenance provided on this line by the utility. Intangible assets with finite useful lives are amortized on a straight-line basis over their estimated useful life. We evaluate our finite-lived intangible assets for impairment as events or changes in circumstances indicate the carrying value of these assets may not be fully recoverable. Events that could result in an impairment include, among others, a significant decrease in the market price or the decision to close a site.

Indefinite-lived intangible assets are not amortized and include emission allowances and land use rights. Emission allowances consist of credits that need to be applied to nitrogen oxide (“NOx”) emissions from internal combustion engines. These engines emit levels of NOx for which environmental permits are required in certain regions in the United States. Except for permanent allocations of NOx credits, allowances available for use each year are capped at a level necessary for ozone attainment per the National Ambient Air Quality Standards. We assess the impairment of intangible assets that have indefinite lives at least on an annual basis or whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable.

If finite-lived or indefinite-lived intangible assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. The fair value is determined based on the present value of expected future cash flows. We use our best estimates in making these evaluations, however, actual future pricing, operating costs and discount rates could vary from the assumptions used in our estimates and the impact of such variations could be material.

Our assessment of the recoverability of finite-lived and indefinite-lived intangible assets is determined by performing monitoring assessment of the future cash flows associated with the underlying gas rights agreements. The cash flows estimates are performed at the operating unit level and based on the average remaining length of the gas rights agreements. Based on our analysis, we concluded the cashflows generated to be well in excess of the carrying amounts. Changes in market conditions related to the various price indexes used in estimating these cash flows could adversely effect these estimates.

Finite-Lived Asset Impairment

In accordance with FASB ASC Topic 360, Property, Plant and Equipment and intangible assets with finite useful lives are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by comparing the carrying amount of an asset or asset group to future undiscounted cash flows expected to be generated by the asset or asset group. Such estimates are based on certain assumptions, which are subject to uncertainty and may materially differ from actual results, including considering project specific assumptions for long-term credit prices, escalated future project operating costs and expected site operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Fair value is generally determined by considering (i) internally developed discounted cash flows for the asset group, (ii) third-party valuations, and/or (iii) information available regarding the current market value for such assets. We use our best estimates in making these evaluations and consider various factors, including future pricing and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates and the impact of such variations could be material. Based on our annual cash flow assessment conduction for monitoring potential indicators of impairment, we concluded the cashflows to be generated are significantly in excess of their carrying value of our operating sites primarily due to the lengths of the underlying gas rights agreements.

As to the remaining long lived asset groups, the Company further concluded, based on our annual cashflow assessment conducted for monitoring potential indicators of impairment, that the cashflows to be generated are significantly in excess of their carrying values of our operating sites primarily due to the lengths of the underlying gas rights agreements and the Company did not record any other impairments related to its cash flows assessment. Separate from our cash flows assessment, we identified discrete events and recorded impairment of We identified discrete events and recorded impairment of $1,586 and $902 for 2024 and 2023, respectively. See Note 3 to our audited consolidated financial statements for further information related to asset impairments.

Emerging Growth Company

We are an emerging growth company, as defined in the JOBS Act. The JOBS Act allows emerging growth companies to delay the adoption of new or revised accounting standards until such time as those standards apply to private companies. We intend to utilize these transition periods, which may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the transition periods afforded under the JOBS Act.

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Recent Accounting Pronouncements

For a description of our recently adopted accounting pronouncements and recently issued accounting standards not yet adopted, see Note 2 to our consolidated financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are exposed to market risks related to Environmental Attribute pricing, commodity pricing, changes in interest rates and credit risk with our contract counterparties. We currently have no foreign exchange risk and do not hold any derivatives or other financial instruments purely for trading or speculative purposes.

We employ various strategies to economically hedge these market risks, including derivative transactions relating to commodity pricing and interest rates. Any realized or unrealized gains or losses from our derivative transactions are reported within corporate revenue in our consolidated financial statements. For information about our realized or unrealized gains or losses with respect to our derivative transactions and the fair value of such financial instruments, see Note 10 and Note 11 to our audited consolidated financial statements.

RIN and Environmental Attribute Pricing Risk

We attempt to negotiate the best prices for our Environmental Attributes and to competitively price our products to reflect the fluctuations in market prices. Reductions in the market prices of Environmental Attributes may have a material adverse effect on our revenues and profits as they directly reduce our revenues. To manage this market risk, we use a mix of short-, medium-, and long-term sales contracts and sell a portion of our Environmental Attributes at fixed-prices, through floor-price margin share agreements and pursuant to forward contracts with terms between one and two years. We also sell our Environmental Attributes bundled with RNG in contracts between two to five years.

