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 Annual Report on Form 10-K. The historical consolidated financial data discussed below reflects the historical results of operations and financial position of Montauk USA, prior to the Equity Exchange on January 4, 2021. Following the Equity Exchange on January 4, 2021, the consolidated financial statements of Montauk USA became our historical financial statements for the periods prior to the Equity Exchange.

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 Annual Report on Form 10-K.

Previous wording

Montauk is a renewable energy company specializing in the recovery and processing of biogas from landfills and other non-fossil fuel sources for beneficial use as a replacement to fossil fuels. We develop, own, and operate RNG projects, using proven technologies that supply RNG into the transportation industry and use RNG to produce Renewable Electricity. We are one of the largest U.S. producers of RNG, having participated in the industry for over 30 years. We established our operating portfolio of 12 RNG and three Renewable Electricity projects through self-development, partnerships, and acquisitions that span six states.

Current wording

Montauk is a renewable energy company specializing in the recovery and processing of biogas from landfills and other non-fossil fuel sources for beneficial use as a replacement to fossil fuels. We develop, own, and operate RNG projects, using proven technologies that supply RNG into the transportation industry and use RNG to produce Renewable Electricity. We are one of the largest U.S. producers of RNG, having participated in the industry for over 30 years. We established our currently operating portfolio of 11 RNG and two Renewable Electricity and development projects through self-development, partnerships, and acquisitions that span seven states.

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. We determined not to transfer a significant amount of D3 RINs generated and available for transfer during the first quarter of 2024. As a result, we have approximately 2,887 RINs in inventory from 2023 gas production and have approximately 7,250 RINs in inventory from 2024 gas production as of the filing of this Report. We have not entered into commitments to transfer these RINs in inventory nor have we entered into agreements to transfer future RINs generated from forecasted future production. The average D3 RIN index price for the fourth quarter of 2023 and January 2024 and through the end of February 2024 was approximately $3.30 and $3.06, respectively.

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

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 four Texas facilities. We intend to capture, clean and liquefy CO2 at select Texas facilities, at which point it will be transported to EE North America (“EENA”), a Texas-based e-methanol facility. The delivery term is expected to last at least 15 years with first delivery expected to begin in 2027. With targeting a commissioning start in 2027, we expect the capital investment to be approximately $15,000 per facility with anticipating spend beginning second half of 2024.

Current wording

In 2024, we signed a contract for the delivery of 140 thousand tons per year of biogenic carbon dioxide (“CO2”) from our four Texas facilities. We intend to capture, clean and liquefy CO2 at select Texas facilities, at which point it will be transported to EE North America (“EENA”), a Texas-based e-methanol facility. The delivery term is expected to last at least 15 years with first delivery expected to begin in 2027. During 2024, we completed the initial site surveys related to locating the CO2 processing equipment, evaluated equipment suppliers, and started engineering design. We continue to target a commissioning start in 2027 and currently expect the capital investment to begin in the second quarter of 2025 for long lead equipment and design engineering.

Previous wording

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

Current wording

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

Previous wording

In 2022, we announced the planned construction of a second RNG processing facility at the Apex landfill. Currently, the landfill host is providing biogas feedstock in excess of our existing processing capacity, therefore triggering the addition of a second facility based on our existing fuel supply agreement. 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 from this increase in waste intake. While the landfill host continues to increase waste intake, we expect there could be a period where we have excess available capacity after the second facility is commissioned. We currently expect commercial operations in the fourth quarter of 2024. We continue to incur capital expenditures for this project.

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 incurring capital expenditures for the project and expect commercial operations in the second quarter of 2025.

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

Previous wording

While these project developments continue, we continue to engage with regulatory agencies in North Carolina related to the resulting power generation derived from swine waste to confirm its eligibility for Renewable Energy Credits under North Carolina’s Renewable Energy Portfolio Standards in anticipation of commercial production. The Turkey location was approved to participate in the Piedmont Natural Gas Renewable Gas Pilot Program which is a step towards obtaining the New Renewable Energy Facility (“NREF”) designation under the North Carolina Utilities Commission. In January 2024, we received notification from the North Carolina Utilities Commission that the Turkey, NC location was approved for an NREF and Certificate of Public Convenience and Necessity. In March 2024, we submitted an amendment to our NREF application for which we expect a decision on the NREF designation during 2024. Obtaining this designation could have an impact on the timing of utility infrastructure at the location. We signed a receipt interconnection agreement with Piedmont Natural Gas for the Turkey, NC location. This agreement is structured to coincide with the development timeline at the Turkey, NC location.

