Montauk Renewables, Inc.

Previous wording

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, MMBtu, MWh, and RIN pricing amounts and unless otherwise indicated.

Current wording

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.

Previous wording

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 12 RNG and two Renewable Electricity projects through self-development, partnerships, and acquisitions that span eight states.

Current wording

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.

Previous wording

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 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.

Current wording

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.

Previous wording

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 and discussions with the landfill host waste intake forecasted projections. As the landfill host continues to increase waste intake, we believe that the additional 2,100 MMBtu per day of production capacity will allow us to process the currently forecasted increase in biogas feedstock volumes. While the landfill host continues to increase waste intake, we continue to expect there could be a period where we have excess available capacity after the second facility is commissioned. We continue to incur capital expenditures for this project and continue to expect commercial operations in the second quarter of 2025.

Current wording

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.

Previous wording

In 2023, we announced a planned development of a renewable natural gas landfill project in Irvine, CA at the Frank R. Bowerman Landfill. The project is anticipated to process the large and growing volumes of biogas in excess of the existing capacity of the REG facility. We currently expect facility commissioning in 2027 and continue to expect the capital investment to range between $85,000 and $95,000. As part of the agreement to develop the RNG plant, we also agreed to work with the landfill host on the landfill's management of its wellfield and its flare facility permit requirements. The landfill has proposed corresponding changes to our agreement which could have impacts to our existing, agreed upon commissioning schedule. We continue to work with the landfill on these proposed changes to assess what, if any, impact these changes could additionally have related to 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 that are projected to be available from the host landfill at the time of commissioning. We continue to incur capital expenditures for this project.

Current wording

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.

Previous wording

In February 2024, we signed a contract for the delivery of 140 thousand tons per year of biogenic carbon dioxide (“CO2”) from our Texas facilities. We intend to capture, clean and liquefy CO2 at select Texas facilities, at which point it will be transported to EE North America's (“EENA”), Houston Texas-based e-methanol facility. The delivery term is expected to last at least 15 years and we continue to expect delivery to begin in 2027. During the second quarter of 2024, we completed initial site surveys related to locating the CO2 processing equipment. We have also received equipment proposals from multiple vendors all having prior experience with liquid CO2 capture and processing. We continue to anticipate commissioning in 2027 and we expect the capital investment to range between $65,000 and $75,000 with capital expenditure beginning in 2025 for long lead equipment and design engineering.

Current wording

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.

Previous wording

In 2021, through a wholly-owned subsidiary Montauk Ag Renewables, we completed an asset purchase related to developing technology 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 to generate renewable electricity, to generate North Carolina swine RECs, and to produce micronutrient organic fertilizer alternatives (the “Montauk Ag Renewables Acquisition”).

Current wording

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”).

Previous wording

In connection with the July 2023 REC agreement with Duke Energy (“Duke”), our Board of Directors approved funding for the first phase of the North Carolina development project in September 2023. Once construction has been completed on the first phase and the facility has been fully commissioned, the project will provide sufficient capacity to satisfy the Duke REC agreement through the deployment of up to seven operational processing lines at the Turkey Creek facility. Including the original equipment acquired in the Montauk Ag Renewables Acquisition, the Turkey, NC 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.

Current wording

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.

Previous wording

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. 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 do not expect to commence significant revenue generating activities until 2025. We intend to contract with additional farms to secure feedstock sources for future production processes.

Current wording

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.

Previous wording

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

Current wording

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.

Previous wording

Regulatory or policy initiatives, including the federal RFS program and state or national-level low-carbon fuel programs in states such as California and Oregon or Canada, that drive demand for RNG and its derivative Environmental Attributes (as further described below).

Current wording

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).

Previous wording

Efficiency, mobility and capital cost flexibility in RNG operations enable them 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 counterparts.

Current wording

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.

Previous wording

We continue to evaluate opportunities to convert our remaining 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 combined sale of RNG and RINs relative to the combined sale of market rate electricity and 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.

Current wording

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.

Previous wording

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 RNG 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.

Current wording

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.

Previous wording

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 D3 RINs for the three years 2023, 2024 and 2025, respectively. While new RNG projects in the US in 2024 have grown at a rate of approximately 20% over 2023, there is still a shortage of cellulosic biofuel (D3 RINs) compared to the volumes set for 2024 and 2025. While the EPA denied all small refinery exemptions in 2022, a federal appeals court rejected EPA’s denial of these small refinery exemptions in July 2024. This appeal, along with the shortfall of cellulosic biofuels (D3 RINs) are expected to impact a future EPA action possibly in 2025 to balance the market. The final rule also included significant changes to the existing RFS program, referred to as biogas regulatory reform, that will require the RNG industry to modify how all RINs are generated. New RFS participating facilities that register July 1, 2024, or after will have to meet the biogas regulatory reform provisions beginning July 1, 2024. Existing RFS participating facilities which registered prior to July 1, 2024, will have until January 1, 2025, to come into compliance with biogas regulatory reforms. For existing registrants, registration updates must be submitted by October 1, 2024. On January 1, 2025, all RFS participants must comply with biogas regulatory reform 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.

