Montauk Renewables, Inc.: Form 10-Q for the period ended Mar 31, 2025

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 Quarterly Report on Form 10-Q. Throughout this section, dollar amounts and production volumes are expressed in thousands, except for per share amounts and RIN pricing amounts and unless otherwise indicated.

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,” “Item 1A.–Risk Factors” of our 2024 Annual Report, and elsewhere in this report.

Overview

Montauk Renewables 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 operating portfolio of 11 RNG and two Renewable Electricity 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 or ADG. We typically secure our biogas feedstock through long-term fuel supply agreements and property lease agreements with biogas site hosts. Once we secure long-term fuel supply rights, we design, build, own, and operate facilities that convert the biogas into RNG or use the processed biogas to produce Renewable Electricity. We sell the RNG and Renewable Electricity through a variety of term length 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 renewable initiatives.

Our current operating projects produce either RNG or Renewable Electricity by processing biogas from landfill sites or agricultural waste from livestock farms. We view agricultural waste from livestock farms as a significant opportunity for us to expand our RNG business, and we continue to evaluate other agricultural feedstock opportunities. We believe that our business model and technology are highly scalable given availability of biogas from agriculturally derived sources, which will allow us to continue to grow through prudent development and complimentary acquisitions.

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 sold all 9,885 D3 RINs generated and available for sale from 2024 RNG production in the first quarter of 2025. The impact of EPA actions associated with implementation of BRRR K2 separation and the extension of the 2024 RIN compliance period has temporarily impacted the commitment timing of the Company. As a result, we have approximately 3,916 RINs in inventory from 2025 RNG production as March 31, 2025. We have subsequently entered into commitments to transfer the majority of our RINs in inventory as of March 31, 2025 at prices approximating to the D3 RIN index. The average D3 RIN index price for the first quarter of 2025 was approximately $2.43. The following table summarizes select historical data related to RINs generated, RINs sold, and RINs generated but unsold. As we self-market a significant portion of our RINs and as the RFS is based on annual compliance, any strategic decision to not monetize available RINs in a quarter could impact the timing of operating revenues recognized during a fiscal year. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The timing of RIN transfers can vary year over year and by period within a year and is contingent on various factors including, but not limited to: (a) the Company’s expectations on RIN index price, (b) operational needs of the Company, (c) obligated parties purchase needs, or (d) the type of customer among other matters.

Capital Development Summary

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

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 in commissioning stage which we expect to be complete in the second quarter of 2025.

Blue Granite RNG Project

In the first quarter of 2025, we received notice from the utility that it will no longer accept RNG into its distribution system, which was in opposition of the letter of intent that was issued when we were awarded the gas rights to the site. As a result, we impaired the capital associated with the early design of RNG equipment. We continue to review various alternatives related to interconnection opportunities as part of our considerations for offtake options with the understanding those alternatives may differ from initial development project assumptions, including physical and virtual and fixed interconnections. We are also reviewing alternatives for this site around producing energy other than RNG. We have paused further capital expenditures related to this site while we consider all alternatives.

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. We continue to work with the landfill host on the landfill’s management of its wellfield and flare facility permit requirements so that we continue 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.

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

Tulsa REG Conversion to RNG

In 2025, we announced the conversion of our Tulsa, Oklahoma Renewable Electric Generation facility to RNG project. The project will offer a variable inlet capacity 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. We expect to target a commissioning start in 2027 and expect to begin incurring capital expenditures for long lead items in the second quarter of 2025.

Montauk Ag Renewables 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, and micronutrient organic fertilizer alternatives (the “Montauk Ag Renewables Acquisition”).

With the change in REC generation passed by the state of North Carolina in 2024, we are in various other negotiations with other utility users to provide swine RECs from our expected first phase production of MWh. We continue to negotiate with potential power purchase agreement providers related to the resulting power generation derived from swine waste. We continue to test the most efficient methods of both collecting and transporting the swine feedstock from the collection farms to the centralized process location, including the removal of low energy content liquid waste. These methods include the pelletization of collected waste.

