Good day, and thank you for standing by. Welcome to the OPAL Fuels First Quarter 2025 Earnings Results Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there'll be a question-and-answer session. To ask a question during the session, you'll need to press star one one on your telephone. You will then hear an automated message advising your hand is raised. To ask for your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to turn the conference over to your speaker for today, Todd Firestone. Please go ahead. Thank you, and good morning, everyone. Welcome to the OPAL Fuels First Quarter 2025 Earnings Conference Call. With me today are Co-CEOs Adam Comora, Jonathan Maurer, and Kazi Hasan, Opal's Chief Financial Officer. OPAL Fuels released financial and operating results for the first quarter of 2025 yesterday afternoon, and those results are available on the investor relations section of our website at opalfuels.com. Presentation and access to the webcast for this call are also available on our website. After completion of today's call, a replay will be available for 90 days. Before we begin, I'd like to remind you that our remarks, including answers to your questions, contain forward-looking statements which involve risks, uncertainties, and assumptions. Forward-looking statements are not a guarantee of performance, and actual results could differ materially from what is contained in such statements. Several factors that could cause or contribute to such differences are described on slides two and three of our presentation. These forward-looking statements reflect our views as of the date of this call, and OPAL Fuels does not undertake any obligation to update forward-looking statements to reflect events or circumstances after the date of this call. Additionally, this call will contain discussion of certain non-GAAP measures. A definition of non-GAAP measures used in the reconciliation of these measures to the nearest GAAP measure is included in the appendix of the release and presentation. Adam will begin today's call by providing an overview of the quarter's results and recent highlights and an update on our strategic and operational priorities. Jon will then give a commercial and business development update, after which Kazi will review financial results. We'll then open the call for questions. I will now turn the call over to Adam Comora, Co-CEO of Opal Fuels. Thanks, Todd. Good morning, everyone, and thank you for participating in OPAL Fuels First Quarter 2025 Earnings Call. First quarter results were in line with expectations. Performance across our business segments was solid, and we continue to execute on our strategic and operational objectives. First quarter adjusted EBITDA was $20.1 million, over 30% higher compared to the same period last year. Our first quarter 2025 fuel station services segment EBITDA was approximately $12.5 million, 80% higher versus the first quarter of 2024. RNG fuel production for the quarter was 1.1 million MMBTU, up nearly 40% versus the same period last year, and in line with our expectations. Our fuel station services segment continues to exhibit strong growth. As we often discuss, the strategic value of our vertical integration, which maximizes the value of RNG that we produce and makes us an attractive partner for new RNG business development opportunities, this segment also provides steady, predictable, and growing cash flow that improves economic returns to the overall business and dampens commodity price volatility. We are maintaining our full-year guidance set out in March and expect to see sequential quarterly RNG production growth throughout the year as our newer projects continue to ramp. We also anticipate continuing growth at our existing landfill RNG facilities. While we are pleased with our execution, we are also cognizant of the uncertain macro and regulatory environments. Although we don't expect our business to be materially impacted by tariffs, recent trade policy uncertainties are causing delays in investment decisions in our customers and partners, including some of our logistic and trucking fleet customers. These delays are not material enough for us to change our guidance regarding fuel station services EBITDA growth for the year, but we are not yet seeing the acceleration of CNG RNG adoption for heavy-duty trucking. That said, we are very encouraged by numerous factors supporting long-term adoption. Our view is driven by product availability of the Cummins 15-liter engine, with Freightliner now moving into production and delivery. In addition, a new regulatory outlook has recognized the challenges of zero-emission vehicles for the heavy-duty market. This significantly expands the potential for adoption of RNG CNG-powered heavy-duty trucking. While this regulatory shift has positive implications for the continued growth of fuel station services, we are still waiting for regulatory clarity for the RNG fuel segment. We are continuing to monitor 45Z implementation, final EPA rulings on the proposed partial waiver introduced in November of last year, and the upcoming Set Rule two, which will include volumes and other market balancing mechanisms. While we are waiting for the regulatory backdrop to clarify, there is still strong bipartisan support for American biofuels and investment in RNG. With that, I'll turn it over to Jon. Jon. Thank you, Adam, and good morning, everyone. As Adam mentioned, our