Quarterly Report for Quarter Ending September 30, 2025 (Form 10-Q)

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 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. 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. We had approximately 749 RINs generated but unseparated at September 30, 2025 which reduced the amount of RINs available for sale as of September 30, 2025. We expect this timing between RINs generated but unseparated and RINs available for sale to only impact 2025 which is the year BRRR became effective. We had approximately 10 RINs in inventory from 2025 RNG production as of September 30, 2025. The average D3 RIN index price for the third quarter of 2025 was approximately $2.19. 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:

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 and this work remains ongoing. The project is anticipated to have production nameplate capacity of approximately 3,600 MMBtu per day, assuming currently forecasted biogas feedstock volumes projected to be available from the host landfill at the time of commissioning. We continue to incur capital expenditures for this project.

Carbon Dioxide Beneficial Use Opportunity

In 2024, we signed a contract for the delivery of 140 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. During the period prior to commissioning, we have been recognizing an exclusivity fee related to the minimum tons of CO2. The annual price per ton under the contract is adjusted annually by the U.S. consumer price index. The agreement with EENA includes a 50% sharing component of any available tax attributes generated by us under code section 45Q, Carbon dioxide sequestration credit, in the Inflation Reduction Act, as applicable. The Tax Reconciliation Act signed into law on July 4, 2025 has potentially impacted the manner in which EENA will use offtake associated with its business development. We continue to expect to develop CO2 at select Texas facilities and are in discussions with EENA regarding our agreement. 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 continue incurring capital expenditures for long lead items 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 continue incurring capital expenditures for long lead items.

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 negotiations with other utility users to provide swine RECs from our expected first phase production of MWh. We expect our annual REC capacity to be approximately 120 RECs, of which the Duke REC agreement is for 47 RECs. In September 2025, a joint motion was filed with the North Carolina Utility Commission ("NCUC") by various entities seeking to modify and delay the 2025 requirements of certain aspects of the North Carolina Clean Energy and Portfolio Standard, specifically, the portfolio standards relating to swine RECs. We note this filing is not dissimilar to historical annual filings in response to the historically limited swine REC market in North Carolina. In October 2025, we filed response comments to the joint motion with the NCUC requesting they grant modifications or delays only to individual power supplies that have demonstrated need, require power suppliers that have not achieved 100% compliance in 2025 to apply any cumulatively acquired swine RECs to the suppliers unsatisfied 2025 pro rata obligation, and modify the swine REC set-aside for 2026 and beyond to match the requirement originally set by North Carolina in 2018.

With the limited swine REC market in North Carolina, we have been negotiating our REC agreements individually. Many of these agreements contain competitive details and, while there remains a limited active swine REC market in North Carolina, we believe the prices we are negotiating will be market based. While we believe these prices will not be based on solar REC prices seen in other US markets, those indices are more illustrative of our expectations of North Carolina swine REC prices than US market wind REC prices. Depending on a variety of factors, we believe our negotiated swine REC prices could fall into the ranges experienced by solar REC indices at $200 to $450 per REC.

We continue our development efforts in North Carolina and continue to expect our production and revenue generation activities to commence in the first quarter of 2026. Alongside our construction efforts for the first phase, for which total investment continues to be projected between $180 million and $220 million, we continue to progress our negotiations with obligated utilities to monetize all remaining uncontracted Renewable Energy Credits (or RECs) from our projected first phase production volumes.

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 developments 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, 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. We expect the Montauk Ag Renewables project to generate tax attributes once placed into service consisting of a mix of investment tax, production tax, or accelerated depreciation. We are reviewing the Tax Reconciliation Act passed in July 2025 to determine what, if any, impacts there are to these expectations.

Waste-stream Biogas Recovery

In 2024, we announced a collaboration with Emvolon to transform methane emissions from waste stream biogas into high-value carbon negative fuel. The initial pilot project at our Atascocita facility in Houston, TX has exceeded its anticipated results. Following a successful field demonstration project, together with Emvolon, we plan to deploy a portfolio of biogas-based sites with an aggregate annual production capacity of up to 50 metric tons of green methanol by 2030. We do not expect short term financial benefits from this joint development venture nor a disruption to our operations.