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 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.

Waste-stream Biogas Recovery

In October 2024, we announced a collaboration with Emvolon to transform methane emissions from waste stream biogas into high-value carbon negative fuel. Leveraging Emvolon's patented technology, the initial pilot is a small-scale demonstration of recovering and converting biogas into green methanol. The pilot project at our Atascocita facility in Houston, TX continues with Emvolon having installed their patented containerized processing technology. We do not expect short term financial benefits from this demonstration nor a disruption to our operations.

Key Trends

Market Trends Affecting the Renewable Fuel Market

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

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

• 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).
• 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.
• 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.
• 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:

• 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.
• 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.
• 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 final rule also included significant changes to the existing RFS 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 expected to target May 2025 to propose RFS obligations for 2026 and 2027. On December 12, 2024, the EPA proposed a partial waiver of 2024 Cellulosic Biofuel Volume Requirements due to the projected shortfall of D3 RINs available to meet the 2024 RVO. This proposal is still pending, and it is unknown when this proposed rule will be finalized (if at all) in 2025.

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. CARB submitted a third notice of proposed regulations for amendments on April 11, 2025. 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.

The BRRR requires that all unseparated K3 RINs generated by the RNG producer on RNG volumes injected into the commercial pipeline distribution system only become valid for sale once they are separated with the support of dispensing statements by a registered dispenser or RIN separator. This process could result in delays to the RNG producer's receipt of the separated K2 RINs from the dispenser. This rule change could also result in a RNG producer's failure to generate K3 RINs for a given gas flow month if the registered biogas producer negligently fails to generate the necessary biogas tokens before the end of the subsequent gas flow month. We expect this initial year impact of the EPA BRRR rule will increase our RINs unsold at the end of 2025.

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 segment is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation to the Company’s consolidated financial statements.

• Renewable Natural Gas Revenues: We record revenues from the production and sale of RNG and the generation and sale of the Environmental Attributes derived from RNG, such as RINs and LCFS credits. Our RNG revenues from Environmental Attributes are recorded net of a portion of Environmental Attributes shared with off-take counterparties as consideration for such counterparties using the RNG as a transportation fuel. We had certain pathway provider sharing arrangements expiring throughout 2024 and in 2025. While we have not yet experienced a significant increase in Environmental Attributes shared with pathway providers in our 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.
• Renewable Electricity Generation Revenues: We record revenues from the production and sale of Renewable Electricity and the generation and sale of the Environmental Attributes, such as RECs, derived from Renewable Electricity. All of our Renewable Electricity production is monetized under fixed-price PPAs from our existing operating projects.
• Corporate Revenues: Corporate reports realized and unrealized gains or losses under our gas hedge programs. The Company does not have any active gas hedge programs. Corporate also relates to additional discrete financial information for the corporate function; primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering and other operations functions not otherwise allocated to a segment.

Our operating revenues are priced based on published index prices which can be influenced by factors outside our control, such as market impacts on commodity pricing and regulatory developments. With our royalty payments structured as a percentage of revenue, royalty payments fluctuate with changes in revenues. We place a primary focus on managing production volumes and operating and maintenance expenses as these factors are more controllable by us.

RNG Production

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

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

• 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.
• 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 were impacted during 2024. Mitigation efforts related to wellfield environmental factors continue in 2025 as the benefits from 2024 efforts did not achieve anticipated results.
• Related to our gas rights agreement with our landfill host at our Rumpke RNG location, in 2025, we began the process of the relocation of our existing Rumpke RNG facility. The timing of this project and requirement to relocate the facility coincides with the landfills filling practices to move into the existing area of our now current Rumpke RNG facility and is contractually obligated. We expect to begin capital expenditures for long lead time equipment in the second quarter of 2025 and expect to target a commissioning in 2028. Depending on the timing of capital expenditure and potential other production capabilities in addition to RNG production related to the full design, we estimate capital expenditures to range between $80,000 - $110,000. This project is included within our 2025 development capital expenditures.
• 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 in 2025.
• 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.
• Quality of Biogas: We are reliant upon the quality and availability of biogas from our site partners. The quality of the waste at our landfill project sites is subject to change based on the volume and type of waste accepted. Variations in the quality of the biogas could affect our RNG production levels. At three of our projects, we operate the wellfield collection system, which allows greater control over the quality and consistency of the collected biogas. At two of our projects, McCarty and Galveston, we have operating and management agreements by which we earn revenue for managing the wellfield collection systems. Additionally, our dairy farm project benefits from the consistency of feedstock and controlled environment of collection of waste to improve biogas quality.
• RNG Production from Our Growth Projects: We anticipate increased production at certain of our existing projects as open landfills continue to take in additional waste and the amount of gas available for collection

