Good morning, ladies and gentlemen, and welcome to the Vertex Energy First Quarter 2023 Earnings Conference Call. At this time, all lines are in a listen-only mode. Following the presentation, we’ll conduct a question-and-answer session. [Operator Instructions] This call is being recorded on Tuesday, May 9, 2023. I’ll now like to turn the conference over to John Ragozzino, Investor Relations. Please go ahead.

Thank you. Good morning, and welcome to Vertex Energy’s first quarter 2023 results conference call. Leading the call today are Chairman and CEO, Ben Cowart; Chief Financial Officer, Chris Carlson; and Chief Operating Officer, James Rhame. Also attending the call are Chief Strategy Officer, Alvaro Ruiz; and Chief Commercial Officer, Doug Haugh. I want to remind you that management’s commentary and responses to questions on today’s conference call may include forward-looking statements, which, by their nature, are uncertain and outside of the company’s control. Although, these forward-looking statements are based on management’s current expectations and beliefs, actual results may differ materially. For a discussion of some of the risk factors that could cause actual results to differ, please refer to the Risk Factors section of Vertex Energy’s latest annual and quarterly filings with the SEC. Additionally, please note that you can find reconciliations of the historical non-GAAP financial measures discussed during the call in the press release issued today. Today’s call will begin with remarks from Ben Cowart, followed by an operational review from James Rhame and financial review from Chris Carlson. At the conclusion of these prepared remarks, we’ll open the line for questions. With that, I’ll turn the call over to Ben.

Thank you, John, and good morning to those joining us on the call today. This morning we issued a press release detailing our financial and operating results for the first quarter of 2023. We are pleased to report a continuation of safe and reliable operations and strong financial and operating results, which were in line with our prior expectations. Our business continued to perform as expected for the quarter as we have enhanced our focus on our Gulf Coast operations following the previously announced sale of our Heartland UMO assets for $90 million in February of this year. We reported total adjusted EBITDA of $34.9 million for the first quarter. Our conventional fuels business at our Mobile facility continued to perform smoothly generating a gross profit for the quarter of $65.5 million, driven by continued attractive refinery margins, offset in part by the impact of reduced throughput during planned downtime associated with the RD project tie-in. Operationally, we reported throughput volumes of approximately 71,000 barrels per day for the quarter in line with our prior guidance issued in late February. Shifts in our product yield profile related to the conversion of our hydrocracker to the production of renewable diesel drove a reduction in volume of finished products such as gasoline and diesel and increased in VGO cut. Fortunately, strength in the VGO market help mitigate the impact of a changing yield profile overall per barrel profitability at the refinery, driving a capture rate of 51%, which was in line with our prior outlook of 50% to 54%. We continue to advance several important strategic initiatives aimed at streamlining our business and enhancing efficiency. As previously mentioned, the sale of the Heartland UMO assets has brought additional liquidity into the business and allow us to tighten our focus on Gulf Coast operations. Additionally, after a lengthy search for a new Chief Commercial Officer, we announced the hiring of Doug Haugh, who I am thrilled to have on our team. I believe Doug’s extensive background and experience bring a tremendous benefit to the company as we seek to capture additional value through the optimization of feedstock procurement and marketing finished products. On March 31 of this year, Vertex reached an important milestone of on schedule and on budget mechanical completion of our RD project. Following ribbon-cutting ceremony hosted by the Mobile Refinery on April 28, our operations team transitioned from the commissioning phase to startup sequencing of the RD facility. Unfortunately, in the days to follow, we encountered issues with the feed pumping system resulting in a startup delay, which Chief Operating Officer, James Rhame will cover in more detail shortly. While this is an unwanted challenge and not the story we hope to have reported to you this morning, I have faith in our team’s ability to safely resolve the issues with minimum delay, as it relates to the first quarter, I will say I’m very proud of how well this team has executed while keeping safety and reliability at the forefront of our operations. With that, I would now like to hand the call over to James, our Chief Operating Officer, who will provide a detailed update on our operations during the quarter, including a more detailed update on the status of our renewable diesel conversion project at Mobile. James?