GreenWave Joint Venture

In the first quarter of 2025, we, through our wholly-owned subsidiary Pesta Energy, LLC, entered into an agreement with Pioneer Renewables Energy Marketing, LLC to form a joint venture, GreenWave Energy Partners, LLC ("Greenwave"). The primary goal of the joint venture is to help address the limited capacity of RNG utilization for transportation by offering third party RNG volumes access to exclusive unique and proprietary transportation pathways. In the third quarter of 2025, Greenwave began matching available RNG capacity to dispensing opportunities through Greenwaves's transportation pathways. The venture has matched capacity and has separated RINs for a limited amount of volumes. We expect increased benefits from Greenwave in the fourth quarter of 2025 and have not directly recognized any significant share of profits. Our capital investment in the joint venture is estimated to be up to approximately $4,500 subject to various and certain requirements as defined in the underlying agreements.

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 and continue discussions with the landfill host.

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:

Factors Affecting Our Future Operating Results:

Acquisition and Development Pipeline

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

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 RINs for the three years 2023, 2024 and 2025, respectively. The final rule also included significant changes to the existing RFS program,

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

On June 13, 2025, the EPA released both the Partial Waiver of the 2024 Cellulosic Biofuel Volume Requirement (Final Rule) and RFS Standards for 2026 and 2027, Partial Waiver of 2025 Cellulosic Biofuel Volume Requirement, and Other Changes (Proposed Rule). The final 2024 cellulosic biofuel volume requirement was reduced from 1,090 to 1,010 million D3 RINs. This reduction was based on actual volumes of D3 RINs generated in 2024. In addition, the EPA is making Cellulosic Waiver Credits ("CWCs") available for 2024 as an additional compliance flexibility for obligated parties.

In the EPA's proposed rule released on June 13, 2025, the cellulosic biofuel volumes for 2025 were proposed to be reduced from 1,376 to 1,190 RINs and make CWCs available for 2025. The proposed cellulosic biofuel volume requirements for 2026 and 2027 are 1,300 and 1,360 D3 RINs, respectively. These volumes are less than the EPA had previously finalized for 2025 and are based on their belief that cellulosic RIN generation from biogas-derived CNG/LNG during 2026-2030 will be constrained by the total usage capacity of CNG/LNG as transportation fuel. These proposed rules are subject to comment periods prior to finalization.

On August 22, 2025, EPA issued decisions on 175 Small Refinery Exemption (SRE) petitions. EPA granted full exemption (100%) to 63 petitions and partial exemptions (50%) to 77 petitions. The SRE decisions exempted corresponding volumes of gasoline and diesel for the 2023 and 2024 compliance years, and increased the number of RINs available for obligated parties to use for compliance with their RFS obligations. Taking into consideration the expected impacts of the SRE decisions on the RFS market, on September 16, 2025, EPA co-proposed a Supplemental Rule that provides additional volumes in 2026 and 2027 RVOs that will represent complete (100%) reallocation or partial (50%) reallocation for SREs granted in full or in part, respectively, for 2023 and 2024, as well as those projected to be granted for 2025.

EPA has indicated an intention to finalize the Supplemental Rule & the RVOs for 2025, 2026 and 2027 by the end of 2025, however, the duration of the US federal government shut down and any residual impacts on EPA staffing after the shutdown concludes may extend finalization of these items into 2026.

In December 2023, CARB released the formal proposal for new LCFS rules. The proposed rules will increase the stringency of CI reduction targets from 20% to 30% in 2030 and 90% by 2045. This reduction would have the potential impact of reducing the number of net credits in the program. On July 1, 2025, CARB's amended LCFS rules officially took effect setting the aggressive carbon intensity reduction targets listed above. The industry may see gradual increases in LCFS credit prices over the next year. The rules also phase out avoided methane crediting for dairy and swine manure pathways by 2040 for CNG usage and through 2045 for RNG used to produce hydrogen. The RNG deliverability/book and claim provisions for out-of-region projects are eliminated for all projects that break ground after 2030. These projects will be required to demonstrate physical deliverability requirements beginning in 2041. Changes to the LCFS program require annual verification of the CI score assigned to a project. Annual verification could significantly affect the profitability of a project, particularly in the case of a livestock farm project. In June 2025, California lawmakers introduced California Senate Bill SB-237, which includes a potential cap on LCFS credit prices of approximately $75/ton.

