Montauk Renewables Inc

Previous wording

In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Cautionary Note Regarding Forward-Looking Statements,” “Item 1A.–Risk Factors” of our 2023 Annual Report, our Form 10-Q for the period ending March, 31 2024 and elsewhere in this report.

Current wording

In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Cautionary Note Regarding Forward-Looking Statements,” “Item 1A.–Risk Factors” of our 2023 Annual Report, and elsewhere in this report.

Previous wording

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. 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 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 currently expect commercial operations in the second quarter of 2025. We do not expect a material operational production impact in 2024 based on the commissioning of the second facility.

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 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.

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 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 for their system to accommodate our interconnection. These utility upgrades do not directly impact our interconnection project but have delayed our commissioning expectation of the facility in 2026. Our pace of capital deployment for this project will match the expected timing related to the utility interconnection but do not expect to incur significant capital expenditures on this project through the rest of 2024.

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 is expected to contribute approximately 900 MMBtu per day of production capacity upon commissioning. We continue to experience delays with our interconnection, most recently due to the utility informing us of their near-term prioritization of remediation efforts from the impacts of Hurricane Helene. 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 for their system to accommodate our interconnection. The prioritization of recovery from Hurricane Helene will delay these utility upgrades and directly impact our interconnection schedule delaying our commissioning expectation of this facility into 2027. Our pace of capital deployment for this project has slowed due to the delay of the utility and we do not expect to incur significant capital expenditures on this project through the remainder of 2024. We expect to resume capital expenditures for this project mid 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 continue to target commissioning in 2026 and expect the capital investment to range between $85,000 - $95,000. 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. 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.

Previous wording

EE North America's (“EENA”), 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 and received the first site plans from EENA. We continue to anticipate commissioning to begin in 2027 and we continue to expect the capital investment to be approximately $15,000 per facility with anticipating spend beginning in the second half of 2024, although we have not yet committed capital to this project.

Current 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.

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 eight 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

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.

Previous wording

We continue to engage with regulatory agencies in North Carolina to confirm the means and methods of power generation from swine waste which will be eligible for Renewable Energy Credits under North Carolina’s Renewable Energy Portfolio Standards in anticipation of commercial production. In early 2024, we received notification from the North Carolina Utilities Commission that the Turkey, NC location was approved for a New Renewables Energy Facility ("NREF") designation and Certificate of Public Convenience and Necessity. In the first quarter of 2024, we submitted an amendment to our NREF application and the public staff of the North Carolina Utilities Commission ("NCUC") deemed our amendment complete and in August 2024 we received notice from the NCUC that our NREF amendment application was approved. While this approval is a critical path item in the timing of the utility infrastructure design and other balance-of-plant componentry at our Turkey, NC facility, we continue to work through the regulatory process and with utility providers to confirm the means and methods of power generation from swine waste in NC. 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

We continue to engage with regulatory agencies in North Carolina to confirm the means and methods of power generation from swine waste which will be eligible for Renewable Energy Credits under North Carolina’s Renewable Energy Portfolio Standards in anticipation of commercial production. In early 2024, we received notification from the North Carolina Utilities Commission that the Turkey, NC location was approved for a New Renewables Energy Facility ("NREF") designation and Certificate of Public Convenience and Necessity (“CPCN”). In the first quarter of 2024, we submitted an amendment to our NREF application, deemed complete by the public staff of the North Carolina Utilities Commission ("NCUC"). In August 2024, we received notice from the NCUC that our NREF amendment application was approved. In October 2024, we received notice from the NCUC that our application for a CPCN and registration for a NREF related to the sale of electricity to generate swine RECs was approved for public notice. We continue to work with the utility providers regarding the utility infrastructure design for the electricity interconnection. Survey and pre-construction activities for the electricity interconnection remain ongoing and in line with our commissioning schedule.

