Good day, everyone, and thank you for participating in today's conference call. I would like to turn the call over to John Sorolle as he provides some important cautions measures contained in the earnings material or made on this call. John, please go ahead.

Thank you, and good day, everyone. Welcome to Montauk Renewable's earnings conference call to review the second quarter 2025 financial and operating results and developments. I'm John Sorolle, Chief Legal Officer and Secretary at Montauk. Joining me today are Sean McLean, Montauk's President and Chief Executive Officer to discuss business development, and Kevin Van Aslen, Chief Financial Officer, to discuss our second quarter 2025 financial and operating results. At this time, I would like to direct your attention to our forward-looking disclosure statement. During this call, certain comments we make constitute forward-looking statements and, as such, involve a number of assumptions, risks, and uncertainties that could cause the company's actual results or performance to differ materially from those expressed in or implied by such forward-looking statements. These risk factors and uncertainties are detailed in Montauk Renewable's SEC filings. Our remarks today may also include non-GAAP financial measures. We present EBITDA and adjusted EBITDA metrics because we believe the measures assist investors in analyzing our performance across reporting periods on a consistent basis by excluding items that we do not believe are indicative of our core operating performance. These non-GAAP financial measures are not prepared in accordance with generally accepted accounting principles. Additional details regarding these non-GAAP financial measures, including reconciliations to the most directly comparable GAAP financial measures, can be found in our slide presentation and in our second quarter 2025 earnings press release in Form 10-Q, issued and filed on August 6, 2025. These are available on our website at ir.montaukrenewables.com. After our remarks, we will open the call to analysts' questions. We ask that you please keep to one question to accommodate as many questions as possible. With that, I will