On March 15, 2025, the Full-Year Continuing Appropriations and Extensions Act, 2025 was signed into law. In May 2025, we were informed that the law eliminated the United States Department of Agriculture Advanced Biofuel Payment Program. We received approximately $200 annually since 2021 under this program.

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.

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.

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 typically we sell RINs in the calendar year they are separated. 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.

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:

Comparison of Three Months Ended September 30, 2025 and 2024

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

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

Revenues for the Three Months Ended September 30, 2025 and 2024

Total revenues in the third quarter of 2025 were $45,258, a decrease of $20,659 (31.3%) compared to $65,917 in the third quarter of 2024. The decrease is related to a decrease in the number of RINs we self-marketed from 2025 RNG production in the third quarter of 2025. In addition, realized RIN pricing decreased approximately 31.4% during the third quarter of 2025 compared to the third quarter of 2024.

Renewable Natural Gas Revenues

We produced 1,445 MMBtu of RNG during the third quarter of 2025, an increase of 53 MMBtu (3.8%) compared to 1,392 MMBtu produced in the third quarter of 2024. Our Rumpke facility produced 50 MMBtu more in the third quarter of 2025 compared to the third quarter of 2024 as a result of higher feedstock gas. Our Apex facility produced 25 MMBtu more in the third quarter of 2025 as a result of the June 2025 commissioning of the second Apex RNG facility. Offsetting the increase was the fourth quarter of 2024 sale of our Southern facility which produced 69 MMBtu in the first nine months of 2024.

Revenues from the Renewable Natural Gas segment in the third quarter of 2025 were $39,883, a decrease of $21,867 (35.4%) compared to $61,750 in the third quarter of 2024. Average commodity pricing for natural gas for the third quarter of 2025 was $3.07 per MMBtu, 42.1% higher than the third quarter of 2024. During the third quarter of 2025, we self-marketed 12,410 RINs, representing a 3,340 decrease (21.2%) compared to 15,750 in the third quarter of 2024. Average pricing realized on RIN sales during the third quarter of 2025 was $2.29 as compared to $3.34 in the third quarter of 2024, a decrease of 31.4%. Average D3 RIN index price for the third quarter of 2025 was $2.19 compared to $3.36 in the third quarter of 2024, a decrease of approximately 34.8%. At September 30, 2025, we had approximately 331 MMBtu available for RIN generation, 749 RINs generated and unseparated, and 10 RINs generated and unsold. At September 30, 2024, we had approximately 308 MMBtu available for RIN generation and 146 RINs generated and unsold. There were no RINS generated and unseparated at September 30, 2024.

Renewable Electricity Generation Revenues

We produced approximately 44 MWh in Renewable Electricity in the third quarter of 2025, an increase of 3 MWh (7.3%) from 41 MWh in the third quarter of 2024. Our Bowerman facility produced approximately 2 MWh more in the third quarter of 2025 compared to the third quarter of 2024. The increase is primarily related to the timing of processing equipment maintenance in the third quarter of 2024.

Revenues from Renewable Electricity facilities in the third quarter of 2025 were $4,246, an increase of $79 (1.9%) compared to $4,167 in the third quarter of 2024. The increase was primarily driven by the increase in our Bowerman facility production volumes.

In the third 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 third quarter of 2024. This provides us with certainty of price resulting from our Renewable Electricity sites.

Expenses for the Three Months Ended September 30, 2025 and 2024

General and Administrative Expenses

Total general and administrative expenses in the third quarter of 2025 were $6,511, a decrease of $3,526 (35.1%) compared to $10,037 for the third quarter of 2024. The decrease is primarily related to the accelerated vesting of certain restricted share awards as a result of the termination of an employee in the third quarter of 2024.

Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in the third quarter of 2025 were $13,924, an increase of $1,338 (10.6%) as compared to $12,586 in the third quarter of 2024. Our Rumpke facility operating and maintenance expenses increased approximately $538 primarily related to preventative maintenance media changes and wellfield operational enhancements. Our Atascocita facility operating and maintenance expenses increased approximately $422 primarily related to the timing of maintenance related to gas processing equipment and increased utility expense. Our Apex facility operating and maintenance expenses increased approximately $275 primarily related to increased utility expense.

Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the third quarter of 2025 were $7,975, a decrease of $2,665 (25.0%) compared to $10,640 in the third quarter of 2024. We recorded an increase to our Pico facility earnout of approximately 7.6% during the third quarter of 2025. Royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues to 20.0% for the third quarter of 2025 from 17.2% in the third quarter of 2024.

Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in the third quarter of 2025 were $2,588, a decrease of $115 (4.3%) compared to $2,703 in the third quarter of 2024. The decrease is primarily driven by our Tulsa facility operating and maintenance expenses which decreased approximately $106 primarily related to timing of annual engine maintenance.

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the third quarter of 2025 were $458, a decrease of $9 (1.9%) compared to $467 in the third quarter of 2024. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of Renewable Electricity revenues to 10.8% for the third quarter of 2025 from 11.2% in the third quarter of 2024.

Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in the third quarter of 2025 were $8,433, a decrease of $2,674 (24.1%) compared to $11,107 in the third 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 third quarter of 2025 was $8,341, an increase of $2,293 (37.9%) compared to $6,048 in the third quarter of 2024. The increase was primarily driven by the timing of wellfield and maintenance capital investments placed into service and our Second Apex RNG Facility project being placed into service.

Impairment loss

We calculated and recorded impairment losses of $48 in the third quarter of 2025, a decrease of $485 (91.0%) compared to $533 in the third quarter of 2024. The decrease primarily relates to specifically identified assets deemed obsolete or non-operable in third quarter of 2024 compared to the third quarter of 2025.

Other Expenses

Other expenses in the third quarter of 2025 was $1,088, a decrease of $607 (35.8%) compared to $1,695 the third quarter of 2024. The decrease is related to a reduction in interest expense in the third quarter of 2025 compared to the third quarter of 2024.

Income Tax Expense

Income tax expense for the three months ended September 30, 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, Investment Tax Credits as well as stock based compensation vesting.

The effective tax rate of (54.9)% for the three months ended September 30, 2025 was lower than the rate for the three months ended September 30, 2024 of 18.9% primarily due to the change in our pre-tax income (loss) for the three months ended September 30, 2025 as compared to the three months ended September 30, 2024.

Operating Income for the Three Months Ended September 30, 2025 and 2024

Operating income in the third quarter of 2025 was $4,448, a decrease of $18,260 (80.4%) compared to $22,708 in the third quarter of 2024. RNG operating income for the third quarter of 2025 was $11,036, a decrease of $22,580 (67.2%) compared to $33,616 in the third quarter of 2024. Renewable Electricity Generation operating loss for the third quarter of 2025 was $166, a decrease of $452 (73.1%) compared to $618 for the third quarter of 2024.

Comparison of Nine Months Ended September 30, 2025 and 2024

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

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

Revenues for the Nine Months Ended September 30, 2025 and 2024

Total revenues in the first nine months of 2025 were $132,988, a decrease of $15,054 (10.2%) compared to $148,042 in the first nine months of 2024. Our total RNG attribute revenues decreased approximately $30,169 in the first nine months of 2025 as compared to the first nine months of 2024. Our realized RIN pricing decreased approximately 28.0% during the first nine months of 2025 compared to the first nine months of 2024. Total RNG commodity revenues increased $13,395 in the first nine months of 2025 as compared to the first nine months of 2024. Our counterparty margin share revenues also increased $1,460 in the first nine months of 2025 as compared to the first nine months of 2024.

Renewable Natural Gas Revenues

We produced 4,247 MMBtu of RNG during the first nine months of 2025, an increase of 59 MMBtu (1.4%) compared to the 4,188 MMBtu produced in the first nine months of 2024. Our Rumpke facility produced 156 MMBtu more in the first nine months of 2025 compared to the first nine months of 2024 as a result of previously disclosed plant processing equipment failures that occurred in the first nine months of 2024. Our Apex facility produced 36 MMBtu fewer in the first nine months of 2025 compared to the first nine months of 2024 as a result of cold weather conditions impacting gas feedstock availability, wellfield extraction environmental factors, as well as plant processing equipment failures. Also offsetting the increase was the fourth quarter of 2024 sale of our Southern facility which produced 69 MMBtu in the first nine months of 2024.