Thank you, Ben. Good morning, everyone, and thank you for joining us this morning. I’ll begin with a brief report on our health safety environmental performance. First quarter 2023 was a clean quarter. Across the entire business, we had zero OSHA reportables and zero environmental reportables. Mobile additionally had zero process safety events. This is the first quarter since the Mobile acquisition that we had zero safety and environmental reportables across the fleet. Moving on to operational performance beginning in Louisiana, our Marrero operations saw continued progress in improving plant reliability and performance in the first quarter, achieving a 91% capacity utilization at the refinery. As previously disclosed, we closed on the sale of our Heartland facility in February. Operations continued safely and smoothly during January through the completion of the sale on February 1. We have continued to support the successful transition of this facility to the new owner. Our conventional fuels business the Mobile facility performed well during the quarter once again despite elevated site activity related during the peak of construction on our RD conversion project. First quarter throughput volumes at the Mobile Refinery averaged 71,328 barrels per day or 95% of saved at operation capacity in line with our previous guidance. Direct OpEx per barrel for the quarter was also in line with our prior expectations at $3.84 per barrel. We continued processing our crude dock consisting of West Texas Intermediate, like Louisiana Sweet, and other local light sweet crudes. As expected finished products such as gasoline, diesel, and jet fuel accounted for 62% of our total product yield during the first quarter 2023, representing a 12% reduction in yield from the previous quarter of 74%. This reduction was due to the shutdown and conversion of the hydrocracker to renewable diesel. Prior to the shutdown, the unit accounted for 8,000 to 9,000 barrels of distillates and upgraded chemical feedstocks. Products yields were in line with expectations and we expect to see similar yields in the conventional business on a go forward basis. Our fuels gross margin per barrel during the quarter was $16.17 driving a capture rate of 51% of the benchmark Gulf Coast 2-1-1 crack spread in line with our guidance of 50% to 54%. The strength in our reported fuels gross margin per barrel and the resulting capture rate versus the benchmark is a function of the strength seen in refining margins for intermediate products such as VGO. Strength in VGO margins offset the impact of reduced diesel production as a result of a hydrocracker conversion on a per barrel profitability. On a rent-adjusted basis, gross margin per barrel was $13.66. Turning to our renewable diesel conversion project, as previously announced, we achieved mechanical completion on schedule on March 31. We’re tremendously proud of the team’s achievement in reaching this goal without safety or environmental incident or disruption to the existing operation despite the many challenges of executing a project of this magnitude in an operating facility. In the process of unit startup sequencing, we experienced a failure in the feed pumping system. These pumps are responsible for supplying feedstock to the renewable diesel hydrocracker. Upon failure, our safety systems worked as designed and our team responded appropriately to bring the unit down in a safe and controlled manner, preventing further impacts, including preserving the catalyst and our hydrocracker. This event is isolated to the feed system with no known impacts to the reactor or any other processing equipment and no impacts to the conventional refining capability. Currently, the renewable diesel unit is safely parked and we have a number of internal and external expert resources engaged in root cause analysis, repair, and restart. As Ben mentioned, we are confident in our team’s ability to take these challenges head on delivering a safe and reliable outcome. As it relates to the timeline, we expect repairs to be completed prior to the end of the second half of May, after which we plan to reinstall and resume the startup sequence of the renewable diesel unit. Our team and I are certainly disappointed to have delayed our targeted timeline for startup. That said, I am proud of how well our team executed under tremendous pressure during this unexpected event. We believe this is a temporary setback and we look forward to updating you in the future as things progress. As stated previously, our focus has been and will continue to be the safe and environmentally sound operation in the facility. With that, I’d like to now hand the call over to Chris Carlson, Chief Financial Officer, who will review our financial results for this quarter as well as provide our outlook for the second quarter of this year.