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to RIN prices. Our analysis, which may differ from actual results, was based on a 2025 estimated D3 RIN Index price of approximately $2.42 and our actual 2024 RINs sold. The estimated annual impact of a hypothetical 10% decrease in the average realized price per RIN would have a negative effect on our operating profit of approximately $7.0 million.

RNG and Renewable Electricity Pricing Risk

The price of RNG and Renewable Electricity changes in relation to the market prices of wholesale gas and wholesale electricity, respectively. Pricing for wholesale gas and wholesale electricity is volatile and we expect this volatility to continue in the future. Further, volatility of wholesale gas and electricity prices also creates volatility in the prices of Environmental Attributes.

We use a mix of short-, medium-, and long-term sales contracts and commodity hedging derivatives to manage our exposure to our pricing risk. We did not enter into a derivative contract to hedge a portion of our RNG production for 2024 or 2023.

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to the market price of wholesale gas. Our analysis, which may differ from actual results, was based on a 2025 estimated NYMEX average Index Price of approximately $3.851/MMBtu and our actual 2024 gas production sold pursuant to contracts that do not provide for a fixed or floor price. The estimated annual impact of a hypothetical 10% decrease in the market price of wholesale gas would have a negative effect on our operating profit of approximately $1.2 million.

Interest Rate Risk

In order to maintain liquidity and fund a portion of development and working capital needs, we have the Amended Credit Facility, which bears a variable interest rate based on SOFR index rate plus a margin based on our Total Leverage Ratio (in each case, as those terms are defined in the Amended Credit Agreement). We use interest rate swaps to set the variable interest rates under the Amended Credit Facility at a fixed interest rate to manage our interest rate risk.

As of December 31, 2024, we had $56.0 million outstanding under the Amended Credit Facility. Our weighted average interest rate on variable debt balances during 2024 was approximately 6.01%. We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to changes in interest rates. Based on our analysis, which may differ from actual results, a hypothetical increase in our effective borrowing rate of 10% would not have a material effect on our annual interest expenses and consolidated financial statements.

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Credit Risk

We have certain financial and derivative instruments that subject us to credit risk. These consist of our commodity hedging derivatives and interest rate swaps contracts. We are exposed to credit losses in the event of non-performance by the counterparties to our financial and derivative instruments.

We are also subject to credit risk due to concentration of our RNG receivables with a limited number of significant customers. This concentration increases our exposure to credit risk on our receivables, since the financial insolvency of these customers could have a significant impact on our results of operations.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Page

Montauk Renewables, Inc.

Audited Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248) 59

Consolidated Balance Sheets as of December 31, 2024 and 2023 60

Notes to Consolidated Financial Statements 65

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Montauk Renewables, Inc.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Montauk Renewables, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2024 and 2023, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.

Change in accounting principle

As discussed in Note 2 to the consolidated financial statements, the Company has adopted new accounting guidance in 2024 related to the disclosure of segment information in accordance with ASU 2023-07, Segment Reporting (Topic 280). The adoption was retrospectively applied to 2023 and 2022.

Basis for opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2007.

Pittsburgh, Pennsylvania

March 14, 2025

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MONTAUK RENEWABLES, INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except per share data)

as of December 31,

Current assets:

Current restricted cash 8 8

Income tax receivable 41 —

Current portion of derivative instruments 471 785

Prepaid insurance and other current assets 2,911 2,819

Non-current restricted cash $ 375 $ 423

Non-current portion of derivative instruments 298 470

Operating lease right-of-use assets 7,064 4,313

Finance lease right-of-use assets 110 36

Related party receivable — 10,138

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:

Related party payable 625 —

Income tax payable — 313

Current portion of operating lease liability 2,049 420

Current portion of finance lease liability 76 26

Current portion of long-term debt 11,853 7,886

Long-term debt, less current portion $ 43,763 $ 55,614

Non-current portion of operating lease liability 5,138 4,133

Non-current portion of finance lease liability 36 10

Commitments and contingencies (Note 20)

STOCKHOLDERS’ EQUITY

Total liabilities and stockholders' equity $ 349,015 $ 350,238

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

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MONTAUK RENEWABLES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

For The Year Ended December 31,

Operating expenses:

Royalties, transportation, gathering and production fuel 31,502 34,861 44,163

Gain on insurance proceeds — — (313 )

Other expenses (income):

Income per share:

Weighted-average common shares outstanding:

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

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MONTAUK RENEWABLES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Common stock Treasury stock

Vesting of stock awards 618,204 6 — — — — 6

Stock-based compensation — — — — 9,836 — 9,836

Vesting of stock awards 352,772 4 — — — — 4

Stock-based compensation — — — — 8,318 — 8,318

Vesting of stock awards 725,608 6 — — — — 6

Consolidation of VIE — — — — (2,432 ) — (2,432 )