Revenues from the Renewable Natural Gas segment in the first nine months of 2025 were $119,162, a decrease of $15,413 (11.5%) compared to $134,575 in the first nine months of 2024. Average commodity pricing for natural gas for the first nine months of 2025 was $3.39 per MMBtu, 61.4% higher than the first nine months of 2024. During the first nine months of 2025, we self-monetized 33,345 RINs, representing a 294 RIN decrease (0.9%) compared to 33,639 RINs in the first nine months of 2024. Average pricing realized on RIN sales during the first nine months of 2025 was $2.34 as compared to $3.25 in the first nine months of 2024, a decrease of 28.0%. This compares to the average D3 RIN index price for the first nine months of 2025 of $2.32 as compared to $3.22 in the first nine months of 2024, a decrease of approximately 28.0%. At September 30, 2025, we had approximately 331 MMBtu available for RIN generation, 749 RINs generated and unseparated, and 10 RINs generated and unsold. At September 30, 2024, we had approximately 308 MMBtu available for RIN generation and 146 RINs generated and unsold. There were no RINS generated and unseparated at September 30, 2024.

Renewable Electricity Generation Revenues

We produced approximately 132 MWh in Renewable Electricity in the first nine months of 2025, a decrease of 8 MWh (5.7%) from 140 MWh in the first nine months of 2024. Our Security facility produced approximately 6 fewer MWh in the first nine months of 2025 compared to the first nine months of 2024 as a result of ceasing operations in connection with the first quarter of 2024 sale. Our Bowerman facility produced approximately 2 fewer MWh in the first nine months of 2025 compared to the first nine months of 2024 primarily related to the planned preventative engine maintenance that was completed in the first nine months of 2025.

Revenues from Renewable Electricity facilities in the first nine months of 2025 were $12,697, a decrease of $770 (5.7%) compared to $13,467 in the first nine months of 2024. The decrease is primarily driven by the decrease in our Bowerman facility production volumes and the cessation of operation at our Security facility.

In the first nine months 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 nine months of 2024. This provides us with certainty of price resulting from our Renewable Electricity sites.

Expenses for the Nine Months Ended September 30, 2025 and 2024

General and Administrative Expenses

Total general and administrative expenses were $24,310 for the first nine months of 2025, a decrease of $3,892 (13.8%) compared to $28,202 for the first nine months of 2024. The decrease was primarily related to the accelerated vesting of certain restricted share awards as a result of the termination of an employee in the first nine months of 2024.

Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in the first nine months of 2025 were $44,970, an increase of $6,341 (16.4%) as compared to $38,629 in the first nine months of 2024. Our Apex facility operating maintenance expenses increased approximately $1,724 primarily related to increased utility expense, the timing of maintenance related to gas processing equipment, increased media change outs, as well as a wellfield operational enhancement program. Our Rumpke facility operating maintenance expenses increased approximately $1,518 primarily related to a wellfield operational enhancement program, increased media change outs, and increased utility expense. Our Atascocita facility operating maintenance expenses increased approximately $1,168 primarily due to gas processing equipment maintenance, timing of media change outs, a wellfield operational enhancement program, and increased utility expense. Our McCarty facility operating maintenance expenses increased approximately $776 primarily related to increased media change outs, timing of maintenance related to gas processing equipment as well as a wellfield operational enhancement program. Our Coastal facility operating maintenance expenses increased approximately $498 primarily related to media change outs. Our Monroeville facility operating maintenance expenses increased approximately $224 primarily related to a process equipment failure.

Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the first nine months of 2025 were $23,757, a decrease of $1,449 (5.7%) compared to $25,206 in the first nine months of 2024. We recorded an increase to our Pico facility earnout of approximately 13.4% during the first nine months of 2025. Royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues to 19.9% for the first nine months of 2025 from 18.7% in the first nine months of 2024.

Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in the first nine months of 2025 were $10,748, an increase of $1,036 (10.7%) compared to $9,712 in the first nine months of 2024. The increase was primarily driven by an increase in non-capitalizable costs at our Montauk Ag Renewables projects.

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the first nine months of 2025 were $1,414, a decrease of $82 (5.5%) compared to $1,496 in the first nine months of 2024. As a percentage of Renewable Electricity Generation segment revenues, royalties, transportation, gathering and production fuel expenses remained unchanged at 11.1%.

Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in the first nine months of 2025 were $25,172, a decrease of $1,530 (5.7%) compared to $26,702 in the first nine months of 2024.