first quarter production results were 38% higher compared to the first quarter of 2024, driven primarily by increasing production at the facilities commissioned in the fourth quarter of 2024. As we mentioned in March on our last earnings call, production from these facilities is growing, and we continue to see positive performance across our other operating facilities. We maintain our 2025 RNG production guidance of 5.0 million MMBTU-5.4 million MMBTU, which at the midpoint is a 37% increase versus 2024. In our in-construction portfolio, we have four landfill RNG projects in construction at Atlantic, Burlington, Cottonwood, and Kirby, which remain on schedule and represent in aggregate 2.1 million MMBTU of annual design capacity. We expect Atlantic to commence commercial operations in the third quarter of this year and the next three during 2026. Our development pipeline has numerous near-term opportunities with secured gas rights, and we are maintaining our guidance to place 2 million MMBTU into construction in 2025. In fuel station services, we have 45 stations in construction, of which 19 are OPAL-owned. We are maintaining our guidance to grow fuel station services 2025 adjusted EBITDA 30%-50% versus 2024. 2025 is off to a good start, and despite the mentioned near-term uncertainties, longer-term market fundamentals are supportive of our business plan and growth potential. Successful, disciplined execution will result in increasing shareholder value. I'll now turn the call over to Kazi to discuss the quarter's financial performance. Kazi? Thank you, Jon, and good morning to everyone joining today's call. Last night, we issued our earnings press release outlining our results for the first quarter ended March 31, 2025. We expect to file our Form 10Q on Monday. Revenue and adjusted EBITDA for the quarter were $85.4 million and $20.1 million, respectively, compared to $64.9 million and $15.2 million in the same period last year. Net income was $1.3 million, up from $0.7 million in Q1 2024. This year-over-year quarterly growth reflects the continued ramp-up of RNG production at facilities commissioned in 2024, along with the growth in our fuel station services segment. Included in these results is Opal's share of adjusted EBITDA from Equity Method Investments, which was $3.4 million for the quarter versus $6.5 million in Q1 2024. The year-over-year decrease is primarily driven by the timing of last year's wind sales and startup-related expenses at new joint venture projects. Capital expenditures for the quarter totaled $17 million, including $5.4 million related to our Equity Method Investments. As Adam mentioned, we maintain our full-year 2025 guidance provided in March. We continue to expect adjusted EBITDA between $90 million and $110 million, supported by RNG production of 5.0-5.4 million MMBTUs. Our guidance assumes D3 RIN pricing of $2.60 per gallon for the entire 2025. As of March 31, our total liquidity was $240 million. This includes $40 million plus of cash, cash equivalents, and short-term investments, more than $178 million of undrawn availability under our term credit facility, and a little over $21 million of remaining capacity under our revolver. In March, we also monetized approximately $8 million in investment tax credit net proceeds and expect roughly $50 million in total ITC sales in 2025, which bolsters our operating cash flow. We believe our current liquidity position, combined with the operating cash flows, will be sufficient to fund our existing capital plan and near-term growth initiatives. With that, I'll now turn the call back over to Jon for closing remarks. In closing, we are pleased with our first quarter results. We remain well-positioned for continued disciplined execution of our strategic growth objectives and the expansion of OPAL's vertically integrated platform. I'll turn the call over now to the operator for Q&A. Thank you all for your interest in OPAL Fuels. Thank you. As a reminder, if you would like to ask a question, please press star one one on your telephone. You hear the automated message that your hand is raised. We also ask that you please wait for your name and company to be announced before proceeding with your question. As well, one question and one follow-up. One moment for the 1st question. The 1st question will be coming from the line of Derrick Whitfield of Texas Capital. Your line is open. Good morning, all, and great update. Thanks, Derek. Good morning. For my 1st question, I wanted to lean in on your production trajectory for the year. While flattest Q1 versus Q4, your guidance implies a material increase in production over the course of the year as recent projects ramp and gas collection improves. Could you perhaps speak to the cadence of production expectations for the year and then the improvement you're expecting in inlet design capacity utilization over the course of the year? Hi, Derek. Jon, I'll take this one. Production for the quarter was within our band of expectations, and production was somewhat affected by a couple of factors, including an unusually cold winter affecting our landfill gas collection. In addition, we had some availability issues at our virtual pipeline projects, which are not generally as reliable as direct connect projects. However, as you mentioned, we are expecting good sequential growth through the next several quarters consistent with our guidance, and this will come