increases. Delays in commencement of production or extended commissioning issues at a new project or a conversion project, such as those we are currently experiencing at Blue Granite as described above, would delay any realization of production from that project.

Pricing

Our Renewable Natural Gas and Renewable Electricity Generation segments’ revenues are primarily driven by the prices under our off-take agreements and PPAs and the amount of RNG and Renewable Electricity that we produce. We sell the RNG produced from our projects under a variety of short-term and medium-term agreements to counterparties, with contract terms varying from three years to five years. Our contracts with counterparties are typically structured to be based on varying natural gas price indices for the RNG produced. All of the Renewable Electricity produced at our biogas-to-electricity projects is sold under long-term contracts to creditworthy counterparties, typically under a fixed price arrangement with escalators.

The pricing of Environmental Attributes, which accounts for a substantial portion of our revenues, is subject to volatility based on a variety of factors, including regulatory and administrative actions and commodity pricing.

The sale of RINs, which is subject to market price fluctuations, accounts for a substantial portion of our revenues. We manage against the risk of these fluctuations through forward sales of RINs, although currently we only sell RINs in the calendar year they are generated. We have subsequently entered into commitments to transfer the majority of our RINs in inventory as of March 31, 2025. We believe the impacts of the EPA BRRR reform and the 2024 proposed partial waiver of the 2024 RVO have temporarily impacted 2025 RIN purchase activity of RFS obligated parties. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.

Factors Affecting Operating Expenses

Our operating expenses include royalties, transportation, gathering and production fuel expenses, project operating and maintenance expenses, general and administrative expenses, depreciation and amortization, net loss (gain) on sale of assets, impairment loss and transaction costs. Our operating expenses can be subject to inflationary cost increases that are largely out of our control.

• Project 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.
• Royalties, Transportation, Gathering and Production Fuel Expenses: Royalties represent payments made to our facility hosts, typically structured as a percentage of revenue. Transportation and gathering expenses include capacity and metering expenses representing the costs of delivering our RNG and Renewable Electricity production to our customers. These expenses include payments to pipeline operators and other agencies that allow for the transmission of our gas and electricity commodities to end users. Production fuel expenses generally represent alternative royalty payments based on quantity usage of biogas feedstock.
• 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. We account for share-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. In April 2025, we accelerated the vesting of certain restricted share awards to non-executives which were unvested as of March 31, 2025 as a result of the termination of an employee. We recognized $1,550 of non-cash stock compensation expense within general and administration expenses which will not be recurring in April 2025. For more information, see Note 14 to our unaudited condensed consolidated financial statements related to share-based compensation.
• Depreciation and Amortization: Expenses related to the recognition of the useful lives of our intangible and fixed assets. We spend significant capital to build and own our facilities. In addition to development capital, we annually reinvest to maintain these facilities.
• Impairment Loss: Expenses related to reductions in the carrying value(s) of fixed and/or intangible assets based on periodic evaluations whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
• Transaction Costs: Transaction costs primarily consist of expenses incurred for due diligence and other activities related to potential acquisitions and other strategic transactions.