Current wording

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.

Previous wording

The EPA has indicated it will not meet the statutorily required deadline of November 2024 to finalize 2026 obligations under the RFS. The EPA expects to target March 2025 to propose RFS obligations for 2026.

Current wording

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.

Previous wording

In December 2023, CARB released the formal proposal for new LCFS rules. CARB held a public workshop for the proposed rules on April 10, 2024. In early October 2024, CARB released another set of 15-day amendments with the most notable near-term change of increasing CI reduction stringency from 5% to 9% in 2025 along with a 20% to 30% reduction by 2030. The proposed rule also creates a 2045 target of 90% reduction. This reduction would have the potential impact of reducing the number of net credits in the program. A public hearing for the proposed rule is set for November 8, 2024. Final rules are expected to be submitted to CARB’s board for approval sometime in the first quarter of 2025. The industry may see pricing volatility including potential increase to LCFS credit prices. However, price increases are not anticipated until after 2025. Also in the proposed 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. RNG projects with avoided methane that were certified before the effective date of the new regulation will be allowed three consecutive 10-year crediting periods. Avoided methane RNG projects that break ground on or after the effective date of the regulation and before January 1, 2030, will be allowed up to two consecutive 10-year crediting periods. If the executive officer of CARB approves a gas map by July 1, 2026, then physical flow of gas to California must be demonstrated by December 31, 2037. If no gas map is approved, the proposed rules will allow reporting entities until January 1, 2041 to demonstrate gas flow.

Current wording

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.

Previous wording

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 have certain pathway provider sharing arrangements expiring at the end of 2024. While we have not experienced a significant increase in Environmental Attributes shared with pathway providers related to our current renewals in 2024, our current pathway renewals have been at higher percentages than our historical counterparty share percentages. We are seeing current proposed pathway renewals for percentages significantly higher than our historical arrangements. Historically, we have monetized less than 25% of our RNG volumes under these fixed-price agreements. The Company is considering its entry into multiple short term contracts throughout 2025, some potentially increasing its historical percentage of volumes monetized under fixed-price arrangements, to provide time for mitigation of these recent market trends.

Current wording

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.

Previous wording

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. Due to these factors, we place a primary focus on managing production volumes and operating and maintenance expenses as these factors are more controllable by us.

Current wording

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.

Previous wording

In the third quarter of 2024, we began to experience trends with several of our landfill hosts delaying its 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 will impact the timing of collection system enhancement installations and the resulting timing of our production increases. We expect these trends to continue through 2025.

Current wording

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.

Previous wording

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

Current wording

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.

Previous wording

Similar wellfield extraction environmental factors have begun to impact gas extraction at our Apex site. We have initiated collaboration efforts with the landfill to mitigate these impacts but we expect these mitigation efforts to continue in 2025.

Current wording

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.

Previous wording

The landfill host changes to their wellfield collection system at our McCarty facility has contributed to elevated nitrogen in the feedstock received by our facility. Additionally, the landfill host modified the wellfield bifurcation approach which has impacted 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.

Current wording

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.

Previous wording

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 termed 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.

Current wording

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.

Previous wording

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, with heavy emphasis on direct sales to 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.

Current wording

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.

Previous wording

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 expect increased general and administrative expenses associated with our ongoing development of Montauk Ag Renewables in 2024. In August 2024, we accelerated the vesting of certain restricted share awards to a non-executive which were unvested as of June 30, 2024 as a result of the termination of the employee. We recognized $2,911 of non-cash stock compensation expense within general and administration expenses which will not be recurring. We account for share-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. For more information, see Note 14 to our unaudited condensed consolidated financial statements related to share-based compensation.

Current wording

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.

Previous wording

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.

Current wording

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).

Previous wording

One MMBtu of RNG has the same energy content as 11.727 gallons of ethanol, and thus may generate 11.727 RINs under the RFS program.

Current wording

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.