from improvements at existing projects, including landfill gas collection expansions at our open and growing landfills that are occurring typically this time of year and through the summer. In addition, our Polk project is going to be transitioning to a direct connect interconnection this month, which should serve to increase that reliability. have also put in place a number of key additions over the last five months or so in the operating team there, which should result in increasing efficiencies and availability across those projects. As we see the Atlantic project on track for commercial operations in the third quarter, we should expect to see results from that in the fourth quarter. As said, we remain confident in our output, and we will see that sequential ramp over the course of the year. Terrific. Maybe leaning in further just on your in-construction RNG projects, it appears, as you noted, that these are generally progressing kind of in line with your expectations. Are you guys experiencing any leading-edge inflation associated with tariffs? You want to, Kazi? You want to take that? Sure. Let me take that. Hi, Derek. On the tariff-related, we are not seeing any cost increase in our construction projects or even in our operating areas yet. I do not expect there is going to be a lot because all the in-construction projects have already—all the equipment has been ordered, like fixed-price contracts have been executed. We do not expect a lot of implications on our current operations as well as the capital. It could be in future projects, and we will make those judgments as part of the FID when we make the final decision on the investments. Maybe just any color around how material that could be on future projects, just from what you guys have been able to size up to date? Just as a guide, some of the future projects, you already made qualifying investments for the ITC purposes. Part of those costs has already been secured in seeing a whole lot of improvement. You remember all of our contents, we try to make it domestic qualified. There could be implications on steel or aluminum, all those areas, but we do not see a major implication. It remains to be seen. We do not know how this whole overall macro situation is going to clarify itself over the next two to six months. To date, we do not see a major implication. That's great. I'll turn it back to the operator. Thank you. The next question will be coming from the line of Matthew Blair of TPH. Your line is open. Great. Thank you. Good morning. I wanted to talk about the wind pricing you achieved in the first quarter. It was down quarter to quarter, but still extremely strong relative to the benchmark index. I think we showed you capturing about 112% of the benchmark index. Could you talk about the drivers here, and is this something that you might be able to replicate in Q2 and going forward? Yeah. Thanks, Matt, Adam Comora here. We did have an average realized wind price of about $271 in the first quarter. We typically do not like to speculate on where wind prices are going or where public policy is going to go. We typically have a philosophy that we are going to sell as we go. We also do not like to talk too much about our trading philosophy and policy. I would say that our second quarter wind price will likely be lower than what it was in the first quarter. Our position for the year is basically about 50% that we have sold and sort of supported by our outlook for our guidance. Sounds good. Then the growth that you're expecting this year in SSS, 30%-50% EBITDA growth coming off a pretty strong number in 2024. Could you talk about—and is it possible for you to split how much of that growth is simply coming from higher volumes? It sounds like you're building 19 of your own stations. Then how much of that growth is coming from expectations of stronger margins due to an increasingly tight dispensing market? Yeah. This is Adam again. There are obviously a few subsegments within fuel station services. We are seeing good, strong performance across all of those. Some of that comes from OPAL Fuels stations that we own and then charge that tolling or compression fee. We had a number of those facilities come online in 2024, and a number coming online in 2025. You annualize the ones that came on throughout the year last year, and the new ones coming on this year. Our construction business continues to perform well in terms of anticipated margins. Our service business there continues to grow as well as we have sort of full-service contracts. Those could be on stations that we build and then service after the fact. There is a component to higher utilization and throughput of our dispensing network as RNG volumes continue to flow through there. It is really all four of those pieces that continue to drive growth in fuel station services. Great. Thanks for your comments. Thank you. One moment for the next question. The next question will come from the line of Martin Malloy of Johnson Rice & Company. Your line is open. Good morning. Thank you for taking my questions. 