Stock-based compensation — — — — 9,959 — 9,959

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

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MONTAUK RENEWABLES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands): For The Year Ended December 31,

Cash flows from operating activities:

Gain on property insurance proceeds — — (313 )

Derivative mark-to-market adjustments and settlements 486 560 (2,652 )

Net loss on sale of assets — 94 (233 )

(Decrease) increase in earn-out liability (1,703 ) 1,266 1,122

Accretion of asset retirement obligations 445 407 296

Liabilities associated with properties sold (225 ) — —

Amortization of debt issuance costs 360 367 412

Cash provided (used) by changes in assets and labilities:

Royalty offset long term receivable (3,089 ) (3,515 ) —

Accounts payable and Accrued liabilities (2,298 ) 1,326 3,467

Cash flows from investing activities:

Asset acquisition (820 ) — —

Cash collateral deposits (48 ) 2 82

Proceeds from insurance recovery — — 313

Cash flows from financing activities:

Common stock issuance 6 4 6

Related party receivable — (1,138 ) —

Finance lease payments (68 ) (74 ) (47 )

Net cash used in financing activities $ (9,842 ) $ (9,330 ) $ (8,279 )

Reconciliation of cash, cash equivalents, and restricted cash at end of period:

Restricted cash and cash equivalents - current 8 8 22

Restricted cash and cash equivalents - non-current 375 423 407

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

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MONTAUK RENEWABLES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For The Year Ended December 31,

Supplemental cash flow information:

Non-cash purchase of Treasury stock 8,309 — —

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

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MONTAUK RENEWABLES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—DESCRIPTION OF BUSINESS

Operations and organization

Montauk Renewables’ Business

Montauk Renewables, Inc. (the “Company” or “Montauk Renewables”) is a renewable energy company specializing in the management, recovery and conversion of biogas into Renewable Natural Gas (“RNG”). The Company captures methane, preventing it from being released into the atmosphere, and converts it into either RNG or electrical power for the electrical grid (“Renewable Electricity”). The Company, headquartered in Pittsburgh, Pennsylvania, has more than 30 years of experience in the development, operation and management of landfill methane-fueled renewable energy projects. The Company has current operations at 13 operating projects located in California, Idaho, Ohio, Oklahoma, Pennsylvania, North Carolina and Texas. The Company sells RNG and Renewable Electricity, taking advantage of Environmental Attribute premiums available under federal and state policies that incentivize their use.

Two of the Company’s key revenue drivers are sales of captured gas and sales of Renewable Identification Numbers (“RINs”) to fuel blenders. The Renewable Fuel Standard (“RFS”) is an Environmental Protection Agency (“EPA”) administered federal law that requires transportation fuel to contain a minimum volume of renewable fuel. RNG derived from landfill methane, agricultural digesters and wastewater treatment facilities used as a vehicle fuel qualifies as a D3 (cellulosic biofuel with a 60% greenhouse gas reduction requirement) RIN. The RINs are compliance units for fuel blenders that were created by the RFS program in order to reduce greenhouse gases and imported petroleum into the United States.

An additional program utilized by the Company is the Low Carbon Fuel Standard (“LCFS”). This is state specific and is designed to stimulate the use of low-carbon fuels. To the extent that RNG from the Company’s facilities is used as a transportation fuel in states that have adopted an LCFS program, it is eligible to receive an Environmental Attribute additional to the RIN value under the federal RFS.

Another key revenue driver is the sale of captured electricity and the associated environmental premiums related to renewable sales. The Company’s electric facilities are designed to conform to and monetize various state renewable portfolio standards requiring a percentage of the electricity produced in that state to come from a renewable resource. Such premiums are in the form of Renewable Energy Credits (“RECs”). The Company’s largest electric facility, located in California, receives revenue for the monetization of RECs as a part of a purchase power agreement.

Collectively, the Company benefits from federal and state government incentives in the United States, provided in the form of RINs, RECs, LCFS credits, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects, that promote the use of renewable energy, as Environmental Attributes.

Background and Reorganization Transactions

On January 4, 2021, the Company, Montauk Holdings Limited (“MNK”) and Montauk Holdings USA, LLC (a direct wholly-owned subsidiary of MNK at the time, “Montauk USA”) entered into a series of transactions, including an equity exchange and a distribution collectively referred to as the “Reorganization Transactions,” that resulted in the Company owning all of the assets and entities (other than Montauk USA) previously owned by Montauk USA, and Montauk Renewables became a direct wholly-owned subsidiary of MNK. Prior to the Reorganization Transactions, MNK’s business and operations were conducted entirely through Montauk USA and its U.S. subsidiaries, and MNK held no substantial assets other than equity of Montauk USA. The Company had no significant operations or assets prior to January 4, 2021 when it engaged in the equity exchange with Montauk USA and MNK.