Previous wording

During the second quarter of 2024, we commissioned the pilot reactor we relocated from Magnolia, NC to our Turkey, NC processing facility. We do not expect this reactor to be operating commercially during 2024, but it will be operated to allow various data collection and testing activities to occur. In connection with the hog space cycle times with our feedstock supply partners, we expect to use this first reactor to test and refine feedstock conveyance, equipment processing, product gas composition, and the composition of the solid output. Though this relocated reactor was previously operated prior to the 2021 Montauk Ag Renewables Acquisition, we plan to use this commissioning process to test the improvements made to the reactor. We are also continuing to staff the Turkey, NC location. We continue to plan for a rolling commissioning schedule for the remaining processing lines through the second half of 2025. We expect to begin generating revenues in 2025 and have sufficient capacity to satisfy the Duke REC agreement after final commissioning during the second half of 2025.

Current wording

We continue to use the pilot reactor that was relocated and previously operated prior to the 2021 Montauk Ag Renewables Acquisition. In connection with the hog space cycle times with our feedstock supply partners, the pilot reactor testing includes refining feedstock conveyance, equipment processing, product gas composition, and the composition of the solid output. We have processed tested both the biogas and micronutrient organic fertilizer alternatives. We are also continuing to staff the Turkey, NC location. We continue to plan for a rolling commissioning schedule for the remaining processing lines through the second half of 2025. We expect to begin generating revenues in 2025 and have sufficient capacity to satisfy the Duke REC agreement after final commissioning during the second half of 2025.

Previous wording

These feedstock supply agreements have allowed us to continue to refine our expected feedstock collection process. This process will involve installing equipment on the farms under agreements, collect feedstock and process the waste through multiple phases of solids concentration at both the farm and our Turkey, NC location. During the second quarter of 2024, we have completed the majority of the installation of collection process equipment on two farms for which we have feedstock agreements.

Current wording

The feedstock supply agreements we have signed allowed us to continue to refine our expected feedstock collection process. This process involves installing equipment on the farms under agreements, collecting feedstock and processing the waste through multiple phases of solids concentration at both the farm and our Turkey, NC location. We have completed the majority of the installation of collection process equipment on two farms for which we have feedstock agreements but continue to refine our collection methods. During the fourth quarter of 2024, we continue to bring additional farms under contract to secure additional feedstock supply.

Previous wording

We 'll continue to evaluate opportunities to convert our remaining facility 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 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.

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 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 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.

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. Final rules are expected for public comment sometime in the third quarter of 2024 with LCFS amendments in first quarter of 2025. 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. 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. 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. 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.

Previous wording

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.

Current wording

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 throughout 2024. While we have not experienced a significant increase in Environmental Attributes shared with pathway providers related to our current renewals, our current pathway renewals have been at higher percentages that our historical counterparty share percentages. If these pathway share percentages continue to increase over our historical counterparty share percentages, we will consider monetizing a larger portion of our RNG through fixed-price contracts to mitigate this impact. 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 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.

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 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. 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.

Previous wording

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

Previous wording

The landfill host at our McCarty facility 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 continue to have lower volumes of feedstock available to be processed at the McCarty facility.

Current 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.

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

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 continued 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 2023. In August 2024, we accelerated the vesting of certain restricted share awards to non-executives which were unvested as of June 30, 2024 as a result of the termination of an 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 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.

Previous wording

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

Current wording

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

Previous wording

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

Current wording

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

Previous wording

We produced 2,794 MMBtu of RNG during the first six months of 2024, an increase of 11 MMBtu (0.4%) over the 2,783 MMBtu produced in the first six months of 2023. Our Coastal facility produced 82 MMBtu more in the first six months of 2024 compared to the first six months of 2023 as a result of plant processing equipment improvements and wellfield operational enhancements. Our Pico facility produced 22 MMBtu more in the first six months of 2024 compared to the first six months of 2023 as a result of commissioning our dairy digestion expansion project. Our Raeger facility produced 18 MMBtu more in the first six months of 2024 compared to the first six months of 2023 as a result of plant processing equipment improvements. Offsetting these increases was our Rumpke facility which produced 105 MMBtu less in the first six months of 2024 compared to the first six months of 2023 as a result of reduced feedstock inlet and, process equipment failures which have since been corrected, in the first six months of 2024.