1st question, just bigger picture. Could you maybe talk about how you're thinking about returning capital to shareholders, potentially dividend policy as you achieve the growth at which time you'll start to generate some meaningful discretionary free cash flow? Yeah, Matt, this is Adam Comora here. I appreciate that question because certainly our largest shareholder, and all of our shareholders are interested in maximizing shareholder value and returning value in any number of ways. This really goes to the flexibility that we have in terms of how we deploy capital and what do we do with the free cash flow generation that's going to be coming to maximize and enhance shareholder value. We're sitting in a position where we have a very strong opportunity set of biogas projects that we can either deploy capital and accelerate growth if they still achieve our required unlevered rates of return. That free cash flow generation can also be used in M&A opportunities to enhance the platform and be accretive to shareholder value. If those things do not materialize and you are no longer achieving rates of return that you want on new capital projects, you have the flexibility to delever and return cash to shareholders through those mechanisms that you were talking about. I know we are trying to achieve better float and liquidity, and we have taken some actions to be doing that with our shareholder base. Share buybacks in the future could always be something that you look at. Right now, we like the opportunity set that we have in front of us to continue to deploy capital and grow our company in these new types of projects. By the way, it could either come in fuel station services where we think there could be a real robust opportunity coming for CNG and RNG in the heavy-duty trucking market, or some real attractive large RNG projects to deploy capital there. We are also cognizant of other ways to create shareholder value from the free cash flow. Thank you for that answer. For my 2nd question, I wanted to ask about potential on the electric power side with respect to your facilities. Maybe if you could talk about what you're seeing there from customer interest or potential projects. Yeah. This is Adam again because the renewable power segment, we do not really talk a lot about. I think it is a really interesting use for smaller biogas or biogenic methane abatement, quite frankly. I think people understand the benefits of renewable power from biogas where it is baseload power, enhances grid stability. It is typically in rural areas or municipality-owned. There are a number of different ways to accelerate or incentivize development in that area. We think that is going to be coming. We have talked historically about an E-RIN policy as being something that could be really effective to drive investment in that space and create incremental value for OPAL Fuels. If it is not the E-RIN policy, we think that there could be other interesting offtake markets for that. I know a lot of data centers were looking for low carbon intensity baseload renewable electricity. We will see if those types of offtake markets develop and provide that good economic return and that sort of thing. We do not have anything to report on that front just yet today. I think also, if you look at our financial statements, you will see we are not making a lot of money on renewable electricity today. This is also something we try and educate the folks in D.C. about, that there is not one size fits all. We always think there is this good, better, best policy with what to do with biogenic methane. We think the worst answer is to flare it locally. We think a good answer is to turn it into renewable electricity for the reasons that we said. If you have a high enough—if you have a large enough emission source, your best answer is to turn it into RNG where you're capturing the full energy there because those landfill gas electric projects aren't the most efficient. They do take higher heat rates to create your electricity. We think that resonates with folks. We just haven't seen yet where that shakes out in terms of how to best structure either policy around it or seeing yet that commercial offtake. We do think it's going to be coming. I'll just add that, as always, our electric project portfolio has represented the raw material for converting these long-term gas rights into RNG projects. We expect to see that continuing over the course of this year and next. Great. Thank you. I'll turn it back. Thank you. One moment for the next question. The next question will come in from the line of Adam Bubes of Goldman Sachs. Your line is open. Hi. Good morning. I was wondering if you could just update us on your latest thoughts around potential timelines and outcomes with the next iteration of biogas policy. Adam, this is Adam here. There's a lot going on. When you talk about biogas policy, obviously, we have a lot of things happening within the EPA with the renewable fuel standard. There's a lot of tax policy coming as well. Maybe I'll start on the tax policy 1st, and then we can move into the RFS. On the tax policy, it seems like from the news that I've been reading, we could be seeing some new tax bills coming out any day next week. It sounds like there could be some energy tax policy included in that. If you recall, when we gave guidance for the year, we had a minimum to very small amounts of 45Z included in our guidance. It feels like I want to just talk from a super high level about what it is that we do again and why we think that there is Republican and bipartisan support for the capture of this biogenic methane from organic waste, which, by the way, will continue. We are going to continue to have biogenic methane coming from that organic waste that we create and