Current wording

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

Previous wording

We continue to expect to have the first of the eight processing lines operational in the second quarter of 2024 and, we are currently planning for a rolling commissioning schedule for the remaining processing lines beginning in the second half of 2024 through the second half of 2025. We continue to expect to begin generating revenues in 2025 and expect to have sufficient capacity to satisfy the Duke REC agreement upon final commissioning during the second half of 2025. At full first phase capacity, we anticipate the ability to process feedstock from over 120 thousand hog spaces per day, which equates to over 200 tons of daily waste collection. We currently estimate the first phase of the project will annually produce approximately 45 to 50 thousand MWh equivalents through the combination of 190 to 200 thousand MMBtu and 25 to 30 thousand MWh. We also estimate that at full processing capabilities, the first phase of the project will additionally produce annually 17 to 20 thousand tons of organic fertilizer alternatives.

Current wording

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

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

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 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. With target commissioning in 2026, we continue to expect the capital investment to range between $85,000 - $95,000, which 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.

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. The landfill has proposed corresponding changes to our agreement, which could impact our existing commissioning schedule. We continue to work with the landfill on these proposed changes to assess what, if any, impacts these changes could have on receipt of required regional regulatory construction permits. The project is anticipated to have production nameplate capacity of approximately 3,600 MMBtu per day, assuming currently forecasted biogas feedstock volumes projected to be available from the host landfill at the time of commissioning. We continue to incur capital expenditures for this project.

Previous wording

In 2023, we announced the planned entrance into South Carolina with the development of a new landfill gas-to-RNG facility. The planned project is expected to contribute approximately 900 MMBtu per day of production capacity upon commissioning. We continue to design and plan for the development and location of the facility as we continue to incur capital expenditures. 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. We expect the utility interconnection initially included in our development assumptions to accept the production from this facility, but will require other upgrades not impacting our interconnection. However, these upgrades have delayed our expectation of commissioning of the facility into 2026.

Current wording

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

Previous wording

We periodically 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.

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

Regulatory, environmental and social factors are key drivers that incentivize the development of RNG and Renewable Electricity projects and influence the economics of these projects. We are subject to the possibility of legislative and regulatory changes to certain incentives, such as RINs, RECs and GHG initiatives. On July 12, 2023, the EPA issued final rules in the Federal Register for the RFS volume requirements for 2023-2025. Final volumes for cellulosic biofuel were set at 838, 1,090 and 1,376 million RINs for the three years 2023, 2024 and 2025, respectively. The EPA did not finalize the eRIN program in this ruling, however, it indicated that it will continue to work on potential paths forward for the eRIN program. However, the EPA did not set a new date for a revised eRIN program. The cellulosic biofuel volumes in the final rule for 2024 and 2025 are lower than the proposed volume as they do not include cellulosic biofuel from eRINs. The final rule also included significant changes to the existing RFS 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 EPA did not finalize the eRIN program in this ruling, however, it indicated that it will continue to work on potential paths forward for the eRIN program. However, the EPA did not set a new date for a revised eRIN program. The cellulosic biofuel volumes in the final rule for 2024 and 2025 are lower than the proposed volume as they do not include cellulosic biofuel from eRINs. The final rule also included significant changes to the existing RFS

Previous 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. However, the industry may see pricing volatility including potential increase to LCFS credit prices. 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. 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.

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. 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.

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 throughout 2024. If we are unable to renew these arrangements based on our historical counterparty share percentages, our ability to monetize RINs from RNG may be impacted. We monetize a portion of our RNG production under fixed-price agreements which provide floor prices in excess of commodity indices.