Current wording

We produced 1,392 MMBtu of RNG during the third quarter of 2024, an increase of 12 MMBtu (0.9%) compared to 1,380 MMBtu produced in the third quarter of 2023. Our Pico facility produced 27 MMBtu more in the third quarter of 2024 compared to the third quarter of 2023 as a result of commissioning our dairy digestion expansion project. Our Raeger facility produced 15 MMBtu more in the third quarter of 2024 compared to the third quarter of 2023 as a result of plant processing equipment improvements and increased inlet flows. Our Galveston and Coastal facilities produced 27 more MMBtu in the third quarter of 2024 compared to the third quarter of 2023 due to previously disclosed third quarter of 2023 dry weather conditions impacting gas feedstock availability. Our Rumpke facility produced 59 fewer MMBtu in the third quarter of 2024 compared to the third quarter of 2023 as a result of reduced feedstock inlet due to ongoing wellfield extraction environmental factors. Our Atascocita facility produced 22 fewer MMBtu in the third quarter of 2024 compared to the third quarter of 2023 as a result of weather driven utility outages which impacted our production.

Previous wording

Revenues from the Renewable Natural Gas segment in the second quarter of 2024 were $38,838, a decrease of $9,771 (20.1%) compared to $48,609 in the second quarter of 2023. Average commodity pricing for natural gas for the second quarter of 2024 was $1.89 per MMBtu, 10.0% lower than the second quarter of 2023. During the second quarter of 2024, we self-monetized 10,000 RINs, representing a 7,441 decrease (42.7%) compared to 17,441 in the second quarter of 2023. Average pricing realized on RIN sales during the second quarter of 2024 was $3.12 as compared to $2.16 in the second quarter of 2023, an increase of 44.4%. This compares to the average D3 RIN index price for the second quarter of 2024 of $3.20 as compared to $2.16 in the second quarter of 2023, an increase of approximately 48.1%. At June 30, 2024, we had approximately 357 MMBtu available for RIN generation and we had approximately 4,707 RINs generated and unsold. At June 30, 2023, we had approximately 367 MMBtu available for RIN generation and 2,966 RINs generated and unsold.

Current 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.

Previous wording

We produced approximately 45 MWh in Renewable Electricity in the second quarter of 2024, a decrease of 4 MWh (8.2%) from 49 MWh in the second quarter of 2023. Our Security facility produced approximately 3 MWh less in the second quarter of 2024 compared to the second 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 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.

Previous wording

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

Current 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.

Previous wording

Total general and administrative expenses in the second quarter of 2024 were $8,737, a decrease of $8 (0.1%) compared to $8,745 for the second quarter of 2023. Our professional fees decreased approximately $257 (26.9%) in the second quarter of 2024 compared to the second quarter of 2023. Employee related costs, including stock-based compensation costs were $5,366 in the second quarter of 2024, an increase of $183 (3.5%) compared to $5,183 in the second quarter of 2023. The increase is primarily related to the forfeited stock awards of approximately $696 in the second quarter of 2023.

Current wording

Total general and administrative expenses in the third quarter of 2024 were $10,037, an increase of $2,189 (27.9%) compared to $7,848 for the third quarter of 2023. Employee related costs, including stock-based compensation costs were $7,216 in the third quarter of 2024, an increase of $2,695 (59.6%) compared to $4,521 in the third quarter of 2023. The increase was primarily related to the accelerated vesting of certain restricted share awards as a result of the termination of an employee. Our corporate insurance fees decreased approximately $262 (17.1%) in the third quarter of 2024 compared to the third quarter of 2023.

Previous wording

Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the second quarter of 2024 were $8,568, a decrease of $1,147 (11.8%) compared to $9,715 in the second quarter of 2023. This decrease is primarily related to lower revenues recognized in the second quarter of 2024. Partially offsetting this decrease was an increase to our Pico facility earnout of approximately 8.3% during the second quarter of 2024. Royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues to 22.1% for the second quarter of 2024 from 20.0% in the second quarter of 2023.

Current 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.

Previous wording

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the second quarter of 2024 were $508, an increase of $18 (3.7%) compared to $490 in the second quarter of 2023. As a percentage of Renewable Electricity Generation segment revenues, royalties, transportation, gathering and production fuel expenses increased to 11.3% from 10.6%.