the animals that we use for our food supply create. It is broadly supported that we should be doing something about that biogenic methane. As it pertains to the tax policy, the one that we're waiting for clarity on, that 45Z, we think we'll be seeing that pretty quickly. It is also pretty interesting too because when we talk about our vertical integration, it also gives us diversity to public policy outcomes as well. Because not only in the tax policy are people talking about 45Z, they're also talking about this RNG Incentive Act, which really would accrue to the downstream fuel station services, whether it's an RNG dispensing tax credit or something that comes back on the fuel usage side. We think that we'll start to get a little bit of clarity around that probably in the coming weeks. We'll see where it shakes out on how the great model is going to work and whether or not it's at the novel tip for dispensing or whether it's on the production side for 45Z or maybe some combination of both. It does feel like there is broad-based bipartisan support for some of that stuff to be included on the tax policy and on the RFS. I'm seeing reports, and I'm sure you guys are seeing reports as well, that the EPA is really trying to keep the timelines on when they put out rules and establish their rulemaking cadence and timeline. We read the same things that everybody else reads where we could see that coming in the coming weeks. As far as the RFS goes, there has been a considerable amount of focus and attention on liquid biofuels. I can understand that. There was a lot of investments made in converting refiners to be able to create renewable diesel. I think previous set rules weren't as supportive for a lot of the investments that were made in that area. You saw that sort of played through in various RIN pricing for various categories. I think there's been a lot of focus on that side of it. There has not been as much attention paid to the cellulosic category as much as we would like to see. The interesting thing there is we actually want the same things as a lot of the liquid advanced biofuels in terms of strong volumes across advanced biofuels. If you have a holistic view on how you are managing the RFS, we think the cellulosic waiver credit can make a lot of sense so that the obligated parties can achieve their compliance. If you have sort of a functioning, working RIN market across the spectrum of those advanced biofuels, you can have that price cap that can really work and support new RNG investment. If you do the math on what it can look like in 2026 and 2027 or however long they do a set rule for, it is really supportive of new investment in RNG and that sort of thing. It is not to say it is always a straight line. We do not know exactly how the rules are going to be. We do feel like what we do does have that broad bipartisan support. We do not know where all these things necessarily shake out. What I can tell you is that it does feel like investment in these sort of RNG products, projects, and the productive use of that biogenic methane is broadly supported, whether it be renewable natural gas in heavy industries like heavy-duty trucking or potentially marine fuel and capturing those smaller emission sources for renewable electricity. We will see where potentially there is positive tax policy or potential positive outcomes out of the RFS. I do believe that we will start getting that regulatory clarity over the next, I do not know, month or two. We will see how long it takes to finalize any of those rules. I would say on the 45Z, that starts January 1, 2025. We obviously have not created any of those tax credits or sold any. That is something that would be active for the entire year. Long answer because there are many layers to that onion. Absolutely. I appreciate all the thoughts there. My last question, it looks like your RNG EBITDA per MMBTU is around $18 in the quarter. Just wondering if you can help us think about puts and takes around the trajectory of EBITDA per MMBTU from here. On one hand, it sounds like these D3 RIN credit prices might step slightly lower sequentially. On the other, I would imagine as you ramp up projects, OpEx per MMBTU maybe moves lower as you spread that OpEx over more production. Just how are you thinking about the trajectory of EBITDA per MMBTU from here? To caveat here, let me answer that question. I think it's simpler than what it may sound. If you think about Jon has mentioned the secular growth in our RNG production throughout the year from the existing facilities plus the ramp-up of projects we've put in construction end of last year. That production would be what the RIN price is going to look like. We already mentioned that we have done pretty well on the RIN price last quarter. It will be less for the second quarter and third quarter and fourth quarter, depending on what the RIN prices are. We are assuming for the rest of the year it's going to show up at $2.60. It's simpler, sequentially growing, and moderated by how the RIN price is shaping up. Great. Thanks so much. Thank you. One moment for the next question. The next question will be coming from the line of Betty Zhang of Scotiabank. Your line is open. Great. Thanks. Good morning. For my 1st question, I was wondering if you could talk about the renewable power segment. In the first quarter, it looked like revenues were down quite a bit. As a result, results were down