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. While we did not experience a significant increase in Environmental Attributes shared with pathway providers in our 2024 renewals, our most recent pathway renewals have been at higher percentages than our historical percentages and the currently proposed pathway renewals are for percentages significantly higher than our historical arrangements. Historically, we have monetized less than 25% of our RNG volumes under these fixed-price agreements. We are considering entry into multiple short term contracts throughout 2025, some potentially increasing our historical percentage of volumes monetized under fixed-price arrangements., to provide time for mitigation of these recent market trends.

Previous wording

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

Current wording

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

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. Strategic decisions to not monetize RINs available to be transferred will have an impact on our operating revenues and operating profit. 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. With our royalty payments structured as a percentage of revenue, royalty

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

Though we collaborate with the landfill host at our Rumpke facility on our gas collection efforts, in addition to drought weather anomalies, other wellfield extraction environmental factors have impacted gas extraction at the site. While the site continues to expand their waste intake and we continue to expand wellfield collection, our volumes could be impacted throughout 2024. Mitigation efforts related to wellfield environmental factors will continue into 2024.

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 have been impacted during 2024. Mitigation efforts related to wellfield environmental factors will continue into 2025 as the benefits from 2024 efforts have not achieved anticipated results.

Previous wording

The landfill host at our McCarty facility recently changed its wellfield collection system which 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 the facility. We are working with the landfill host but have currently experienced 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

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

Current wording

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

Previous wording

RNG Production from Our Growth Projects: We anticipate increased production at certain of our existing projects as open landfills continue to take in additional waste and the amount of gas available for collection increases. Delays in commencement of production or extended commissioning issues at a new project or a conversion project would delay any realization of production from that project.

Current wording

RNG Production from Our Growth Projects: We anticipate increased production at certain of our existing projects as open landfills continue to take in additional waste and the amount of gas available for collection increases. Delays in commencement of production or extended commissioning issues at a new project or a conversion project, such as those we are currently experiencing at Blue Granite as described above, would delay any realization of production from that project.

Previous wording

Project Operating and Maintenance Expenses: Operating and maintenance expenses primarily consist of expenses related to the collection and processing of biogas, including biogas collection system operating and maintenance expenses, biogas processing, operating and maintenance expenses, and related labor and overhead expenses. At the project level, this includes all labor and benefit costs, ongoing corrective and proactive maintenance, project level utility charges, rent, health and safety, employee communication, and other general project level expenses. Unanticipated feedstock processing or gas conditioning equipment failures occurring outside our planned preventative maintenance program can increase project operating and maintenance expenses and reduce production volumes.

Current wording

Operating and Maintenance Expenses: Operating and maintenance expenses primarily consist of expenses related to the collection and processing of biogas, including biogas collection system operating and maintenance expenses, biogas processing, operating and maintenance expenses, and related labor and overhead expenses. At the project level, this includes all labor and benefit costs, ongoing corrective and proactive maintenance, project level utility charges, rent, health and safety, employee communication, and other general project level expenses. Unanticipated feedstock processing or gas conditioning equipment failures occurring outside our planned preventative maintenance program can increase project operating and maintenance expenses and reduce production volumes. The timing of gas conditioning and process equipment preventative maintenance intervals could impact the timing and amount of our operating and maintenance expenses within a given quarter.

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. We also expect increased general and administrative expenses associated with share-based compensation related to the board of directors approval of grants of stock options to the executives of the Company in April 2023. The Company accounts for stock-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. For more information, see Note 15 to our audited consolidated financial statements.

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. The Company accounts for stock-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. For more information, see Note 15 to our audited consolidated financial statements.

Previous wording

Depreciation and Amortization: Expenses related to the recognition of the useful lives of our intangible and fixed assets. We spend significant capital to build and own our facilities. In addition to development capital, we annually reinvest to maintain these facilities.

Current wording

Depreciation, Depletion and Amortization: Expenses related to the recognition of the useful lives of our intangible and fixed assets. We spend significant capital to build and own our facilities. In addition to development capital, we annually reinvest to maintain these facilities.

Previous wording

We produced 5,499 MMBtu of RNG during 2023, a decrease of 23 MMBtu (0.4%) from the 5,522 MMBtus produced in 2022. Reduced preventative maintenance and wellfield optimization led to increased production, notably with our Atascocita facility producing 84 MMBtu more in 2023 compared to 2022. Offsetting these improvements were unrelated wellfield quality issues and weather anomalies which lowered production, led by our Rumpke facility producing 95 fewer MMBtu in 2023 compared to 2022.