Key Operating Metrics

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

• Production volumes: We review performance by site based on unit of production calculations for RNG and Renewable Electricity, measured in terms of MMBtu and MWh, respectively. While unit of production measurements can be influenced by 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.
• 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. A majority of our Renewable Electricity Generation segment Environmental Attributes are monetized as a component of our fixed-price PPAs.
• Average realized price per unit of production: Our profitability is highly dependent on the commodity prices for natural gas and electricity, and the Environmental Attribute prices for RINs, LCFS credits, and RECs. Realized prices for Environmental Attributes monetized in a year may not correspond directly with that year’s production as attributes may be carried over and subsequently monetized. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.

Comparison of Three Months Ended March 31, 2025 and 2024

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

(in thousands, unless otherwise indicated)

(1) RINs are generated in the month that the gas is dispensed to generate RINs, which occurs the month after the gas is produced. Volumes under fixed/floor-price arrangements generate RINs which we do not self-market. K3 RIN separation occurs after the gas is dispensed (RINs generated but unseparated).

(2) One MMBtu of RNG has the same energy content as 11.6935 gallons of ethanol, and thus may generate 11.6935 RINs under the RFS program.

(3) Represents RINs available to be self-marketed by us during the reporting period.

(4) Represents gas production which has not been dispensed to generate RINs.

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

Revenues for the Three Months Ended March 31, 2025 and 2024

Total revenues in the first quarter of 2025 were $42,603, an increase of $3,816 (9.8%) compared to $38,787 in the first quarter of 2024. The increase is primarily related the monetization of prior period RINs of approximately 6,822 that were carried into 2025. As a result, we sold 25.3% more RINs during the first quarter of 2025 compared to the first quarter of 2024. Partially offsetting this impact was a decrease in realized RIN pricing of approximately 24.3% during the first quarter of 2025 compared to the first quarter of 2024.

Renewable Natural Gas Revenues

We produced 1,389 MMBtu of RNG during the first quarter of 2025, a decrease of 22 MMBtu (1.6%) compared to 1,411 MMBtu produced in the first quarter of 2024. Our Rumpke facility produced 39 MMBtu more in the first quarter of 2025 compared to the first quarter of 2024 as a result of a previously disclosed plant processing equipment failure that occurred in the first quarter of 2024. Offsetting this increase was our Apex facility that produced 57 fewer MMBtu in the first quarter of 2025 compared to the first quarter of 2024 as a result of cold weather conditions impacting gas feedstock availability, wellfield extraction environmental factors, as well as plant processing equipment failures.

Revenues from the Renewable Natural Gas segment in the first quarter of 2025 were $38,451, an increase of $4,463 (13.1%) compared to $33,988 in the first quarter of 2024. Average commodity pricing for natural gas for the first quarter of 2025 was $3.65 per MMBtu, 62.9% higher than the first quarter of 2024. During the first quarter of 2025, we self-monetized 9,885 RINs, representing a 1,996 increase (25.3%) compared to 7,889 in the first quarter of 2024. Average pricing realized on RIN sales during the first quarter of 2025 was $2.46 as compared to $3.25 in the first quarter of 2024, a decrease of 24.3%. This compares to the average D3 RIN index price for the first quarter of 2025 of $2.43 as compared to $3.12 in the first quarter of 2024, a decrease of approximately 22.1%. At March 31, 2025, we had approximately 336 MMBtu available for RIN generation, 1,482 RINs generated and unseparated, and 3,916 RINs generated and unsold. At March 31, 2024, we had approximately 384 MMBtu available for RIN generation and 3,351 RINs generated and unsold.

Renewable Electricity Generation Revenues

We produced approximately 46 MWh in Renewable Electricity in the first quarter of 2025, a decrease of 8 MWh (14.8%) from 54 MWh in the first quarter of 2024. Our Security facility produced approximately 6 MWh less in the first quarter of 2025 compared to the first quarter of 2024 as a result us ceasing operations in connection with the first quarter of 2024 sale of the gas rights back to the landfill host.

Revenues from Renewable Electricity facilities in the first quarter of 2025 were $4,152, a decrease of $647 (13.5%) compared to $4,799 in the first quarter of 2024. The decrease was primarily driven by the cessation of operations at our Security facility.