Depreciation

Depreciation and amortization in the first nine months of 2025 was $21,634, an increase of $4,329 (25.0%) compared to $17,305 in the first nine months of 2024. The increase was primarily driven by the timing of wellfield and maintenance capital investments placed into service and our Second Apex RNG Facility project being placed into service.

Impairment loss

We calculated and recorded impairment losses of $2,472 in the first nine months of 2025, an increase of $1,240 (100.6%) compared to $1,232 in the first nine months of 2024. The impairment losses in the first nine months of 2025 primarily relate to a development project RNG interconnection for which the local utility is no longer accepting RNG into its distribution system. All associated costs related to the interconnection were impaired and specifically identified assets deemed obsolete or non-operable. The impairment losses in the first nine months of 2024 primarily relate to the remaining book value of assets at the Security facility and various RNG equipment that was deemed obsolete for current operations.

Other Expenses

Other expenses in the first nine months of 2025 was $3,533, an increase of $497 (16.4%) compared to $3,036 in the first nine months of 2024. The increase is primarily related to proceeds received from the sale of gas rights ahead of the fuel supply agreement expiration of our Security facility in the first nine months of 2024 which is offset by decreased interest expense of $752.

Income Tax Expense

Income tax expense for the nine months ended September 30, 2025 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21.0% primarily due to the benefit from production tax credits.

The effective tax rate of 27.7% for the nine months ended September 30, 2025 was lower than the rate for the nine months ended September 30, 2024 of 20.6% primarily due to due to discrete events related to the vesting of restricted grants on stock compensation offset by tax benefits related to production and investment tax credit as compared to year-to-date pre-tax book loss.

Operating (Loss) Income for the Nine Months Ended September 30, 2025 and 2024

Operating income in the first nine months of 2025 was $2,501, a decrease of $23,443 (90.4%) compared to $25,944 in the first nine months of 2024. RNG operating income for the first nine months of 2025 was $30,630, a decrease of $26,281 (46.2%) compared to $56,911 in the first nine months of 2024. Renewable Electricity Generation operating loss for the first nine months of 2025 was $3,534, an increase of $1,324 (59.9%) compared to $2,210 for the first nine months 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 income, which is the most directly comparable GAAP measure, for the three months ended September 30, 2025 and 2024:

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 nine months ended September 30, 2025 and 2024:

Liquidity and Capital Resources

Sources of Liquidity

At September 30, 2025 and September 30, 2024, our cash and cash equivalents, net of restricted cash, was $6,766 and $54,973, 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 September 30, 2025, we had debt before debt issuance costs of $67,000, 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 September 30, 2025, $47,000 was outstanding under the term loan and we had $20,000 of 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 5.56% and 6.01% at September 30, 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:

As of September 30, 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 13- 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 $16,000. 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 $90,000 and $120,000. The majority of our ongoing 2025 development capital expenditures are related to our ongoing development of Montauk Ag Renewables, the Bowerman RNG project, and the EENA CO2 project. To a lesser extent in 2025, the Tulsa RNG project and our Rumpke RNG relocation project will incur development capital expenditures. 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.

Cash Flow

The following table presents information regarding our cash flows and cash equivalents for the nine months ended September 30, 2025 and 2024:

For the first nine months of 2025, we generated $29,997 of cash provided by operating activities compared to $43,071 in the first nine months of 2024. For the first nine months of 2025, income and adjustments to income from operating activities provided $29,319 compared to income and adjustments to income provided $46,737 in first nine months of 2024. Working capital and other assets and liabilities provided $678 in the first nine months of 2025 compared to working capital and other assets and liabilities used $3,666 in the first nine 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 nine months of 2025 were $75,106, of which $51,895, $8,533, and $7,536 were related to the Montauk Ag Renewables in North Carolina, Rumpke RNG relocation project, and our second Apex RNG facility, respectively.

Our net cash flows provided by financing activities of $10,421 for the first nine months of 2025 increased by $18,176 compared to cash used in financing activities in the first nine months of 2024 of $7,755 as a result of proceeds received from our revolving credit agreement.

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 9 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 13 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 nine months of 2025, we had $3,321 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 nine months of 2024, we did not have off-balance sheet arrangements other than outstanding letters of credit of $2,185.

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 19 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, medium and long 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 cash flows 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 an impairment of $48 and $533 for the three months ended September 30, 2025 and 2024, respectively and $2,472 and $1,232 for the nine months ended September 30, 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.