quite a bit as well. Just curious what the drivers were there. This is Jon. In the renewable power segment, last year we had the ISCC pathway in that segment, and those contracts terminated. There was a substantial decrease from those contracts being terminated in the fourth quarter. That is principally where you are seeing the differences there. Otherwise, it is a pretty consistent performer. In the future, you might see decreases as projects move from renewable power into construction or operation as RNG projects. Otherwise, it should be fairly consistent. We are seeing good opportunities for contracting the power output of those projects as well as RIN prices in certain—I am sorry, REC prices in certain markets as well. Other than that, Betty, I think that is the principal driver of the change. Yeah. This is Adam here. I just want to follow up on that. I think as people might remember, we were enjoying an international export market through renewable power. That lapsed in November of last year. There will be a couple more quarters of that, which was already baked into our guidance and factored into our business plan for 2025. It opened up a sort of—or it made me think about a little broader conversation on tariffs because we did get that 1st earlier question on tariffs, which do not have a material impact on the projects in construction. As Kazi had mentioned, we do not think they will have too material an impact as we are evaluating some of the new project opportunities in front of us. It made me think again about some of those indirect implications on tariffs. When we talk about RNG and we're talking about U.S. public policy and how the RFS potentially plays out and what's happening in our domestic tax policy here, an indirect effect of tariffs is we don't have an export market currently for the RNG that we produce. We think that that's going to be a really interesting opportunity once all that stuff shakes out and those international markets open up again, whether it be for renewable power or other potential markets for RNG. Once those sorts of things shake out and you get European pathways back, we think that's an interesting opportunity for us. Great. That's helpful. Thanks. In the first quarter, I also wanted to ask about what looked like a pretty substantial income tax benefit around $8 million. Just curious if there was anything to point out there. Yeah. Those are the sale of our ITC Section 48 tax credits. If folks remember, we don't include the cash proceeds from the sale of the Section 48 ITC tax credits. It's not included in our EBITDA guidance, but it is included in net income and cash flow. That's what that $8 million was. That was where Kazi was referring earlier, somewhere anticipated to be about $50 million in 2025. Got it. Thank you. Thank you. As a reminder, if you'd like to ask a question, please press star one one on your telephone. Our next question will be coming from the line of Matthew Blair of TPH. Your line is open. Hi. Thanks for taking the questions. Even a hazy at the moment, RNG margin outlook pending regulatory certainty certainly looks a hell of a lot better these days than E-RIN's prospects. Depending on what we see in coming weeks and months, is there room to accelerate conversion of biofuel power projects to RNG? Yeah. I mean, that's what we're excited about. We have a number of projects that we've got secured biogas rights on and a number of conversion projects. And quite frankly, a number of those are sizable projects. Wherever that public policy shakes out, it really defines what your opportunity set is, right? If there is RIN price volatility, we still have a lot of or a subset of larger projects that we can still underwrite and make a lot of sense. At the same time, we're being disciplined and prudent. The way our business is structured is these projects do require a significant amount of capital. They take ballpark 18-24 months to develop and finish out construction on. You typically spend the money early and upfront. Then you recognize significant free cash flow for a long period of time once the projects are operational. We also balance how quickly we move on our development based on whatever the externalities are, be it public policy, capital markets, what have you. We have really got the ability to either accelerate development and grow faster or be prudent and manage the balance sheet effectively as well to make sure that you do not, as our chairman likes to say, get over your skis. We have got the ability to either lean in and accelerate development or stage it out as the projects come online and you deliver the free cash flow. Great. My 2nd kind of big picture question, obviously, you're hearing from multiple parties that downstream continues to look strong. You obviously have a nice construction program going on there. Uptake on the 15-liter CMI engines seems to be slower than anticipated. Kind of thinking into the end of the decade, Macro Trump administration policies obviously support accelerated domestic liquids production and production from our allies, as well as heavily stair-stepping LNG exports. A really fearful worst-case scenario outlook might envision, what are we going to do if there's $50 a lower crude and $4 a higher systemically Henry Hub gas? Are you hearing any concerns about that? This is Adam again. I would say no. I think natural gas is going to stay cheap to oil for as long as