In the first quarter of 2025, 100.0% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices associated with underlying PPAs, as compared to 100.0% in the first quarter of 2024. This provides us with certainty of price resulting from our Renewable Electricity sites.

Expenses for the Three Months Ended March 31, 2025 and 2024

General and Administrative Expenses

Total general and administrative expenses in the first quarter of 2025 were $8,754, a decrease of $673 (7.1%) compared to $9,427 for the first quarter of 2024. Employee related costs, including stock-based compensation costs were $5,011 in the first quarter of 2025, a decrease of $713 (12.5%) compared to $5,724 in the first quarter of 2024.

Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in the first quarter of 2025 were $14,090, an increase of $1,949 (16.1%) as compared to $12,141 in the first quarter of 2024. Our Apex facility operating and maintenance expenses increased approximately $663 primarily related timing of gas processing preventative maintenance schedule and plant process equipment failure repairs. Our McCarty facility operating and maintenance expenses increased approximately $308 primarily related to the timing of preventative maintenance media changes as well as wellfield operational enhancements. Our Rumpke facility operating and maintenance expenses increased approximately $221 primarily related to wellfield operational enhancements. Our Coastal facility operating and maintenance expenses increased approximately $221 primarily related to the timing of preventative maintenance media changes.

Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the first quarter of 2025 were $7,114, an increase of $1,117 (18.6%) compared to $5,997 in the first quarter of 2024. We recorded a decrease to our Pico facility earnout of approximately 12.5% during the first quarter of 2025. Royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues to 18.5% for the first quarter of 2025 from 17.6% in the first quarter of 2024.

Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in the first quarter of 2025 were $3,351, an increase of $1,059 (46.2%) compared to $2,292 in the first quarter of 2024. The increase was primarily driven by an increase in non-capitalizable costs at our Montauk Ag Renewables projects. Our Tulsa facility operating and maintenance expenses increased approximately $332 primarily related to plant process equipment maintenance.

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the first quarter of 2025 were $457, a decrease of $64 (12.3%) compared to $521 in the first quarter of 2024. Royalties, transportation, gathering and production fuel expenses increased as a percentage of Renewable Electricity revenues to 11.0% for the first quarter of 2025 from 10.9% in the first quarter of 2024.

Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in the first quarter of 2025 were $7,571, an increase of $1,053 (16.2%) compared to $6,518 in the first quarter of 2024. We make royalty payments to our fuel supply site partners on the commodities we produce and the associated Environmental Attributes. These royalty payments are typically structured as a percentage of revenue subject to a cap, with fixed minimum payments when Environmental Attribute prices fall below a defined threshold. To the extent commodity and Environmental Attributes’ prices fluctuate, our royalty payments may fluctuate upon renewal or extension of a fuel supply agreement or in connection with new projects. Our fuel supply agreements are typically structured as 20-year contracts, providing long-term visibility into the margin impact of future royalty payments.

Depreciation

Depreciation and amortization in the first quarter of 2025 was $6,264, an increase of $830 (15.3%) compared to $5,434 in the first quarter of 2024. The increase was primarily driven by the timing of wellfield capital investments placed into service and our Pico Digestion Capacity Increase project being placed into service.

Impairment loss

We calculated and recorded impairment losses of $2,047 in the first quarter of 2025, an increase of $1,519 (287.7%) compared to $528 in the first quarter of 2024. The increase primarily relates to the impairment of an RNG interconnection at our Blue Granite RNG project. The local gas utility informed us that no new connections would be accepted within their distribution pricing.

Other Expenses

Other expenses in the first quarter of 2025 was $1,191, an increase of $1,086 (1034.3%) compared to $105 in the first quarter of 2024. The increase was primarily related to proceeds received from the sale of gas rights ahead of the fuel supply expiration at our Security facility in the first quarter of 2024.

Income Tax (Benefit) Expense

Income tax benefit for the three months ended March 31, 2025 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21.0% primarily related to the adjustment of Production Tax Credits.