turn the call over to Sean. Thank you, John. Good day, everyone, and thank you for joining our call. On June 13, 2025, the EPA released the partial waiver of the 2024 cellulosic biofuel volume requirement, the RFS standards for 2026 and 2027, the partial waiver of the 2025 cellulosic biofuel volume requirement, and other changes in their proposed rule. The final 2024 cellulosic biofuel volume requirement was reduced from $1,090,000 to $1,010,000,000 D3 RINs. This reduction was based on actual volumes of D3 RINs generated in 2024. In addition, the EPA is making cellulosic waiver credits available for 2024 as an additional compliance flexibility measure for obligated parties. This final rule has limited direct impact to Montauk as we have sold all of our 2024 RINs. For 2025, the EPA has proposed cellulosic biofuel volumes for 2025 to be reduced from $1,376,000,000 to $1,190,000,000 RINs and to make cellulosic waiver credits available for 2025. These proposals, coupled with the EPA's biogas regulatory reform rule of matching the production of RNG with the dispensing of RNG to transportation, appear to have limited the pricing level at which the D3 RIM currently trades. The proposed cellulosic biofuel volume requirements for 2026 and 2027 are 1,300,000,000 and 1,360,000,000 D3 RIMs, respectively. In justification of these lower-than-expected volumes and the suggestion that small refinery exemptions be potentially revisited, the EPA has expressed their view that cellulosic ring generation from biogas CNG LNG during 2026 to 2030 will be constrained by the total usage capacity of CNG LNG as transportation fuel. In the first quarter of 2025, we entered into an agreement with Pioneer Renewables Energy Marketing to form a joint venture, Green Wave Energy Partners. The primary goal of the joint venture is to help address this limited capacity of RNG utilization for transportation by offering third-party RNG volume producers access to exclusive, unique, and proprietary transportation pathways. We expect to be the RIN separator for the joint venture and expect to receive separated RINs as our distributions. While we have yet to realize material benefits from the joint venture through the second quarter, we have begun successfully contracting, dispensing, and separating RINs through these proprietary transportation pathways. We continue our development efforts in North Carolina with an expectation to commence production and revenue generation activities in early 2026. As previously noted, the favorable change in swine renewable energy credit generation legislation enacted by the state of North Carolina in 2024 has us engaged on various stages of negotiations with obligated utilities to provide wrecks from our expected 2026 production. We have executed a power purchase agreement for the expected power to be produced from the first phase of electric production. The term of this PPA begins once we commission the facility and covers 100% of the electricity produced for 10 years. The PPA price is based on said tariffs and considers various impacts, including, but not limited to, demand, season, and time of day, and we believe the average price considering these factors of $48 per megawatt hour is in line with various southeastern United States power markets ranging from 40 to 60 megawatt hours. This favorable change in swine renewable energy credit generation legislation has compelled us to refine development efforts in North Carolina to focus on feedstock exclusively from swine waste, no longer inclusive of an agricultural component. Additionally, we've refined our production focus for this first phase to be exclusively electricity generation. Correspondingly, we continue to optimize the collection and transportation of swine feedstock from the collection farms to the centralized processing location, including the removal of low-energy content liquid waste. Such efforts include the pelletization of collected waste and the incorporation of additional upstream processes using screw press and centrifuge technologies. Our feedstock collection and transportation optimization efforts are expected to have an impact on both the number of farm serviced as well as the associated equipment and operating costs. Given the opportunity set afforded by the change in legislation and our refined focus on both the feedstock optimization and increased electricity generation, we are increasing the range of capital investment expected for this first phase to $180 million to $220 million. The revised estimate of the total project to the extent impacting 2025 is included in our 2025 development capital expenditures range. We have successfully completed the construction and commissioning of a second RNG processing facility at the Apex Landfill. As previously noted, the construction of the second facility was triggered by the landfill host projections of biogas feedstock volumes in excess of the original facility's production capacity, driven by the landfill host waste intake projections. The second facility provides us with an additional 2,100 mmVTU per day of production capacity. We continue to expect a period of excess production capacity as the landfill host continues to increase their waste intake. In 2024, we signed a contract for the annual delivery of 140,000 tons per year of biogenic carbon dioxide. We intend to capture, clean, and liquefy CO2 at select Texas facilities, at which point EE North America will transport it to a Texas-based emethanol facility. The delivery term is expected to last 15 years, with the first delivery expected to begin in late 2027. During the period prior to commissioning, we have been recognizing an exclusivity fee related to the minimum tons of CO2. The annual price per ton under the contract is adjusted by the U.S. Consumer Price Index. The agreement with EENA also includes a 50% sharing of any available tax attributes generated by us under Code Section 45Q, Carbon Dioxide Sequestration Credit, in the Inflation Reduction Act as applicable. There are other revenue sharing components under the agreement to the extent we're able to produce CO2 prior to EENA accepting delivery, excluding any estimate of tax attributes and including a U.S. consumer price index range of 2.5% to 3% annually. we estimate the total revenues under this 15-year term to provide an annual minimum of 140,000 tons of CO2 will range between $170 million to $201 million in total. We have completed the initial type surveys related to the location of the CO2 processing equipment, have evaluated equipment suppliers, and started engineering design. We continued to target a commissioning start in 2027 and began incurring capital expenditures for long lead items and design engineering in the second quarter of 2025. Also in 2024, we announced a collaboration with Envolon to transform methane emissions from waste stream biogas into high-value carbon-negative fuel. Leveraging Envolon's patented technology, the initial pilot was a small-scale demonstration of recovering and converting biogas into green methanol. The initial pilot project at our Atascosita facility in Houston, Texas exceeded its anticipated results. Following a successful field demonstration project, together with Embolon, we plan to deploy a portfolio of biogas sites with an aggregate annual production capacity of up to 50,000 metric tons of green methanol by 2030. We do not expect short-term financial benefits from this joint development venture, nor a disruption to our operations. And with that, I will turn the call over to Kevin.