Previous wording

Revenues from the Renewable Natural Gas segment in the third quarter of 2024 were $61,750, an increase of $10,815 (21.2%) compared to $50,935 in the third quarter of 2023. Average commodity pricing for natural gas for the third quarter of 2024 was $2.16 per MMBtu, 15.3% lower than the third quarter of 2023. During the third quarter of 2024, we self-monetized 15,750 RINs, representing a 2,000 increase (14.5%) compared to 13,750 in the third quarter of 2023. Average pricing realized on RIN sales during the third quarter of 2024 was $3.34 as compared to $3.05 in the third quarter of 2023, an increase of 9.5%. This compares to the average D3 RIN index price for the third quarter of 2024 of $3.36 as compared to $3.01 in the third quarter of 2023, an increase of approximately 11.6%. At September 30, 2024, we had approximately 308 MMBtu available for RIN generation and we had approximately 146 RINs generated and unsold. At September 30, 2023, we had approximately 320 MMBtu available for RIN generation and 764 RINs generated and unsold.

Current wording

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.

Previous wording

We produced approximately 41 MWh in Renewable Electricity in the third quarter of 2024, a decrease of 7 MWh (14.6%) from 48 MWh in the third quarter of 2023. Our Security facility produced approximately 5 MWh less in the third quarter of 2024 compared to the third quarter of 2023 as a result us ceasing operations in connection with the first quarter of 2024 sale of the gas rights back to the landfill host.

Current wording

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.

Previous wording

Revenues from Renewable Electricity facilities in the third quarter of 2024 were $4,167, a decrease of $586 (12.3%) compared to $4,753 in the third quarter of 2023. The decrease was primarily driven by the cessation of operations at our Security facility.

Current wording

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.

Previous wording

In the third quarter of 2024, 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 2023. This provides us with certainty of price resulting from our Renewable Electricity sites.

Current wording

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.

Previous wording

Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the third quarter of 2024 were $10,640, a decrease of $277 (2.5%) compared to $10,917 in the third quarter of 2023. We recorded a decrease to our Pico facility earnout of approximately 27.5% during the third quarter of 2024. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of RNG revenues to 17.2% for the third quarter of 2024 from 21.4% in the third quarter of 2023.

Current wording

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.

Previous wording

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the first nine months of 2024 were $1,496, an increase of $5 (0.3%) compared to $1,491 in the first nine months of 2023. As a percentage of Renewable Electricity Generation segment revenues, royalties, transportation, gathering and production fuel expenses increased to 11.1% from 10.8%.

Current wording

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.

Previous wording

Royalties, transportation, gathering, and production fuel expenses in the first nine months of 2024 were $26,702, an increase of $1,114 (4.4%) compared to $25,588 in the first nine months of 2023. We make royalty payments to our fuel supply site partners on the commodities we produce and the associated Environmental Attributes. These royalty payments are typically structured as a percentage of revenue subject to a cap, with fixed minimum payments when Environmental Attribute prices fall below a defined threshold. To the extent commodity and Environmental Attributes’ prices fluctuate, our royalty payments may fluctuate upon renewal or extension of a fuel supply agreement or in connection with new projects. Our fuel supply agreements are typically structured as 20-year contracts, providing long-term visibility into the margin impact of future royalty payments.

Current wording

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.

Previous wording

Depreciation and amortization in the third quarter of 2024 was $6,048, an increase of $702 (13.1%) compared to $5,346 in the third quarter of 2023. The increase was associated with timing of capital investment placed into service primarily driven by our Pico Digestion Capacity Increase project.

Current wording

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.

Previous wording

Other expenses in the first nine months of 2024 was $3,036, a decrease of $305 (9.1%) compared to $3,341 in the first nine months of 2023. The decrease was primarily related to proceeds received from the sale of gas rights ahead of the fuel supply agreement expiration of our Security facility which offset increased interest expense of $604.

Current wording

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.

Previous wording

Income tax expense for the three months ended September 30, 2024 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21.0% primarily related to vesting of restricted stock grants on stock compensation and the benefit from production tax credits.

Current wording

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.

Previous wording

The effective tax rate of 18.9% for the three months ended September 30, 2024 was higher than the rate for the three months ended September 30, 2023 of 17.8% primarily related to vesting of restricted stock grants on stock compensation and the benefit from production tax credits.

Current wording

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.

Previous wording

Operating income in the third quarter of 2024 was $22,708, an increase of $5,927 (35.3%) compared to $16,781 in the third quarter of 2023. RNG operating income for the third quarter of 2024 was $33,616, an increase of $9,553 (39.7%) compared to $24,063 in the third quarter of 2023. Renewable Electricity Generation operating loss for the third quarter of 2024 was $618, a decrease of $1,318 (188.3%) compared to operating income of $700 for the third quarter of 2023.

Current wording

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.