The effective tax rate of 40.6% for the three months ended March 31, 2025 was higher than the rate for the three months ended March 31, 2024 of 18.2% primarily due to pre-tax loss for the three months ended March 31, 2025, and a reported pre-tax income for the three months ended March 31, 2024.

Operating Income (Loss) for the Three Months Ended March 31, 2025 and 2024

Operating income in the first quarter of 2025 was $410, a decrease of $1,958 (82.7%) compared to $2,368 in the first quarter of 2024. RNG operating income for the first quarter of 2025 was $10,369, a decrease of 1,211 (10.5%) compared to $11,580 in the first quarter of 2024. Renewable Electricity Generation operating loss for the first quarter of 2025 was $1,021, a decrease of $1,397 (371.5%) compared to operating income of $376 for the first quarter of 2024.

Non-GAAP Financial Measures:

The following table presents EBITDA and Adjusted EBITDA, non-GAAP financial measures, for each of the periods presented below. We present EBITDA and Adjusted EBITDA because we believe the measures assist investors in analyzing our performance across reporting periods on a consistent basis by excluding items that we do not believe are indicative of our core operating performance. In addition, EBITDA and Adjusted EBITDA are financial measurements of performance that management and the board of directors use in their financial and operational decision-making and in the determination of certain compensation programs. EBITDA and Adjusted EBITDA are supplemental performance measures that are not required by or presented in accordance with GAAP. EBITDA and Adjusted EBITDA should not be considered alternatives to net (loss) 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 (loss) income, which is the most directly comparable GAAP measure, for the three months ended March 31, 2025 and 2024:

(1) We recorded impairment losses of $2,047 and $528 for the three months ended March 31, 2025 and 2024, respectively. The impairment losses in the first three months of 2025 primarily relate the impairment of an RNG interconnection at our Blue Granite RNG project. The first three months of 2024 impairment relates to an REG site in which we 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.

Liquidity and Capital Resources

Sources of Liquidity

At March 31, 2025 and March 31, 2024, our cash and cash equivalents, net of restricted cash, was $40,111 and $63,277, 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 and operational risks that could adversely affect our cash flows and liquidity.

At March 31, 2025, we had debt before debt issuance costs of $53,000, compared to debt before debt issuance costs of $56,000 at December 31, 2024.

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

Amended Credit Agreement

On December 21, 2021, the Company entered into the Fourth Amendment with Comerica and certain other financial institutions. The current credit agreement, which is secured by a lien on substantially all of our assets and assets of certain of our subsidiaries, provides for a five-year $80,000 term loan, a five-year $120,000 revolving credit facility, and a $75,000 accordion feature.

As of March 31, 2025, $53,000 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 $3,000 through 2026, with a final payment of $32,000 in late 2026 with an interest rate of 5.54% and 6.01% at March 31, 2025 and December 31, 2024, respectively.

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 March 31, 2025, we were in compliance with all applicable financial covenants under the Amended Credit Agreement.

For additional information regarding the Amended Credit Agreement, see Note 12— Debt to our unaudited condensed consolidated financial statements.

Capital Expenditures

We have historically funded our growth and capital expenditures with our working capital, cash flow from operations and debt financing. We expect our non-development 2025 capital expenditures to range between $14,000 and $17,000. Our 2025 non-development capital plans include annual preventative maintenance expenditures, annual wellfield expansion projects, and other specific facility improvements. Additionally, we estimate that our existing 2025 development capital expenditures will range between $100,000 and $150,000. The majority of our 2025 development capital expenditures are related to our ongoing development of Montauk Ag Renewables, the second Apex facility, the Bowerman RNG project, the EENA CO2 project, Tulsa RNG project and our Rumpke RNG relocation 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. As we continue to explore strategic growth opportunities, we have not entered into nonbinding letters of intent for any opportunity, 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 the three months ended March 31, 2025 and 2024:

40

For the first three months of 2025, we generated $9,140 of cash provided by operating activities compared to $14,292 in the first three months of 2024. For the first three months of 2025, income and adjustments to income from operating activities provided $8,807 compared to income and adjustments to income provided $9,357 in first three months of 2024. Working capital and other assets and liabilities provided $333 in the first three months of 2025 compared to working capital and other assets and liabilities providing $4,935 in the first three months of 2024.