After completion of the Reorganization Transactions, (i) Montauk USA ceased to own any substantial assets and (ii) all entities through which MNK’s business and operations were conducted became owned, directly or indirectly, by the Company. MNK adopted a plan contemporaneously with the completion of the Reorganization Transactions that authorized the liquidation and dissolution of MNK.

On January 15, 2021, MNK sold the membership interest of Montauk USA to a third party. On January 26, 2021, MNK distributed all of the outstanding shares of the Company’s common stock as a pro rata dividend to the holders of MNK’s ordinary shares (the “Distribution”), subject to any tax withholding obligations under applicable South African law. Each ordinary share of MNK outstanding on January 21, 2021, the record date for the Distribution (the “Record Date”), entitled the holder thereof to receive one share of the Company’s common stock.

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On January 26, 2021, the Company closed the initial public offering of its common stock on the Nasdaq Capital Market (the “IPO”) with the shares traded under the symbol “MNTK”. Montauk Renewables issued 2,702,500 shares at $8.50 per share and received gross proceeds of $22,971. The Company’s common stock was also secondarily listed on the Johannesburg Stock Exchange (“JSE”) under the trading symbol “MKR”.

On January 26, 2021, the Company entered into a Loan Agreement and Secured Promissory Note (as amended on February 22, 2021, December 22, 2021, December 22, 2022, December 27, 2023 and March 5, 2025) with MNK pursuant to which the Company advanced a cash loan to MNK for MNK to pay its dividends tax liability arising from the Reorganization Transactions under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended. The terms of the loan following the amendments are substantially similar to the initial loan agreement and were primarily entered into to (1) increase the principal amount outstanding under the loan to $10,690 in the aggregate (2) extended the maturity date to December 31, 2033 also, in accordance with Montauk Renewables’ obligations set forth in the Transaction Implementation Agreement ("TIA"). MNK is currently an affiliate of the Company and certain of the Company’s directors are also directors of MNK. See Note 17 for more information.

MNK was delisted from the JSE on January 26, 2021. The MNK Board of Directors and Shareholders held its annual general meeting in March 2023 and voted to take MNK private.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The historical consolidated financial information included reflects the historical results of operations and financial position of Montauk USA through January 4, 2021 when MNK sold the membership interest of Montauk USA. The consolidated financial statements of Montauk USA became the Company’s historical financial statements following the IPO. Certain historical financial information included relates to periods prior to the Reorganization Transactions. On December 31, 2024, the Company re-assessed its determination of the primary beneficiary of the Variable Interest Entity ("VIE") MNK under the guidance in ASC 810, Consolidation. Refer to Note 17 – Related Parties for further information. All intercompany balances and transactions have been eliminated in consolidation.

The Company utilizes the equity method of accounting for companies where its ownership is greater than 50% and significant but controlling interest does not exist.

Retrospective Presentation of Ownership Related to the Reorganization Transactions

As discussed in Note 1, as a result of the Reorganization Transactions, the Company acquired the assets and entities (excluding Montauk USA) which were previously owned by MNK. As part of the Reorganization Transactions, a 1:1 pro rata distribution of shares of the Company’s common stock was made to holders of MNK’s ordinary shares. The Reorganization Transactions resulted in a pro rata distribution whereby the ownership of the Company after the Reorganization Transactions was identical to the ownership of MNK prior to the Reorganization Transaction and was therefore akin to a common control transaction. All member’s equity in the financial statements and notes have been retrospectively adjusted to give effect to the Distribution, as if such pro rata distribution on a 1:1 basis occurred as of all pre-IPO periods presented, including periods presented on the Consolidated Balance Sheets, Consolidated Statements of Operations, Consolidated Statements of Stockholders’ and Member’s Equity and notes to the Consolidated Financial Statements contained herein.

Reclassifications

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

Segment Reporting

The Company reports segment information in three segments: RNG, Renewable Electricity Generation and Corporate. This is consistent with the internal reporting provided to the chief operating decision maker who evaluates operating results and performance. The aforementioned business services and offerings described in Note 1 are grouped and defined by management as two distinct operating segments: RNG and Renewable Electricity Generation. Below is a description of the Company’s operating segments and other activities.

The RNG segment represents the sale of gas sold at fixed-price contracts, counterparty share RNG volumes and applicable Environmental Attributes. This business unit represents the majority of the revenues generated by the Company. The Renewable Electricity Generation segment represents the sale of captured electricity and applicable Environmental Attributes. Corporate & Other

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relates to additional discrete financial information for the corporate function. It is primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering and other operations functions not otherwise allocated to a segment. As such, the corporate entity is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation to the Company’s consolidated financial statements.