Thank you, James, and welcome to those joining us on the call today. For the three months ended March 31, 2023, Vertex reported net income attributable to common shareholders of $53.8 million or $0.71 per share versus a net loss attributable to common shareholders of $4.9 million or $0.08 per share in the first quarter 2022. We reported adjusted EBITDA of $34.9 million in the first quarter 2023 versus $13 million in the prior year period and $75.2 million in fourth quarter 2022. The sequential decline in adjusted EBITDA reflects a combination of the reduced throughput, lower crack spreads and shifts in the product yield profile as expected. The first quarter financial results include an after tax gain on sale of assets in the amount of $48.9 million, reflecting the recent sale of the Heartland facility. Total capital expenditures for the first quarter 2023 were $73.9 million roughly in line with our revised CapEx guidance issued on April 14. The increase in capital investment for the first quarter reflects an acceleration of Phase I spending geared towards strengthening the site’s position ahead of the plans Phase II of the project. As previously outlined, Phase II of our renewable diesel conversion project includes the installation of additional hydrogen capacity and drives a planned capacity expansion from the initial 8,000 barrels per day expecting in Phase I to 14,000 barrels per day. As of March 31, 2023, the company had total cash and equivalents including restricted cash of $95.1 million versus $146.2 million at the end of the prior quarter. Vertex had total net debt outstanding of $282.1 million at the end of the first quarter of 2023, including lease obligations of $129.9 million, implying a net debt to trailing 12-month adjusted EBITDA ratio of 1.5 times as of March 31, 2023. We continue to remain fully exposed to current refining margins with no fixed crack spread price heads contracts currently in place. Looking to the second quarter of 2023, we anticipate total conventional throughput volumes at Mobile to be between 68,000 and 72,000 barrels per day, reflecting total facility capacity utilization of between 91% and 96%. OpEx per barrel is expected to be $3.80 to $4 per barrel for the quarter and our capture rate on the benchmark Gulf Coast 2-1-1 crack spread is forecast to be approximately 50% to 54%. We anticipate total capital expenditures for the second quarter to be between $30 million to $35 million. I’d now like to turn the call back to Ben Cowart to provide some final comments before we open it up for Q&A.

Thank you, Chris. Since our last call, we’ve made significant progress in continued transition to what we like to refer to today as Vertex 2.0. We managed to further streamline operations in order to improve operational focus on the conventional and renewable fuels businesses. We achieved our goal of reaching mechanical completion of the renewable diesel conversion project both on time and on budget. We also added additional bench strength to the leadership team via the addition of Mr. Doug Haugh as our Chief Commercial Officer. As James stated, we are disappointed in the startup delays for our renewable diesel facility, but I know we have an outstanding team who has demonstrated the ability to overcome these type of challenges. Overall, I’m encouraged by the significant accomplishments we’ve achieved throughout the first quarter and I look forward to providing further updates as we continue forward. With that, we’ll open the line for questions. Operator?

Thank you. Ladies and gentlemen, we’ll now begin the question-and-answer session. [Operator Instructions] Your first question comes from Donovan Schafer from Northland. Please go ahead.

Hey guys. Thanks for taking the questions. I’m glad to see the fossil fuel side of the refinery seems to be operating quite well, looks like pretty good results there. But I want to really dig into the delay on the RD conversion side. Just wondering, James, if you can kind of – I’m going to ask you to more or less kind of like visually flesh out or paint the picture for us of kind of what was going on there. On the extreme end, you can imagine a case of explosions and chaos, which it seems of course not likely given all the OSHA and then, you didn’t – it doesn’t seem like there were presumably spills or anything like that given environmental incidents. So is this just like an internal, like a sensor goes off or something. And then it’s sounds like it was isolated just on the pumping side, but there’s sort of like an – maybe an interplay with the hydrocracker. And I guess, another important question here would just be the pumping – the feedstock pumping equipment. Is that specialized equipment where you – there’s a – it’s a special type of pump given that it’s soybean oil or is it something pretty generic just moving fluids, works for all kinds of fluids, been sitting there for a while and you’re just trying to kind of figure out why this legacy or older piece of equipment’s not quite working. Anything kind of just flushing that out more completely would be great.