Thank you, Sean. I will be discussing our second quarter 2025 financial and operating results. Please refer to our earnings press release in the supplemental slides that have been posted to our website for additional information. Our profitability is highly dependent on the market price of environmental attributes, including the market price of rents. RINs. As we self-market a significant portion of our RINs, a strategic decision not to commit to transfer available RINs during a period will impact our revenue and operating profit. The impact of the EPA rulemaking associated with the implementation of BRRR K2 separation and the extension of the 2024 RIN compliance period has temporarily impacted our commitment timing of our 2025 RNG production. At June 30th, 2025, we had approximately 3 million RINs generated and unseparated. We expect this timing between RINs generated but unseparated and RINs available for sale to only impact 2025, which is the year DRRR became effective. We had approximately 108,000 RINs in inventory from 2025 RNG production as of June 30th, 2025. These RINs were transferred in July under a commitment entered into in June 2025 at a price of $2.42. The average D3 rent index price for the second quarter of 2025 was approximately $2.36. Total revenues in the second quarter of 2025 were $45.1 million, an increase of $1.8 million, or 4.1%, compared to $43.3 million in the second quarter of 2024. The increase is primarily related to timing of revenues recognized under a short-term fixed price contract in the 2025 second quarter when compared to the amount of RINs available but unsold at June 30, 2024. Partially offsetting this impact was a decrease in realized RIN pricing during the second quarter of 2025 to $2.42 compared to $3.12 in the second quarter of 2024 and a reduction in RINs available for sale as a result of the EPA DRRR reform. Total general and administrative expenses were $9.0 million for the second quarter of 2025, an increase of $0.3 million, or 3.5%, compared to $8.7 million in the second quarter of 2024. Employee-related costs, including stock-based compensation, were $6.1 million in the second quarter of 2025, an increase of $0.7 million, or 13.7%, compared to $5.4 million in the second quarter of 2024. The increase in non-cash stock-based compensation costs relate to a one-time acceleration of approximately $1.6 million in the second quarter of 2025 due to the termination of an employee, which we do not expect to recur in the second half of 2025. This compares to unrecognized stock compensation costs of $4.9 million that will be recognized over approximately the following three-in-one-quarter years. Before turning to our operating segment, metrics, I want to address the recent tax law changes occurring with the passage of the One Big Beautiful Bill Act. On July 4, 2025, this bill was signed into law. Tax changes are enacted in the period past, and as such, we will adopt applicable changes beginning in the third quarter of 2025. This legislation includes significant tax and spending policies, extends or enhances various components of the tax cuts in jobs acts and made various changes to the tax credits included in the Inflation Reduction Act. Please refer to our 2025 Second Quarter Form 10-Q filed on August 6, 2025 for various aspects of the tax law changes we are reviewing. Included in our second quarter of 2025 tax provision is approximately $0.8 million in tax benefits from investment tax credits for certain qualifying property resulting from our 2024 PICO Digestion Expansion Project. Based on our PICO project study, we are better positioned to understand the Inflation Reduction Act investment tax credits for qualifying projects and assets. For other qualifying projects, we now believe that approximately 50 to 75 percent of the project capital will qualify for investment tax credits, and depending upon a wide variety of factors for projects started within State Harbor Guidelines, the tax benefits could range up to 30 percent. to our second APEX RNG facility placed in the service this quarter, we expect to generate tax attribute benefits in our 2025 tax year and to include these benefits in our annual tax provision as of December 31st, 2025. For estimation purposes, we believe that based on approximately 50% of the project capital qualifying and with safe harbor guidelines not being met, investment tax credits could range between $1.0 million and $2.1 million for this project. For similar other qualifying projects, we continue to believe that 50 to 75 percent of the capital will qualify at a 6 to 12 percent investment tax credit, subject to various safe harbor applicability. Turning to our segment operating metrics, I'll begin by reviewing our renewable natural gas segment. We produced 1.4 million MMBTU of RNG during the second quarter of 2025, flat as compared to 1.4 million during the second quarter of 2024. Our Rumpke facility produced 67,000 MMBTU more in the second quarter of 2025 compared to the second quarter of 2024 as a result of a previously disclosed reduction in feedstock inlet and process equipment failures which occurred in the second quarter of 2024 offsetting this increase was the fourth quarter 2024 sale of our southern facility which produced 22,000 MMVTU in the second quarter of 2024 revenues from the renewable natural gas segment during the second quarter of 2025 or 40.8 million an increase 2.0 million or or 5.1%, compared to $38.8 million during the second quarter of 2024. Average commodity pricing for natural gas for the second quarter of 2025 was 82.0% higher than the prior year period. During the second quarter of 2025, we self-marketed 11.1 million RINs, representing a 1.1 million increase, or 10.5%, compared to 10 million RINs self-marketed during the second quarter of 2024. Average pricing realized when RIN sales during the second quarter of 2025 was $2.42 as compared to $3.12 during the second quarter of 2024, a decrease of approximately 22.4%. This compares to the average D3 RIN index price for the second quarter of 2025 of $2.36, being approximately 26.1% lower than the average D3 RIN index price for the second quarter of 2024 of $3.20. At June 30th, 2025, we had approximately 0.3 million MMBTU available