Use of Estimates

The preparation of financial statements, in conformity with accounting principles generally accepted in the United States (“GAAP”), requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents include highly liquid investments with maturity dates of three months or less from the date of purchase and are recorded at cost. The Company may hold cash in excess of federally insured limits. Restricted cash is classified as current or non-current based on the terms of the underlying agreements and represents cash held as deposits, cash held in escrow and cash collateral for financial letters of credit.

Accounts and Other Receivables

Accounts and other receivables on the Consolidated Balance Sheets represent outstanding billings for goods and services delivered to customers on an unsecured basis as well as reimbursable expenses. In evaluating its allowance for doubtful accounts for accounts receivable, the Company performs ongoing reviews of its outstanding receivables to determine if any amounts are uncollectible and adjusts the allowance for doubtful accounts accordingly.

Property, Plant and Equipment

Property, plant and equipment purchases are stated at cost, except for asset retirement obligations, which are recorded at estimated fair value at inception date. Depreciation and amortization are based on costs less estimated salvage values, primarily using the straight-line method over the estimated useful lives or, if applicable, the term of the related gas rights agreements or power purchase agreements, whichever is shorter. Maintenance and repairs are expensed as incurred. Major improvements that extend the useful lives of property are capitalized.

The estimated useful lives of the Company’s property, plant and equipment reflect the expected consumption of the economic benefit of these assets as noted in the following table:

Buildings and improvements 5 - 30 years

Machinery and equipment 1 - 43 years

Gas mineral rights 15 - 25 years

$313 in insurance proceeds were received for the year ended December 31, 2022, related to an engine failure at an RNG Facility. These insurance proceeds are included in Gain on insurance proceeds for the year ended December 31, 2022, within the Consolidated Statements of Operations.

Goodwill and Intangible Assets

Goodwill is the cost of an acquisition less the fair value of the identified net assets of the acquired business.

Separately identifiable intangible assets are recorded at their fair values upon acquisition. The Company accounts for its intangible assets in accordance with ASC 350, Intangibles—Goodwill and Other (“ASC 350”). Finite-lived intangible assets include interconnections, customer contracts and trade names & trademarks. The interconnection intangible asset is the exclusive right to utilize an interconnection line between the operating plant and a utility substation to transmit produced natural gas and electricity. Included in that right is full maintenance provided on this line by the utility. Intangible assets with finite useful lives are amortized on a straight-line basis over their estimated useful life as depicted in the chart below. Indefinite intangible assets are not amortized and include emission allowances and land use rights.

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The estimated useful lives of separately identified intangible assets are as follows:

Interconnection 10 - 25 years

Customer contracts 2 - 15 years

Emissions allowances Indefinite

Land use rights Indefinite

Assets Held for Sale

Assets classified as held for sale are reported at the lower of their carrying value or fair value less costs to sell. Assets are classified as held for sale if their carrying amounts will be recovered through a sale transaction, rather than through continued use. This condition is met only when the sale is highly probable and the assets are available for immediate sale in their present condition, subject only to terms that are usual and customary for sales of such assets. Management must be committed to a sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale and actions required to complete the plan of sale indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. Impairment losses on initial classification as held-for-sale are recognized in the Consolidated Statement of Operations. Assets classified as held for sale are no longer depreciated or amortized.

Leases

The Company assesses leases in accordance with ASU 2016-02, Leases, (“ASU 2016-02”). This ASU requires lessees to recognize a right-of-use asset and lease liability on the Consolidated Balance Sheet for leases classified as either operating or finance leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize a right-of-use asset and lease liability. Additionally, when measuring assets and liabilities arising from a lease, optional payments should be included only if the lessee is reasonably certain to exercise an option to extend the lease, exercise a purchase option, or not exercise an option to terminate the lease. A right-of-use asset represents an entity’s right to use the underlying asset for the lease term, and a lease liability represents an entity’s obligation to make lease payments. The measurement, recognition and presentation of expenses and cash flows arising from leases by a lessee remains the same. The Company has included further lease disclosures in Note 19.

Long-lived Asset Impairment

In accordance with ASC 360, Property, plant, equipment and intangible assets with finite useful lives are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by comparing the carrying amount of an asset or asset group to future undiscounted cash flows expected to be generated by the asset or asset group. Such estimates are based on certain assumptions, which are subject to uncertainty and may materially differ from actual results. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets.

A summary of impairment losses on tangible and intangible assets for the year ended December 31, 2024, 2023 and 2022 is included in Note 3.

Indefinite-Lived Asset Impairment

Indefinite-lived intangible assets are required to be evaluated for impairment at least annually or whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable. The evaluation of impairment under ASC 350 requires the use of projections, estimates and assumptions as to the future performance of the Company’s operations, including anticipated future revenues, expected operating costs and the discount factor used. Actual results may differ from projections. If such indefinite-lived assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets.