Yes. Thank you, Donovan. Good morning. The – so to put this in front, this was not really a material event and these are brand new pumps that were designed specifically for this case, all the different feedstocks that we’d premised. As we brought in external expertise to look at the failure of the pumping system plus our own internal plus the technology provider, what we found it is they were designed for the products that we had, however, there’s a transitionary period during startup that they were not designed for. And so as a result of it, we damaged the pumps. These pumps are, I would say, they’re specialty pumps, they’re positive displacement pumps, but we took them back to the manufacturer. They’re repairing those and returning those to us. At the same time, we’re going through a very rigorous investigation, making sure we understand what did occur, which we now know, and we’re putting hardware and changes in place such that we can protect these pumps from this again. Did that answer your question, Donovan?

Yes. And I’m just going to kind of restate to make sure I’m grasping. So it’s sort of like, you have the commissioning process and maybe there’s a – you could graph or chart the pressure or temperature or some other set of specifications that go through in commissioning and that’s maybe outside the parameters of just regular day-to-day running. And so as you’re going through the commissioning some kind of a parameter jumped outside of the design spec that was just in the nature of how you’re doing things like on the initial ramp up commissioning. And so that was just sort of a myth there. And so is that correct, am I framing that properly?

I think you characterized it pretty well.

Okay. Okay, great. And then moving on to the production mix. The drop in gasoline and diesel, that makes perfect sense and as expected kind of per taking the hydro – doing the RD conversion, it was nice though to see an uptick in the jet fuel, and I know that also kind of aligns with how the markets have been going. I know gasoline and diesel prices have been coming down, but jet fuel’s been doing a bit better. So I’m curious, is that a reflection of any ability on your guidance part to kind of quickly adjust within diesel versus gasoline versus kerosene or jet fuel, making kind of adjustments there to benefit from where prices are better? Or is that just kind of – just the incidental kind of artifact of everything else that’s happening and sort of changing simultaneously?

No, thank you for pointing it out. That’s really been the hard work of the people inside of Mobile, adjusting to the market and moving our yield to match what is going on inside the marketplace. We do have a limited amount that we can do that, but they didn’t respond well both the operations and technical group to maximize the amount of jet that we could make out of the hardware that we have.

Okay, great. Thanks guys. I’m going to take the rest of my questions offline, but congratulations on – sorry to hear about the delay, but it sounds like a pretty workable issue. So I’ll leave it with that.

Thank you, Donovan.

Thank you. Your next question comes from Manav Gupta from UBS. Please go ahead.

Hey guys. So just going back a little on the timeline. You bought this refinery, you executed some quick hit projects, the capture rate improved, then obviously you moved the hydrogen to other part. But there were still a whole bunch of projects, which the team has identified, which can lead to higher capture in the future. I think making premium gasoline is one of them. So can you just quickly talk about some of these other projects which could potentially be executed in the future that will help you drive higher capture at the refinery?

Yes, thank you and good morning. Thanks for the question. What we have identified is really yield improvement projects, premium gasoline being one of those that we’ll be looking at and some having to make hardware changes in order to be successful there. And we’re working on those. The first project is coming online here relatively soon that the team there brought forward. This is one of the things that basically the team was waiting for us to show up and us really talk about what the opportunities were and we have a list of low capital, high return projects that will improve our yield structure. And as I told the market and I told you I believe last quarter, over the next two, two and a half years, I expect to recover the profitability that we experience with a hydrocracker in service with our existing assets.

Great guys. And one thing, which if there’s a little bit of a misconception, which if you could clear on the call, some believe out there that you are tied to refined soybean oil and you do not have pretreat capabilities. But you do, you just have them in a tolling agreement and you can pretty much process anything you want. So if you could clarify that, that you’re not tried to refine soybean oil and you can actually run tallow or grease or whatever through your tolling agreements. Thank you.

Yes, it’s Doug Haugh here. It’s a good point. I think the – it is a mischaracterization of our capabilities. And it’s not just about pretreatment. It’s also about just feedstock selection, development, qualification, which we’re in the process of doing with several feedstocks today. So that is not dependent on additional Phase II developments, which we’ve talked about. It’s not a dependent on additional hydrogen, it’s not dependent on pretreatment in fact. It’s just simply prequalifying those additional feedstocks to make sure that we understand the operating parameters that James’s team has to deal with in a production environment. But that – it’s a – you’re correct, that’s a mischaracterization of our capabilities and the unit’s capabilities and the positioning of the facility as far as feedstocks go.