for RIN generation, 3.0 million RINs generated but unseparated, and 0.1 million RINs separated and unsold. At June 30th, 2024, we had approximately 0.4 million MMBTU available for RIN generation and 4.7 million RINs generated and unsold. On June 30, 2024, there were no RINs generated but unseparated. Our operating and maintenance expenses for our RNG facilities during the second quarter of 2025 were $17.0 million, an increase of $3.1 million, or 22%, compared to $13.9 million during the second quarter of 2024. We do not anticipate approximately $1.8 million of nonlinear discrete expenses to recur in the second quarter, in the second half of 2025, as they relate primarily to annual preventative maintenance and gas processing equipment preventative maintenance. The primary drivers of the 2025 second quarter increase of $3.1 million were timing of preventative maintenance, media change-out maintenance, and other well-filled operational enhancement programs at our Apex, McCarty, Rumpke, and Atascasita facilities. We produced approximately 42,000 megawatt hours in renewable electricity during the second quarter of 2025, a decrease of approximately 3,000 megawatt hours, or 6.7%, compared to 45,000 megawatt hours during the second quarter of 2024. Approximately 2,000 of this decrease relates primarily to the planned timing of preventative engine maintenance at our Bowerman facility. Revenues from the renewable electricity facilities during the second quarter of 2025 were $4.3 million, a decrease of 0.2 million, or 4.5%, compared to 4.5 million during the second quarter of 2024. The decrease is primarily driven by the aforementioned decrease in our Bowerman facility production volumes. Our renewable electricity generation operating and maintenance expenses during the second quarter of 2025 were 4.8 million, an increase of 0.1 million, or 2%, compared to 4.7 million during the second quarter of 2025. We do not anticipate approximately $1.4 million of discrete expenses primarily associated with our environment facility to occur – to recur in the second half of 2025 as they relate to nonlinear annual preventative maintenance. The nominal resulting increase in the second quarter of 2025 was primarily driven by an increase in noncapitalizable costs at our Montauk Ag Renewables projects in Turkey, North Carolina. Offsetting the increase, our Tulsa facility operating and maintenance expenses decreased approximately $0.2 million primarily related to well-filled collection enhancements. During the second quarter of 2025, we reported impairments of $0.4 million, an increase of $0.2 million compared to $0.2 million in the second quarter of 2024. The increase primarily relates to specifically identified assets deemed obsolete or non-operable. We did not record any impairments related to our assessment of future cash flows. Operating loss for the second quarter of 2025 was $2.4 million, a decrease of $3.3 million compared to an operating income of $0.9 million for the second quarter of 2024. RNG operating income for the second quarter of 2025 was $9.2 million, a decrease of $2.5 million, or 21.2%, compared to an operating income of $11.7 million for the second quarter of 2024. Renewable electricity generation operating loss for the second quarter of 2025 was $2.3 million, an increase of $0.3 million, or 19.2%, compared to the $2 million operating loss for the second quarter of 2024. Turning to our balance sheet, June 30, 2025, $50 million was outstanding under our term loan, and we had approximately $20 million of outstanding borrowings under our revolving credit facility. As of June 30, 2025, the company capacity available for borrowing under our revolving credit facility was $97.4 million. For the first six months of 2025, we generated $17.3 million of cash from operating activities, an increase of 19.3% compared to $14.5 million for the first six months of 2024. Based on our estimate of the present value of our PICO earn- PICO earn-out obligation, we reported an increase of $0.8 million to the liability at June 30, 2025. This increase was recorded through our R&G segment royalty expense. For the first six months of 2025, our capital expenditures were approximately $45.3 million, of which $27.7 million, $8.4 million, and $7.3 million were related to our ongoing development of Montauk Ag Renewables, our contractually obligated Rumpke R&G relocation, and our second Apex facility, respectively. As of June 30, 2025, we had cash and cash equivalents, net of restricted cash, of approximately $29.1 million. We had accounts and other receivables of approximately $7.5 million. We do not believe we have any collectability issues within our receivables balance. Adjusted EBITDA for the second quarter of 2025 was $5.0 million, a decrease of $2.0 million, or 28.6%, compared to adjusted EBITDA of $7.0 million for the second quarter of 2024. As previously noted, for the second quarter of 2025, we incurred the following discrete or nonlinear expenses. Approximately $1.5 million within general administrative expenses for accelerated stock-based compensation, and approximately $1.8 million and $1.4 million, respectively, within RNG and REG operating expenses relating to the timing of discrete preventative maintenance. We do not expect these discrete and nonlinear expenses to recur in the second half of 2025. EBITDA for the second quarter of 2025 was $4.6 million, a decrease of $2.1 million, or 31.3%, compared to EBITDA of $6.7 million for the second quarter of 2024. Net loss for the second quarter of 2025 was $5.5 million, an increased loss of $4.8 million as compared to $0.7 million for the second quarter of 2024. Our income tax expense increased approximately $1.5 million for the second quarter of 2025 as compared to the second quarter of 2024. The difference in effective tax rates between 2025 second quarter and the 2024 second quarter primarily relate to changes in pre-tax loss for the second quarter of 2025 as compared to the second quarter of 2024 pre-tax profit. Additionally impacting our second quarter 2025 tax provision was the discrete impacts of the affirmation to accelerated stock vesting and the Inflation Reduction Act investment tax credits. I'll now return the call back over to Sean.