Asset Retirement Obligations

The Company accounts for asset retirement obligations as required under ASC 410, Asset Retirement and Environmental Obligations, (“ASC 410”). ASC 410 requires the fair value of a liability for an asset retirement obligation be recognized in the period in which the legal obligation arises, with the associated discounted asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset and the annual accretion expense recorded in operations. The Company has recorded in the consolidated financial statements estimates for asset retirement obligations related to the decommissioning and removal requirements for specific gas processing and distribution assets, as required by their associated gas rights agreements.

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Revenue

The Company recognizes revenue in accordance with ASC 606, Revenue from Contracts with Customers(“ASC 606”). Revenue from the Company’s point in time product sales is recognized when products are transferred, or services are invoiced and control transferred. Revenue from the Company’s product and service sales provided under long-term agreements is recognized as the Company transfers control of the product or renders service to its customers, which approximates the time when the customer is invoiced. The Company has presented the disclosures required by ASC 606 in Note 4.

Income Taxes

The Company is treated as a corporation for income tax purposes. Therefore, income taxes are accounted for under the liability method on a consolidated basis by the Company and its consolidated subsidiaries in accordance with ASC 740, Income Taxes (“ASC 740”). Deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws. The provision for income taxes includes federal and state income taxes.

The Company recognizes the financial statement benefit of a tax position only after determining the relevant tax authority would more-likely-than-not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the consolidated financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company recognizes accrued interest and penalties related to unrecognized tax benefits in income tax expense.

Derivative Instruments

The Company applies the provisions of ASC 815, Derivatives and Hedging, (“ASC 815”). ASC 815 requires each derivative instrument to be recorded in the Consolidated Balance Sheets at its fair value. Changes in a derivative instrument’s fair value are recognized currently in earnings.

Fair Value of Financial Instruments

The Company employs varying methods and assumptions in estimating the fair value of each class of financial instruments for which it is practical to estimate fair value. For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value due to the short maturity of these instruments. For long-term debt, the carrying amounts approximate fair value as the interest rates obtained by the Company approximate the prevailing interest rates available to the Company for similar instruments.

In accordance with ASC 820, Fair Value Measurement (“ASC 820”), a hierarchy is established which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the assets and liabilities or can be corroborated with observable market data for substantially the entire contractual term of the assets or liabilities.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the assets or liabilities and are consequently not based on market activity but rather through particular valuation techniques. The Company uses the fair value methodology to value the assets and liabilities recorded at fair value, including the Company’s asset retirement obligations and earn out liability.

The values of the Level 2 interest rate derivatives were determined using a model, which incorporates market inputs including the implied forward interest rate yield curve for the same period as the future interest rate swap settlement. The Company has also considered both its own credit risk and counterparty credit risk in determining fair value and determined these adjustments were insignificant for the years ended December 31, 2024 and 2023. The Company’s asset retirement obligations are recorded at fair value at the time the liability is incurred if a reasonable estimate of fair value can be made. Fair value is determined by calculating the estimated present value of the cost to retire the asset as determined by qualified engineers, based on currently available information and inflation estimates and is considered a Level 3 measurement. The Company’s earn-out liability fair value is determined by calculating the estimated present value of future obligations based on currently available information and the discount factor used and is considered a Level 3 measurement.

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A summary of changes in the fair values of the Company’s Level 3 instruments, attributable to asset retirement obligations and the earn out liability, for the years ended December 31, 2024 and 2023 is included in Note 11.

Renewable Identification Numbers (“RINs”)

The Company generates D3 RINs through its production and sale of RNG used for transportation purposes as prescribed under the Federal Renewable Fuel Standard. The RINs that the Company generates as government incentives through its renewable operating projects can be separated and sold as credits independent from the energy produced and not a result of physical attributes of the Company’s production. Therefore, no cost is allocated to the RIN when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The Company had 6.8 and 0.1 million RINs generated and unsold as of December 31, 2024 and 2023, respectively.

Renewable Energy Credits (“RECs”)

The Company generates RECs through its production and sale of landfill methane into renewable electric energy as prescribed by the State of California Renewables Portfolio Standard or the EPA. The RECs that the Company generates as government incentives through its renewable operating projects are able to be separated and sold as credits independent from the electricity produced and not a result of physical attributes of the Company’s production. Therefore, no cost is allocated to the REC when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred.