Thank you so much guys.

Thank you. Your next question comes from Noah Kaye from Oppenheimer. Please go ahead.

Hi. This is Jason Vernoff on for Noah Kaye. Thank you for taking my question. So how does the new RD timeline affect the timing to receive RIN and LCFS registration? When do you expect you’ll be eligible for both credits?

Yes. The timeline only affects really LCFS. We are got the applications in for RIN being able to capture the RINs we expect that within the next month or so. So that will occur or at least we are waiting on government approval, so recognize that we don’t control that, but we’ve done all the things we need to do to be able to assure ourselves that we’re getting the RINs. And then we must have 90 days of production data running to input to get LCFS. Right now, we expect that sometime in the fourth quarter or first quarter of next year for that – for us to get that approval.

Got it. Thank you. And on the 2Q guide for refinery throughput, what’s driving the 91% to 96% utilization assumption? Does the ongoing work on the RD system impact throughput? Is there any additional downtime at your plan to take in the quarter for the plant? Thank you.

Yes, there’s a couple of things that we’re playing and we are trying to give the best guidance we had going forward. There is some incremental impact with just hydrogen in the fuel system, but that’s incremental. We also will do a short pit stop and it’s just really a heater piggy and that’s incremental in the next month or so. But the one thing we are trying to signal a little bit, one of our third-party pipeline suppliers has a risk on their pipeline system of being able to deliver pipeline barrels. And so we at least wanted to signal what that looked like in the future. We’re working to mitigate those risks, but did not want to surprise you guys, and so therefore, we put that within our guidance.

Got it. Thanks.

Thank you. Your next question comes from Eric Stine from Craig-Hallum. Please go ahead.

Good morning, everyone.

Good morning, Eric.

Hey, just – so just following up on that last question on throughput, I mean, so obviously you’re calling out a few things that whether it’s just the incremental impact of what’s going on at the refinery right now, the short turnaround and that pipeline risk. I mean, what do you view once the RD system is up and running. I mean, is there – it doesn’t sound like we’re at a different throughput level or expectation. I mean, is it fair to say that if we look out into the back half of the year, we’re back to more normal expected throughput levels?

Yes, yes. We’re back in the 75,000 range. That’s of course us going forward, our fuel system is back to what we would call more normal. And that will help us as well as us just positioning ourself to run full during that time period. But we have ran pretty well for the last 90 plus days with the hydrocracker down. The team’s done a very good job managing that system.

Yes. Okay. Yes, just wanted to confirm how we think about it going forward and once we get through this quarter. Maybe just on the renewable diesel project, obviously, top of mind, you’re – you’ve talked about it quite a bit. But where does your comp – I mean, it sounds like you’re pretty confident that you’re basically going to miss a month here and then you start up – and then the startup process begins again. I mean, maybe where does your confidence lie. What are the reasons for that confidence? It doesn’t sound like you’ve received that repaired equipment yet, but is it something that is once you do – you’ve got line of sight there, and once you do, it’s a relatively quick repair.

Yes. The repairer we had purchased repair parts for these pumps prior to purchasing them, and that was part of our purchase agreement. So therefore, we had at least mitigated the risk because these are specialty pumps. So that’s why we’re confident there. However, we still have to go through some of the hardware and changes that we’re going to make to protect these pumps, and that includes a rigorous MOC process that requires us to train our personnel on site. And then we will have not just the additional subject matter experts that we’ve brought in to help us with this, but they’ll be there watching us and helping us during the startup and making sure that we take care of these pumps. Now, when I look at the rest of the system, we were able – pretty well able to operate the rest of the unit. So we didn’t see anything that looked unusual to us during the time that it was up and operating or the – we had all the compressors and pumps working. So we have high confidence that we had tested every bit of the system that we could at that time, and now it’s going forward and how do we manage around these pumps and making sure that we do the right thing and be good safety and environmental stewards of the asset and the people.

Okay. All right. And I would assume that’s something that you’ll update the Street on as a pretty material event when that restart process starts up again.