Our net cash flows used in investing activities has historically focused on project development and facility maintenance. Our capital expenditures for the first three months of 2025 were $11,632, of which $6,076, $5,855, and $1,397 were related to the Montauk Ag Renewables in North Carolina, second Apex RNG facility, and Bowerman RNG project, respectively.

Our net cash flows used in financing activities of $3,018 for the first three months of 2025 increased by $998 compared to cash used in financing activities in the first three months of 2024 of $2,020.

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 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 8 in the unaudited condensed consolidated financial statements for further information regarding the asset retirement obligations.

We have contractual obligations under our debt agreement, including interest payments and principal repayments. See Note 12 in the unaudited condensed consolidated financial statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. During the first three months of 2025, we had approximately $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 draw downs on these outstanding letters of credit. During the first three months of 2024, 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. We lease office space and other office equipment under operating lease arrangements, expiring in various years through 2033. See Note 18 in the unaudited condensed consolidated financial statements for further information related to the lease obligations.

We have other contractual obligations associated with our fuel supply agreements. The expiration of these agreements range between 2-18 years. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,695.

In April 2025, the Board of Directors of Montauk Renewables Inc. authorized a share repurchase program (the “Share Repurchase Program”), pursuant to which we may, from time to time, purchase currently outstanding shares of its common stock for an aggregate repurchase price not to exceed $5,000. The timing, number and purchase price of shares repurchased under the program, if any, will be determined by a Repurchase Committee, comprised of Board members and management. The Share Repurchase Program does not have an expiration date and there are no assurances that purchases will take place under the program.

Critical Accounting Policies and Estimates

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

Revenue Recognition

Our revenues are comprised of renewable energy and the related Environmental Attribute sales provided under a variety of short-term and medium-term agreements with our customers. All revenue is recognized when we satisfy our performance obligation(s) under the contract (either implicit or explicit) by transferring the promised product to the customer either when (or as) the customer obtains control of the product. A performance obligation is a promise in a contract to transfer a distinct product or service to a customer. A contract’s transaction price is allocated to each distinct performance obligation. We allocate the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract.

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

The nature of the Company’s 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.

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.

RECs

We generate RECs through our production and conversion of landfill methane into Renewable Electricity in various states, including California, Oklahoma, and Texas. 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 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.

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.

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 affect 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. We identified discrete events and recorded impairment of $2,047 and $528 for the three months ended March 31, 2025 and 2024, respectively. See Note 3 in the unaudited condensed 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, which ends after 2025. The JOBS Act allows emerging growth companies to delay the adoption of new or revised accounting standards until such time as those standards apply to private companies. We intend to utilize these transition periods, which may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the transition periods afforded under the JOBS Act.

Recent Accounting Pronouncements

For a description of our recently adopted accounting pronouncements and recently issued accounting standards not yet adopted, see Note 2 of our unaudited condensed consolidated financial statements in this report.

There have been no material changes since our disclosure in Quantitative and Qualitative Disclosures About Market Risk included as Item 7A in our 2024 Annual Report.

Management’s Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) or 15d-15(e) under the Exchange Act, as of the end of the period covered by this quarterly report. Disclosure controls and procedures are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Our management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Our management, including our principal executive officer and principal financial officer, after evaluating the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report, concluded that as of such date, our disclosure controls and procedures were effective at a reasonable level of assurance.

Changes in Internal Control Over Financial Reporting

In March 2025, we implemented a new Enterprise Resource Planning ("ERP") system. In conjunction with the ERP implementation, we updated the design of key internal controls over financial reporting.

Except as discussed above, there were no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

We face a number of risks that could materially and adversely affect our business, results of operations, cash flow, liquidity, or financial condition. A discussion of our risk factors can be found in Part I, “Item 1A Risk Factors” in our 2024 Annual Report any of which could have a material effect on us.