Equity-Based Compensation

The Company accounts for equity-based compensation under the provisions of ASC 718, Compensation—Stock Compensation, (“ASC 718”). ASC 718 requires compensation costs related to share-based payment transactions, measured based on the fair value of the instruments issued, be recognized in the consolidated financial statements over the requisite service period of the award. Stock options are initially measured on the grant date using the Black-Scholes valuation model, which requires the use of subjective assumptions related to the expected stock price volatility, term, risk-free interest rate and dividend yield. For restricted stock shares, the Company determines the grant date fair value based on the closing market price of the stock on the date of the grant.

Employee Benefits

Leave entitlement

Employee entitlements to annual leave are recognized when they accrue to employees. An accrual is made for the estimated liability to the employees for annual leave up to the financial year end date. This liability is included in “Accrued liabilities” in the Consolidated Balance Sheets.

Bonus Plans

The Company recognizes a liability and an expense for incentive compensation bonuses awarded based on the achievement of Company and personnel goals where contractually obliged or where there is a past practice that has created a constructive obligation. An accrual is maintained for the appropriate proportion of the expected bonuses which would become payable at year end.

Recently Adopted Accounting Standards

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segments. The amendments in 2023-07 aim to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. ASU 2023-07 is effective for the Company's Annual Report on Form 10-K for the year ended December 31, 2024, and subsequent interim periods, with early adoption permitted. The amendments should be applied retrospectively to all prior periods presented in the financial statements. The Company has adopted the standard and the enhanced expense disclosures can be found in Note 18.

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848), which provides optional expedients and exceptions to the current guidance on contract modifications and hedging relationships to ease the financial reporting burdens of the expected market transition from London Interbank Offered Rate (“LIBOR”) and other interbank offered rates to alternative reference rates. The guidance was effective upon issuance and may be applied prospectively to contract modifications made and hedging relationships entered into or evaluated on or before December 31, 2022. The FASB included a sunset provision within Topic 848 based on expectations of when the LIBOR would cease being published. The sunset provision has been amended from December

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31, 2022, to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848. The Company’s current debt agreement bears interest at the Secured Overnight Financing Rate, "SOFR", plus an applicable margin.

Recently Issued Accounting Standards

In November 2024, the FASB issued ASU 2024-03, Income Statement — Reporting Comprehensive Income — Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. This ASU requires public business entities to disclose, on an annual and interim basis, disaggregated information about certain income statement expense line items. The ASU also requires disclosure of the total amount of selling expenses recognized in continuing operations on an annual and interim basis and disclosure of a public business entity’s definition of selling expenses on an annual basis (or in interim reporting periods if the definition is changed). Public business entities are required to apply the guidance prospectively but are permitted to apply it retrospectively. The ASU is effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments in 2023-09 aim to enhance the transparency and decision usefulness of income tax disclosures. ASU 2023-09 is effective for the Company's Annual Report on Form 10-K for the year ended December 31, 2025, with early adoption permitted. Other than enhanced disclosures, the Company does not expect a material impact from the adoption of this standard on its consolidated financial statements.

NOTE 3—ASSET IMPAIRMENT

The Company recorded $1,586, $902 and $4,852 in impairment losses for the years ended December 31, 2024, 2023 and 2022, respectively. In 2024, for one of its REG sites, the Company entered into a bill of sale, assignment and assumption agreement to sell its rights to the existing fuel supply agreement and property back to the site host in advance of the fuel supply agreement termination date and received $1,000 in proceeds. The effective date of the sale, assignment and assumption agreement was October 1, 2024. The Company elected to cease operations prior to the assignment date and consequently the remaining book value of long lived assets and intangibles were impaired for $312. The $1,000 in proceeds received was recognized as Other income in the Consolidated Statement of Operations. In addition, $329 in REG impaired assets were due to initial startup testing failures for one of its REG construction work in progress sites. Remaining 2024 impairments, $843 in RNG assets and $102 in REG assets, were for various equipment that was deemed obsolete or inoperable for current operations. 2023 impairments included $777 for specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use and recorded in the Company's RNG segment. The remaining $125 in impairments were for specifically identified obsolete REG critical spares. The 2022 impairments included $2,133 for a REG site wherein the forecasted future cash flows did not exceed the carrying value of the site’s long lived assets. A second REG site was impaired for $1,393 due to a discrete conclusion that certain assets acquired in the May 2021 Asset acquisition would no longer be utilized by the Company. An RNG site was impaired for $1,108 due to the specific identification of certain assets no longer capable of being used as designed. Additional impairments were recorded for computer software and hardware no longer being utilized, $191, and an amended customer contract, $27, no longer in use.

Impairment loss was recorded under Operating expenses within the Consolidated Statements of Operations for the years ended December 31, 2024, 2023, and 2022.