Yes. And it’s – we expect relatively short duration to put it in, but we do – I do not want pressure on – additional pressure on the team, and I want the team to really go through and be rigorous in just the troubleshooting the root cause analysis and the repair.

Sure. No, makes sense. Thanks for that. Then last question for me, just you mentioned a previous question, RINs and LCFS credits and confidence on RINs. Can you just remind us if I’m thinking about it correctly, I believe RINs, while you’re confident that you get that pathway approved that’s something that if you were not to get that in Q2, you could do retro – you could recognize retroactively and I believe LCFS is different that is not retroactive. Am I thinking about that correctly?

Yes, you are. I’ll let Doug has probably even more experience than I do on dealing with renewable diesels, so I’ll let him answer.

Yes. It’s – you have to be a little careful about the retroactive characterization as long as we maintain possession of the production, which we will during that period. And we’ve accounted for any additional working capital needs that might create, if there’s delays in that certification on the RINs. But we don’t lose the RIN value, right. It’s just – you don’t obtain it the minute you produce, but you certainly get it on the first gallon produced assuming you maintain title to that production while it’s on site. LCFS is different. You require the run time, so we – you don’t recover that value on that first 90 days of production, so you’ve characterized it correct. One just has to be careful to maintain title to the product while you’re in the process.

Yes. Okay. And just to confirm, you said that you think you get that LCFS, not the certification, but when you think you can start capturing that – those credits that would be in either 4Q or 1Q?

Yes, we expect 4Q, but again, subject to the government, which we all understand the constraints.

And then – yes, that’s 4Q not starting the 90 days, right. That would be at the…

No. That’s having value, correct. That’s having the values in production at that time. And it is worth noting, those are specific pathways. So when it comes to LCFS, one is perpetually climbing down the carbon intensity curve, right, as you’re optimizing to capture those values at the highest levels. So you’re never really done. We certainly will start up on a default pathway that they assign, and that gets you in at the base level, and then you can continue to enhance your capture of those credits as you improve your carbon intensity, which back to the related question around feedstocks is a big part of our activities.

Okay. Very helpful. Thanks.

Thank you. Your next question from comes from Amit Dayal from H.C. Wainwright. Please go ahead.

Thank you. Good morning, everyone. Just going back to the RD delay with the pumps, was this sort of a human error or a mechanical failure? Could you clarify please?

Yes. So even though we haven’t closed out the investigation, there is and the investigation will also point to not just the mechanical failure that occurred, what did it, but how humans interacted. Our team responded well and brought it to a safe place. So as we go through the investigation, we’re looking at those items that are there that can also help humans perform, but in the end it was more mechanical than human at this stage would be my characterization.

Understood. Thank you for that. Also just looking at the inventory, it grew by around $52 million. Was this related to your preparation for the RD production or was this something else?

Yes, good question. So the inventory did grow mostly on soybean oil and yes, you’re right, that was the head of the RD startup, so all in preparation for RD.

Okay. Thank you. And just last one for me, what is the CapEx, the $30 million to $35 million going into for 2Q?

Yes. I would say the majority of that is going to be part of the Phase 2 project for RD. Then of course, we have our normal maintenance CapEx. That makes up the balance of that.

Okay. Thank you. That’s all I have guys. I appreciate it.

Thank you.

Thank you. Your next question comes from Brian Butler from Stifel. Please go ahead.

Good morning. Thanks for taking my questions.

Good morning.

Good morning, Brian.

Just on the first on renewable diesel, was any renewable diesel produced before the feedstock pump failed?

No, no. We were in the startup phase getting the – everything conditioned so that we could introduce steam and that’s when the failure occurred.

Okay. And when you think of the repair and then how kind of the ramp up is going to work, should we – you’re going to be producing something, I’m guessing, or at least your plan is to produce something in June, and how does that ramp through the back half of 2023, if you think of that 8,000 kind of target of what can be produced before Phase 2?

Yes. We were going – we have a production plan that was really directed to us by the technology provider Haldor. And we’re going to start let’s just say kind of mid rates and then we’ll ramp up as the catalyst is conditioned and that’ll wrap up over a four to six-week kind of period is what our plan is. But we won’t move forward until we’re together with our technology provider and make sure the catalyst and we’ve got the oversight looking there to prudently and bring the unit forward up to the max rate that you described.