Thank you, Kevin. In closing, and though we don't provide guidance as to our internal expectations on the market price of environmental attributes, including the market price of D3 rents, we are reaffirming our full year 2025 outlook provided in May 2025. For 2025, we continue to expect our RNG production volumes to range between 5.8 and 6 million MMVTUs with corresponding RNG revenues to range between $150 million and $170 million. We note that these ranges have not changed relative to our 2025 expectations as we continue to manage through regulatory uncertainty. We continue to expect our 2025 renewable electricity production volumes to range between 178 and 186,000 megawatt hours with corresponding renewable electricity volumes to range revenues to range between $17 million and $18 million, again unchanged from our previous guidance. And with that, we will pause for any questions from our analysts.

Thank you. At this time, we will conduct the question and answer session. As a reminder, to ask a question, you will need to press star 1-1 on your telephone and wait for your name to be announced. To withdraw your question, please press star 1-1 again. Please stand by while we compile the Q&A roster. Our first question comes from a line of Matthew Blair from TPH. Your line is now open.

Matthew Blair Thank you, and good morning. I have a two-parter here. The first is on the D3 RBO. And, Sean, thanks for your comments to start things off. But it looks like this year's D3 RIN generation is on pace, you know, not just to easily exceed the RVO for 2025, but also the proposed numbers for 2026 and 2027. Are you hearing anything that the EPA may reconsider these proposed numbers and move them higher? Is there any hope for a better RVO for the RNG space? And then the second question is you highlighted that RNG OpEx moved up in the second quarter. It sounds like that was mostly one-time preventative maintenance, media changeouts, things like that. It looks like the royalty share also moved up to about 21% in Q2 versus 19% in Q1. Would you expect that royalty share to stay around 21% for the third and fourth quarters, or would that move down as well?

Thank you, Matthew. I will take the first part related to the RVO as we're all aware the RVO is still within a comment period and obviously a data point that they are taking into consideration is that imbalance between the run rate of production and generation of D3 RINs and what the RVO proposed to be set and so So that continues to be evaluated by the EPA with that potential change pending. Kevin, perhaps you can comment on the OPEX.