Current wording

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

Previous wording

Revenues from the Renewable Natural Gas segment in 2023 were $156,455, a decrease of $39,763 (20.3%) compared to $196,218 in 2022. Average commodity pricing for natural gas for 2023 was 58.7% lower than the prior year. During 2023, we self-marketed 44,936 RINs, representing a 1,113 increase (2.5%) compared to 43,823 in 2022. The increase was primarily related to the prior period RIN volumes carried over into 2023 compared to 2022. Average pricing realized on RIN sales during 2023 was $2.71 as compared to $3.25 in 2022, a decrease of 16.6%. This compares to the average D3 RIN index price for 2022 of $2.63 being approximately 11.7% lower than the average D3 RIN index price in 2022 of $2.98. At December 31, 2023, we had approximately 0.4 million MMBtus available for RIN generation and had approximately 0.1 million RINs generated and unsold. We had approximately 0.4 million MMBtus available for RIN generation and approximately 0.7 million RINs generated and unsold at December 31, 2022.

Current wording

Revenues from the Renewable Natural Gas segment in 2024 were $157,983, an increase of $1,528 (1.0%) compared to $156,455 in 2023. Average commodity pricing for natural gas for 2024 was 17.2% lower than the prior year. During 2024, we self-marketed 36,639 RINs, representing an 8,297 decrease (18.5%) compared to 44,936 in 2023. The decrease was primarily related to the decision to not self-market a significant amount of RINs in inventory in the fourth quarter of 2024. Average pricing realized on RIN sales during 2024 was $3.28 as compared to $2.71 in 2023, an increase of 21.0%. This compares to the average D3 RIN index price for 2024 of $3.12 being approximately 18.6% higher than the average D3 RIN index price in 2023 of $2.63. At December 31, 2024, we had approximately 291 MMBtus available for RIN generation and had approximately 6,822 RINs generated and unsold. We had approximately 358 MMBtus available for RIN generation and approximately 108 RINs generated and unsold at December 31, 2023. We have entered into commitments and transferred all of our RINs in inventory related to our 2024 RNG production.

Previous wording

We produced 194 MWh in Renewable Electricity in 2023, an increase of approximately 4 MWh (2.1%) compared to 190 MWh in 2022. Our Security facility produced 5 MWh more in 2023 compared to 2022 as a result of the prior period engine maintenance.

Current wording

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

Previous wording

Royalties, transportation, gathering and production fuel expenses for the Company’s RNG facilities for 2023 were $32,876, a decrease of $9,463 (22.4%) compared to $42,339 in 2022. Our Pico facility earnout increased approximately 12.8% during 2023 compared to 2022 based on our current estimate of the present value of the earnout. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of RNG revenues to 21.0% for 2023 from 21.6% in 2022.

Current wording

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

Previous wording

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for 2023 were $1,985, an increase of $161 (8.8%) compared to $1,824 in 2022 and as a percentage of Renewable Electricity Generation segment revenues increased from 10.6% to 10.8%.

Current wording

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

Previous wording

Royalties, transportation, gathering, and production fuel expenses in 2023 were $34,861, a decrease of 9,302 (21.1%) compared to $44,163 in 2022. 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 2024 were $31,502, a decrease of 3,359 (9.6%) compared to $34,861 in 2023. We make royalty payments to our fuel supply site partners on the commodities we produce and the associated Environmental Attributes. These royalty payments are typically structured as a percentage of revenue subject to a cap, with fixed minimum payments when Environmental Attribute prices fall below a defined threshold. To the extent commodity and Environmental Attributes’ prices fluctuate, our royalty payments may fluctuate upon renewal or extension of a fuel supply agreement or in connection with new projects. Our fuel supply agreements are typically structured as 20-year contracts, providing long-term visibility into the margin impact of future royalty payments.

Previous wording

Depreciation and amortization in 2023 was $21,158, an increase of $458 (2.2%) compared to $20,700 in 2022. The increase is associated with the timing of capital investments placed into service in 2023.