the eye can see, specifically here in North America. I want to remind everybody, when we got into the fuel station service segment, I do not know, 13 years ago or so, we always had the eye that ultimately there was going to be this strategic value of vertically integrating with all of our biogas assets. At the same time, we were really excited about the prospect of compressed natural gas as a transportation fuel. We always thought if you could take natural gas and turn it into an oil substitute, it was a good way to take advantage of an energy arc between those two things. I think that's going to continue for, quite frankly, as long as the eye can see, given what it costs to produce crude versus what it costs to lift that gas here in the U.S. As far as the uptake of the 15-liter engine, we're really encouraged by what we're seeing and people realizing that it is a good answer to even if you're just using CNG, you're going to get 20% emission reductions versus diesel. Quite frankly, it's disinflationary when you look at the cost of the fuel versus oil. Now, when we talk about the "slower uptake" or why aren't we there yet, it's been a confluence of factors of product availability where we didn't have a Freightliner engine, which is, I don't know, 40% or so of the market until really just now at the recent ACT Expo. I think, and you've also got now this macro environment where trade looks like it's a little challenged right now. We have seen really good adoption. Our base business is really around more recession-resistant kind of businesses, refuse, moving food and beverages, and that sort of thing around the country. When we talk about the slower uptake, it's really around those logistics and transportation fleet customers that did not have a product until this 15-liter engine showed up. I would also say when we were getting into it 13 or 14 years ago, everybody was doing it for the economics, right? People were not really as focused on sustainability or emission profiles back then. Back then, you were talking about a $60,000 premium for the 12-liter tractor versus where it is today. I think this period of uncertainty is also sort of healthy. We think we're getting to a place where the economics are going to work on CNG versus RNG. Once we do that, we think we're also opening up a whole new area of growth where RNG today is about, what, 2% of the diesel market. Even if we do a fantastic job capturing all the biogenic methane, RNG could maybe grow seven, eight, nine, 10 times from where it is today. There's an opportunity for CNG once we get maybe the price premium down a little more, which should happen with scale. There are some structural things we also need to address there and make sure there's a residual market for tractors when people want to trade out of them. A lot of those for-hire fleets typically operate in a one to three-year contract environment. Shippers, that was the other thing from ACT Expo. We saw a lot of collaboration with the shippers that are hiring these for-hire fleets that really want to see them transition into it. They are starting to realize, "Hey, maybe we need to do four or five-year contracts so that a five-year payback for those tractors can really help accelerate adoption." We see a lot of positives coming. We see that policy shift away from trying to make that one zero emission work for every industry shifting. People are going to lean in on it. I am not overly concerned about what may be a short-term oil price move that shrinks the economics a little bit. We think long-term, there is going to be a very attractive economic incentive between CNG and diesel. Do you really think that customers are willing to look at four- to five-year paybacks versus, say, as little as one to two? That's a really interesting question because I think if you talk to most C-suites out there, they would say a four- to five-year payback is pretty attractive on capital. I think if they get contracts that support that kind of timeframe and maybe they have better visibility on residual values, I think the answer would be yes. I think a lot of public companies are willing to trade CapEx for OpEx as well. I think the answer is yes. By the way, there are some customers, obviously, that can see shorter paybacks. Right now, what happens in the industry is the RNG producers are making RNG more attractive and shrinking the payback by passing along some of the RIN value to those fleets. Yes and no. Some companies, yes. Provided they have contracts on the other side of it, yes. If a fleet owns their own tractor and keeps it for 10 years, the answer is pretty easy for them, right? We will see how it all plays out. We are still trying to work. Hopefully, more competition will bring down that incremental price for that tractor. I think there are also some coming DEF requirements that maybe cause that diesel tractor to go up in price. That shrinks the premium. We are getting there, though, on the economics of CNG on its own. Not quite there yet, but we are pretty close to getting there. Appreciate the answers. Thank you. Thank you. This does conclude today's Q&A session. There are no more questions in the queue. I would like to turn the call back over to Adam Comora for closing remarks. Please go ahead. All right. We thank everybody for your interest in OPAL Fuels and hope everybody enjoys the rest of the day. Thank you for participating. You may all disconnect.