NOTE 4—REVENUES FROM CONTRACTS WITH CUSTOMERS

The Company’s revenues are comprised of renewable energy and related Environmental Attribute sales provided under short, medium and long term contracts with its customers. All revenue is recognized when (or as) the Company satisfies its performance obligation(s) under the contract (either implicit or explicit) by transferring the promised product or service to its customer either when (or as) its customer obtains control of the product or service. A performance obligation is a promise in a contract to transfer a distinct product or service to a customer. A contract’s transaction price is allocated to each distinct performance obligation. The Company allocates the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract. The Company's typical invoicing terms are payment due within 30 days.

Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring its products or services. As such, revenue is recorded net of allowances and customer discounts as well as net of transportation and gathering costs incurred by the customer following the transfer of control of the commodities sold. To the extent applicable, sales, value add and other taxes collected from customers and remitted to governmental authorities are accounted for on a net (excluded from revenues) basis.

The Company’s performance obligations related to the sale of renewable energy (i.e. RNG and Renewable Electricity) are generally satisfied over time. Revenue related to the sale of renewable energy is generally recognized over time using an output based upon the product quantity delivered to the customer. This measure is used to best depict the Company’s performance to date under the

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terms of the contract. Revenue from products transferred to customers over time accounted for approximately 26%, 24% and 29% of revenue for the years ended December 31, 2024, 2023 and 2022, respectively.

The nature of the Company’s long-term contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of the Company’s influence as the variable consideration is dictated by the market. Therefore, the variable consideration associated with the long-term contracts is considered fully constrained.

The Company’s performance obligations related to the sale of Environmental Attributes are generally satisfied at a point in time and were approximately 74%, 76% and 71% of revenue for the years ended December 31, 2024, 2023 and 2022, respectively. The Company recognizes Environmental Attribute revenue at the point in time in which the customer obtains control of the Environmental Attributes, which is generally when the title of the Environmental Attribute passes to the customer upon delivery. In limited cases, title does not transfer to the customer and revenue is not recognized until the customer has accepted the Environmental Attributes. The Company’s performance obligations under its counterparty sharing agreements are generally satisfied at a point in time when the earnings process is completed by the counterparty. Counterparty sharing arrangement revenues were approximately 0.4%, 0.0% and 0.6% of revenue for the years ended December 31, 2024, 2023 and 2022, respectively.

The following tables display the Company’s disaggregated revenue by major source, excluding realized and unrealized gains or losses under the Company’s gas hedge program, based on product type and timing of transfer of goods and services for the years ended December 31, 2024, 2023 and 2022:

Goods transferred at a point in time Goods transferred over time Total

Major goods/Service line:

Electric environmental attributes 7,586 — 7,586

Operating segment:

Goods transferred at a point in time Goods transferred over time Total

Major goods/Service line:

Electric environmental attributes 7,522 — 7,522

Operating segment:

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Goods transferred at a point in time Goods transferred over time Total

Major goods/Service line:

Electric environmental attributes 7,016 — 7,016

Operating segment:

Practical expedients and remaining performance obligations

The Company recognizes the sale of natural gas and electric commodities using the right to invoice practical expedient. The Company determined that the revenues recognized as of period end correspond directly with the value transferred to customers and the Company's satisfaction of the performance obligations to date. Furthermore, with the application of the right to invoice practical expedient and in consideration that contracts related to future environmental attributes sales do not exceed one year, there are no remaining unsatisfied or partially satisfied performance obligations as of December 31, 2024.

NOTE 5—ACCOUNTS AND OTHER RECEIVABLES

The Company extends credit based upon an evaluation of the customer’s financial condition. Credit terms are consistent with industry standards and practices. Accounts Receivable consist of sales to large creditworthy energy and utility companies. Reserves for uncollectible accounts, if any, are recorded as part of general and administrative expenses in the Consolidated Statements of Operations. No reserve expense was recorded for the years ended December 31, 2024, 2023 and 2022.

Accounts and other receivables consist of the following as of December 31, 2024, 2023 and 2022:

Reimbursable expenses 9 47 17

NOTE 6—ASSETS HELD FOR SALE

In 2021, the Company initiated a plan to sell nitrogen oxide (“NOx”) emissions allowances credits. The Company concluded that it met the criteria under applicable guidance for a long-lived asset to be held for sale, and accordingly reclassified the emissions allowances of $777 as current assets held for sale on the Consolidated Balance Sheet at December 31, 2021. The Company estimated the fair value of these assets and concluded that the fair value exceeded the carrying value and no impairment was recorded by the Company for the year ended December 31, 2021. In March 2022, the NOx emissions allowances credits were sold for $1,088. A $311 gain on sale of intangible assets was recorded for the year ended December 31, 2022.

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NOTE 7—PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant and equipment consists of the following as of December 31, 2024 and 2023:

Less: Accumulated depreciation and amortization (192,483 ) (175,482 )