Thank you, Matthew. And, yeah, we expect to not have the approximate 1.8 within RNG and the 1.4 within our REG segments to recur in the second half of the year. These were planned, expected preventative maintenance items that, you know, again, occurred generally once a year. So that's why we wanted to highlight the fact that we had these preventative maintenance impacts incurring now primarily in the second half of this year. And we don't expect to incur those levels of expense in the second half of this year. Specifically in regards to that royalty calculation, that was a one-time – we address our PICO earnout quarterly, as we're reporting, based upon our expectations of future results of our PICO location. However, the increase this quarter was related to a discrete impact of us receiving our final tranche increase of feedstock manure associated with the expansion of feedstock that led to our building and commissioning the CSTRs, increasing our digestion capacity. With us receiving that final increase and making a final payment to the dairy for that manure increase, we reduced our discount rate, i.e. we reduced the risk of us not receiving that. So it was a sort of a formulaic calculation associated with a discount rate in our expectations as opposed to anything necessarily changing with the results or operations of PICO. So that one-timer influenced our second quarter RNG royalty expense. And on a run rate standpoint, we would expect that production revenue notwithstanding on our tiered royalties to normalize back at that approximate

20% level. Thank you. Our next question comes to a line of Tim Moore from Clear Street. Your line

is now open thanks uh just a couple quick questions um you know your operating and maintenance expense you know rose significantly since last october revenue you know you discussed which was nice to quantify the uh the discrete 1.8 1.4 million dollar expenses that won't really be incurred at that level in the second half um are there any other expenses you can think of as you look at your projects whether it's you know swine um anything else you're doing that might you know drag down some of the profitability in the second half of this year early next year just kind of curious about that as you know as we kind of look at the second half of this year and into next year for the question

Tim generally we see we do some planned outages at our facilities early in the year specifically some some outages at our McCarty location with a planned outage that, you know, drove an increase in, you know, power controls and equipment controls and things like that. But generally for the second half of this year, we don't expect those large one-timers to continue in the second half. If you look back at our first half of this year compared to first half of last year, you'll see that generally for our existing locations, we generally incur higher expenses in the first half versus lower expenses in the second half. So presuming that our timing of outages continue, I would expect that run rate, if you will, in the future to continue. However, occasionally our outages are impacted. If we receive word from our outbound utilities that there's going to be some outages impacting us, we might change the timing of our planned outages, or if we are looking at other preventative maintenance that indicates that we need to do something else with the equipment at either an RNG or a power site, we might move that around. But a long-winded way, Tim, of saying that as of right now, as we're entering into our detailed bottoms-up budgeting for 2026, I don't necessarily anticipate any change from our historical run rate of 2025 or our second half of 2025 expectations being lower than the first half of this year, nor a robust change in our timing or overall level of expenses into 2026.

So just a summary of things that could happen, not things that we have any anticipation of. One other comment that's probably not material but at least worth mentioning is if you're looking at operating expenses on a percentage basis of production or revenue. There is a baseline of non-capitalizable costs associated with our build-out at Turkey. And so where you will see those costs continue, they're not currently paired with production or revenue and have a disproportionate impact. Because you're onboarding staff and personnel and you're doing certain things to run the facility equipment that we've already commissioned down there, utility charges and whatnot. Those things will continue to ramp up, but what will be significant is when we get into the early part of 26, it will be matched with your revenue and your production coming from that

new facility. Our next question comes from a line of Betty Vang from Scotiabank. Your line is now

open. Thank you. Good morning. Thanks for taking my question. I wanted to ask about the JV that you announced. Could you please elaborate on perhaps what's the nature of that JV and the contribution by the partners? And maybe should we understand it as distribution of RNG? How should we think about that? Thank you.

Thanks, Betty. I think the best way to explain or give a little more detail behind that JV is the comments that we made regarding the positioning that the EPA has been taking. As they've been adjusting the RVO for the proposed RVO volumes for this year and the outward years, they've been explaining. They've been very verbal about that they have this concern that the growth in the usage of RNG into transportation is not growing at the pace of the potential production of RNG. Knowing that that's your critical path, no pun intended, for the generation of D3 RINs, they have slowed the growth percentages that they've applied to those RBOs. And so rather than fixing volumes at lower pricing or looking for alternative usage of the feedstock biomethane for something other than the production of RNG and the underlying RIN, we have focused on trying to form pathway opportunities that are new, unique, proprietary that qualify for these transportation usages. The ability to do that that has been acknowledged by the EPA is an opportunity to offset those perceived growth slowing of the usage of the RNG into transportation and allow for that to be more commensurate to the growth of the production of RNG should go well to offset the approach that the EPA is currently taking to try and keep those growth volumes slower, but at a minimum opens up the opportunity short-term for a large amount of volumes that the industry is claiming that do not have a home for usage in the RNG transportation space.