Current wording

Depreciation, depletion and amortization in 2024 was $23,515, an increase of $2,357 (11.1%) compared to $21,158 in 2023 . The increase is associated with the timing of capital investments placed into service in 2024, specifically our Pico digestion capacity increase and Raeger capital improvement projects.

Previous wording

As of December 31, 2023, we utilized all of our limited NOLs. We have an additional $12,986 of federal net operating losses that are not expected to be realizable due to loss limitation rules. As of December 31, 2022, we had utilized all of our non-limited NOLs.

Current wording

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

Previous wording

We have approximately $13,042 in federal tax credit carryforwards that expire 20 years from the date incurred, which will begin to expire in tax year 2026. We have pre-tax state net operating loss carryforwards of $18,059 which will begin to expire in tax year 2026.

Current wording

As of December 31, 2024 and 2023, we had approximately $12,274 and $13,042, respectively, federal tax credit carryforwards that expire 20 years from the date incurred, which will begin to expire in tax year 2026. As of December 2024, we continue to carry state NOL balances in Pennsylvania and Florida from 2023.

Previous wording

For the year ended December 31, 2023 and 2022, income tax expense was $3,418 and $8,048, respectively and has been calculated resulting in an annual effective tax rate (“AETR”) of 18.61%, respectively.

Current wording

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

Previous wording

Operating profit in 2023 was $23,640, a decrease of $20,926 (47.0%) compared to $44,566 in 2022. RNG operating profit for 2023 was $59,286, a decrease of $35,153 (37.2%) compared to $94,439 in 2022. Renewable Electricity Generation operating loss for 2022 was $595, a decrease of $6,424 (91.5%) compared to $7,019 in 2022.

Current wording

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

Previous wording

We calculated and recorded impairment losses of $902 for 2023, a decrease of $3,950 (81.4%) compared to $4,852 for 2022. In 2023, we recorded impairments of $777 for specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use as well as $125 in obsolete REG critical spares. In 2022, we recorded an impairment of $2,133 for a REG site wherein the forecast future cash flows did not exceed the carrying value of the site’s long lived assets. A second REG site was impaired for $1,393 due to discrete conclusion that certain assets acquired in the May 2021 Montauk Ag Renewables Acquisition would no longer be utilized. Also in 2022, we recorded an impairment at an RNG facility for approximately $1,108 due to the specific identification of certain assets no longer being capable of use as designed.

Current wording

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

Previous wording

At December 31, 2023 and 2022, our cash and cash equivalents, net of restricted cash, was $73,811 and $105,177, 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.

Current wording

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

Previous wording

At December 31, 2023, we had debt before debt issuance costs of $64,000, compared to debt before debt issuance costs of $72,000 at December 31, 2022.

Current wording

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

Previous wording

As of December 31, 2023, $64,000 was outstanding under the term loan and we had no outstanding borrowings under the revolving credit facility. The term loan amortizes in quarterly installments of $2,000 through December 2024, quarterly installments of $3,000 from 2025 through the maturity, with a final payment of $32,000, on December 21, 2026. Interest rates were 6.11% and 4.12% at December 31, 2023 and 2022, respectively. The revolving and term loans under the Amended Credit Agreement bear interest at the BSBY Margin or Base Rate Margin based on our Total Leverage Ratio (in each case, as those terms are defined in the Amended Credit Agreement).

Current wording

As of December 31, 2024, $56,000 was outstanding under the term loan and we had no outstanding borrowings under the revolving credit facility. The term loan amortizes in quarterly installments of $2,000 through December 2024, quarterly installments of $3,000 from 2025 through maturity, with a final payment of $32,000, on December 21, 2026. Interest rates were 6.01% and 6.11% at December 31, 2024 and 2023, respectively. The revolving and term loans under the Amended Credit Agreement bore interest at the BSBY Margin or Base Rate Margin based on our Total Leverage Ratio (in each case, as those terms are defined in the Amended Credit Agreement) as of September 30, 2024. The BSBY ceased publication on November 15, 2024, and the current debt agreement was amended to utilize the Secured Overnight Financing Rate Index ("SOFR"), plus applicable margin.