Current wording

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the third quarter of 2024 were $467, a decrease of $66 (12.4%) compared to $533 in the third quarter of 2023. As a percentage of Renewable Electricity Generation segment revenues, royalties, transportation, gathering and production fuel expenses remained unchanged at 11.2%.

Previous wording

Royalties, transportation, gathering, and production fuel expenses in the second quarter of 2024 were $9,077, a decrease of $1,128 (11.1%) compared to $10,205 in the second quarter 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 third quarter of 2024 were $11,107, a decrease of $343 (3.0%) compared to $11,450 in the third quarter 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.

Previous wording

Depreciation and amortization in the second quarter of 2024 was $5,823, an increase of $572 (10.9%) compared to $5,251 in the second quarter of 2023. The increase is associated with timing of capital investment placed into service related to our Pico Digestion Capacity Increase project.

Current 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.

Previous wording

We calculated and recorded impairment losses of $171 in the second quarter of 2024, a decrease of $103 (37.6%) compared to $274 in the second quarter of 2023. The impairment losses in the second quarter of 2024 primarily relates to various RNG equipment that was deemed obsolete or no longer suitable for current operations. The second quarter of 2023 impairment relates to specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use and recorded in the Company's RNG segment.

Current wording

We calculated and recorded impairment losses of $533 in the third quarter of 2024, an increase of $482 (945.1%) compared to $51 in the third quarter of 2023. The specifically identified impairments were for various RNG equipment that was deemed obsolete or inoperable for current operations and REG assets that were impacted under initial startup testing for one of our REG construction work-in-progress sites. The third quarter of 2023 impairment related to specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use and recorded in our RNG segment. None of the impairments were related to expected future cash flows.

Previous wording

Other expenses in the second quarter of 2024 was $1,236, an increase of $615 (99.0%) compared to $621 in the second quarter of 2023. The increase is primarily related to an increase in interest expense of $575 from the second quarter of 2024 compared to the second quarter of 2023.

Current wording

Other expenses in the third quarter of 2024 was $1,695, an increase of $656 (63.1%) compared to $1,039 in the third quarter of 2023. The increase was primarily related to an increase in interest expense of $540 from the third quarter of 2024 compared to the third quarter of 2023.

Previous wording

Income tax expense for the three months ended June 30, 2024 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21.0% primarily due to the benefit from production tax credits.

Current 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.

Previous wording

The effective tax rate of 39.9% for the six months ended June 30, 2024 was higher than the rate for the six months ended June 30, 2023 of 4.4% primarily due to discrete events related to the vesting of restricted stock grants on stock compensation as compared to the year to date pre-tax book income. The prior year period benefit was related to the year to date pre-tax book loss.

Current 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.

Previous wording

Operating Income (Loss) for the Six Months Ended June 30, 2024 and 2023

Current wording

Operating Income (Loss) for the Three Months Ended September 30, 2024 and 2023

Previous wording

Operating income in the second quarter of 2024 was $868, a decrease of $12,689 (93.6%) compared to $13,557 in the second quarter of 2023. RNG operating income for the second quarter of 2024 was $11,715, a decrease of $11,314 (49.1%) compared to $23,029 in the second quarter of 2023. Renewable Electricity Generation operating loss for the second quarter of 2024 was $1,969, an increase of $1,393 (241.8%) compared to $576 for the second quarter of 2023.

Current 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.

Previous wording

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

Current wording

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

Previous wording

Total revenues in the first six months of 2024 were $82,125, an increase of $9,716 (13.4%) compared to $72,409 in the first six months of 2023. The increase is primarily related to an increase in Realized RIN pricing of approximately 39.5% during the first six months of 2024 compared to the first six months of 2023.

Current wording

Total revenues in the first nine months of 2024 were $148,042, an increase of $19,945 (15.6%) compared to $128,097 in the first nine months of 2023. The increase was primarily related to an increase in Realized RIN pricing of approximately 25.5% during the first nine months of 2024 compared to the first nine months of 2023.