Good day, everyone, and thank you for participating in today's conference call. I would like to turn the call over to John Ciroli as he provides some important cautions regarding forward-looking statements and non-GAAP financial measures contained in the earnings material or made on this call. John, please go ahead. John Cir

Thank you, and good day, everyone. Welcome to Montauk Renewables earnings conference call to review the second quarter 2025 financial and operating results and developments. I'm John Ciroli, Chief Legal Officer and Secretary at Manta. Joining me today are Sean McClain, Montauk's President and Chief Executive Officer, to discuss business development; and Kevin Van Asdalan, 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 Renewables' SEC filings. Our remarks today may also include non-GAAP financial measures. We present EBITDA and adjusted EBITDA metrics because we believe 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 and Form 10-Q issued and filed on August 6, 2025. These are available on our website at ir.montaukrenewables.com. [Operator Instructions] And 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 requirements and other changes in their proposed rule. The final 2024 cellulosic biofuel volume requirement was reduced from $1.090 billion to $1.010 billion 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 and 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 billion to $1.190 billion 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 RIN currently trades. The proposed cellulosic biofuel volume requirements for 2026 and 2027 are $1.300 billion and $1.360 billion D3 RINs, 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 RIN 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, GreenWave 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 in various stages of negotiations with obligated utilities to provide RECs 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 set 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 facilities production capacity, driven by the landfill host waste intake projections. The second facility provides us with an additional 2,100 MMBtu 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 e-methanol 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 site surveys related to the location of the CO2 processing equipment, have evaluated equipment suppliers and started engineering design. We continue 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 Emvolon to transform methane emissions from waste stream biogas into high-value carbon-negative fuel. Leveraging Emvolon'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 Atascocita facility in Houston, Texas, exceeded its anticipated results. Following a successful field demonstration project together with Emvolon, 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 and 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 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 rule making 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 30, 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 BRRR became effective. We had approximately 108,000 RINs in inventory from 2025 RNG production as of June 30, 2025. These RINs were transferred in July under a commitment entered into in June 2025 at a price of $2.42. The average D3 RIN 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 BRRR 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 noncash stock-based compensation costs related to a onetime 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 [ 3 and 1/4 ] years. Before turning to our operating segment metrics, I want to address the recent taxable 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 and Jobs Act 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 2021 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% of the project capital will qualify for investment tax credits and depending upon a wide variety of factors for projects started within safe harbor guidelines, the tax benefits could range up to 30%. Related to our second Apex RNG facility placed into 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 31, 2025. For estimation purposes, we believe that based on approximately 50% of the project capital qualified 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% of the capital will qualify at a 6% to 12% 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 the 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 MMBtu in the second quarter of 2024. Revenues from the Renewable Natural Gas segment during the second quarter of 2025 were $40.8 million, an increase of $2.0 million 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 RIN self marketed during the second quarter of 2024. Average pricing realized on 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 30, 2025, we had approximately 0.3 million MMBtu available for regeneration, 3.0 million RINs generated but unseparated and 0.1 million RINs separated and unsold. At June 30, 2024, we had approximately 0.4 million MMBtu available for RIN generation and 4.7 million RINs generated and unsold. At 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 occur -- to recur in the second quarter -- in the second half of 2025 as they relate primarily to annual preventative maintenance and gas processing equipment preventive 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 wellfield operational enhancement programs at our Apex, McCarty, Rumpke and Atascocita 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 was 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 Bowerman 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 wellfield collection enhancements. During the second quarter of 2025, we recorded 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 nonoperable. We did not report 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. At 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's capacity available for borrowing under our revolving credit facility was $97.4 million. For the first 6 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 6 months of 2024. Based on our estimate of the present value of our 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 RNG segment royalty expense. For the first 6 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, a contractually obligated Rumpke RNG 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 collectibility 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 briefly noted, for the second quarter of 2025, we incurred the following discrete nonlinear expenses, approximately $1.5 million within general and 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 non-inlayer 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 of 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 pretax loss for the second quarter of 2025 as compared to the second quarter of 2024 pretax profit. Additionally impacting our second quarter 2025 tax provision was the discrete impact 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 RINs, 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 million and 6 million MMBtus 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 178,000 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.

[Operator Instructions] Our first question comes from the line of Matthew Blair from TPH.

And I have 2-parter here. The first is on the D3 RVO. And Sean, thanks for your comments to start thins off. But it looks like this year's D3 RIN generation is on pace not just to easily exceed the RVO for 2025, but also the proposed numbers for 2026 and 2027. Are you sharing anything that the EPA may reconsider these composed numbers and move them higher? Like 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 onetime preventative maintenance, media change-outs, 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?

I will take the first part related to the RVO. As we're all aware, the RVO is still within a common 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 that continues to be evaluated by the EPA with that potential change pending. Kevin, perhaps you can comment on the OpEx.

Yes. And yes, we expect to not have the approximate $1.8 million within RNG and the $1.4 million within our REG segments to recur in the second half of the year. These were planned expected preventative maintenance items that, again, occur 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 onetime -- 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 [ Manor ] associated with the expansion of feedstock that led to our building and commissioning the CFTR increasing our digestion capacity. With us receiving that final increase and making a final payment to the dairy for that [ Manor ] 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 at Pico. So that onetimer 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.

Our next question comes from the line of Tim Moore from Clear Street.

Just a couple of quick questions. Your operating and maintenance expense rose significantly since last October, [ it's in the ] revenues. You discussed -- which was nice to quantify the discrete $1.8 million, $1.4 million other expenses that won't really be incurred at that level in the second half. Are there any other expenses you can think of as you look at your projects, whether it's swine, anything else you're doing that might drag down some of the profitability in the second half of this year or early next year? Just kind of curious about that as we kind of look at the second half of this year and into next year.

Thanks for the question, Tim. Generally, we see -- we do some planned outages at our facilities early in the year. Specifically some outages at our McCarty location with a planned outage that drove an increase in power controls and equipment controls and things like that. But generally, for the second half of this year, we don't expect those large onetimers 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, 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 noncapitalizable 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 as your onboarding staff and personnel and you're doing certain things to run the facility equipment that we've already commissioned down their 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 the line of Betty Zhang from Scotiabank.

I wanted to ask about the JV that you announced. Could you please elaborate on perhaps what's the nature of that JV and a big contribution by the partners? And maybe should we understand it as distribution of RNG? How should we think about that?

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 in the outward years, they've been explaining. They've been very verbal about that they have this concern that the growth and 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 the 3 RINs, they have slowed the growth percentages that they've applied to those RVOs. 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, we can contribute potentially up to an additional $2.1 million. So our contribution in the form of capital could approximately up to $4.5 million as well as the technical understanding and know-how associated with transacting RINs. 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 RINs.

Our next question comes from the line of Tim Moore from Clear Street.

So Sean, for the North Carolina Ag swine project, when might you get a better understanding maybe of the expansion potential there? It seems like it would just be highly incremental margin as you build that out more and the demand there ramps up. And just curious, investors are always asking me, beside that project, what else you're the most excited and enthusiastic about 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 offtake 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 noncaloric 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 manufacturer 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 RNG 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 2 areas that I think are very nice balances to our continuation to materially and enthusiastically be in the generation of D3 RINs. So those are the items that keep us the most excited all the while we continue to evaluate for existing and future opportunities in sort of the legacy business that we have landfill gas to RNG and the subsequent generation of RINs.

And Tim, we could also point you to the press release yesterday between Montauk Renewables and Emvolon 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.