And then also, Betty, to address your contribution question, we've contributed approximately $2.3 million and subject to various triggers and requirements within the underlying agreement, excuse me, we can contribute potentially up to an additional $2.1 million. And so our contribution in the form of capital could approximate up to 4.5, as well as the technical understanding and know-how associated with, you know, with transacting rent. The other partners are bringing in what we would consider the IP, the relationships, and these new and unique pathways to dispense third-party volumes and separate K3 from K2 rents.

Thank you. Our next question comes from the line of Tim Moore from Clear Street. Go ahead.

Thanks for allowing the follow-up. So, Sean, for, you know, the North Carolina Axe Wine project, when might you get a better understanding maybe of the expansion potential there? You know, it seems like it would just be highly incremental margin as you build that out more and the demand there ramps up. And just, you know, just curious, you know, investors are always asking me, you know, besides that project, you know, what else you're the most excited and enthusiastic about, you know, as you look out the next 12 to 18 months for the company?

That's a great question, Tim. Obviously, before we seek to do rapid expansion of that opportunity in North Carolina, it's critical to the company that we commissioned the first phase of this, and it's done so with predictable long-term fixed-price off-take arrangements. The opportunity to do that and to take advantage of the enhanced legislation has really caused a very refined focus and optimization as to what it is that we intend to do in North Carolina, predominantly address the growing need for the farming community to remove this waste from their core business and to do so in a way that removes the most amount of non-caloric liquid and to have a very optimized, dry, pelletized product that is specifically now for the generation of just electricity and take full advantage of that legislation change that was passed at the end of the year. The expandability, you are correct. There is an economy of scale there that can be reached quite enthusiastically with the optimization of the farm side collection, the optimization of the pelletization, and the continued suite of combustible fuel supply that comes out of our patented reactor process that allows for you to continue electric generation, to segue into gas generation, and the continuation of a valuable biochar product that is used as fertilizer and soil amendments. There's a lot of directional flexibility that happens on a project that has the way that we are building this. The opportunity for both the electric and the gas interconnections, The opportunity for pelletized waste, the opportunity that we have on this campus for rail transportation that could allow for us to reach beyond not only from a feedstock inlet, but also a production outlet in the form of the pelletized waste that we're creating. There's a variety of different directions that that project can be taken for future expansion. And notwithstanding the cost reductions that you can get from further horizontal or vertical integrations, particularly in the manufacturing and the securing of the raw materials that go into the production of even our reactors. The space that we have taken in Turkey, North Carolina, is sufficient for a lot of these additional expansion opportunities or optimization opportunities. And we continue to work with local municipalities and government agencies to pursue any types of tax credit or incentive opportunities to expand what we believe is a very exciting project that we've taken on. I'm excited about all projects that we have in the company. It is a very fortunate position for a company that's been in this business as long as it has to have everything from its traditional landfill R&G conversion opportunities or additional electric gen opportunities to be in second and third phases of its shift to an increasing level of commodity-based revenue streams. The opportunity to take on the large-scale production of biogenic carbon dioxide in a commodity base that has the upside of potential tax credit revenue but doesn't have the attribute risk associated with that commodity. And the ability to look at projects that may be limited in terms of size and scope or proximity to a pipeline for RNG injection and look at the opportunity to develop those with a very efficient technology in the form of methanol production are the two areas that I think are very nice balances to our continuation to materially and enthusiastically be in the generation of D3. rents. Those are the items that keep us the most excited. All the while, we continue to evaluate and explore existing and future opportunities in sort of the legacy business that we have, landfill gas to R&G and the subsequent generation of rents.

And, Tim, we could also point you to the press release yesterday between Montauk Renewables and for the joint development, joint venture between our companies that was mentioned in today's call for the 50,000 gallons per year of green methanol looking to be produced.

Thank you, everyone. This concludes the question and answer session. I would now like to turn it back to Sean for closing remarks.

Thank you. And thank you for taking the time to join us on the conference call today. We look forward to speaking with you when we present our third quarter 2025 results.

Thank you for your participation in today's conference call. This does conclude the program. You may now disconnect.