Okay. And that – so that means kind of early second or third quarter, you could be at that 8,000, I’ll call it August, July.

That that would probably be our guess at this stage, we’ll continue to provide that this would go forward as we progress through startup and through the first several months of operation, the first month or two of operation.

Okay. And then on the price for renewable diesel, can you give some color on kind of where that pricing stands? If you think of the price stack I guess you’d call it, where you have the ultra low sulfur, RINs, blenders tax credit, and then I guess LCFS, but that’s not until fourth quarter or first quarter next year.

Yes, that’s correct. And I – that, that is the stack of credits. Doug here, I think the values as well as diesel has come down, renewable diesel has come down as well. Obviously the blenders, when you’re calculating that stack, the blender’s credit’s constant because it’s a dollar credit set at a value. The RINs obviously will come in and out as that market continues to balance. RINs have remained strong relatively this year and we’d expect that to continue, given the supply and demand balance on renewable. The real change in value of the stack, if you’re tracking it, has been LCFS, so fortunate or not for us. Right now, foregoing the LCFS values on the first 90 days of production as we described, was a fairly nominal impact because LCFS has come off in value so much in the past four months. One couldn’t predict that, but we’ll take it. And it certainly makes us feel a little bit better about not having that one on startup. But otherwise, the value is driven by the underlying diesel value, the volatility in the RIN, and then the changes in LCFS and then you just add the dollar credit on top of that.

Okay. Do you guys have maybe what a number would’ve been for first quarter, just kind of a reference point? I just want to make sure we’re kind of all in the same place.

No, I mean, I just refer you to public indexes of that we don’t quote a price on it and it changes every day.

Right. Okay. Then I guess on the feedstock side, can we go through maybe kind of the strategy there and kind of what’s – what feedstock has been acquired and at what price that inventory has been built at?

Well, let me just speak about infrastructure, which I think is important to appreciate. We’ve had some questions around feedstocks in general, pre-treatment and RINs it’s all related. So it’s important to understand that as we get each pathway qualified, you have to obviously procure the feedstock at good values. You got to logistically manage that to get it to the plant. You got to have infrastructure store it and segment it. You can co-mingle like for like, but you can’t just co-mingle feedstocks at will because the old violate you are in pathways. So there’s very specific infrastructure that’s been developed. We have a – when we look at feedstock preparation the team’s done tremendous work to put in the capabilities we need to supply the plant very economically and those are both logistical and storage infrastructure. Its a couple hundred thousand barrels of barging capability and capacity that we have now in service every day to feed the plant and almost half a million barrels of storage for both the feedstocks and the RD production. So I think when you compare this facility to others in terms of the logistical capabilities and capacity storage infrastructure that was available in Mobile, both at the refinery and commercially available to port, it’s been a tremendous asset in facilitating our startup in terms of building inventory to make sure we can run at the max rates that James can safely achieve with the operating team. And that feedstock supply is not a constraint and that we’re able to do it optimally against the marketplace. Again, because we have the logistical capability to go get the feedstock and not depend on others, it’s a pretty thin supply chain that can be unreliable if one doesn’t plan for it. So we’ve really been focusing on the infrastructure to make sure we can reliably and economically obtain the feedstocks we need to run at max rates.

Okay. And then one last one just on conventional, can you update us on just kind of the sensitivity to the crack spread for like let’s say a barrel – a dollar barrel change. How should we think about that impact on the conventional business?

Yes. You’re – so Brian, this is the tricky question as far as trying to pin down what the cracks are going to do and the market conditions and what we’re looking at. Obviously, at the moment cracks have come in. There’s a very broad view on where the industry’s going and it would be shooting in the dark. It could be really good and it could be not good at all. So you got to pull those research data points out for yourself. We think that we’re on a good quarter for the second quarter. Cracks have come in some, I mean, you can see that just go look up the 211 crack. So we’re managing to that and very focused on our efficiencies and our yields and I think we’re set up really well to navigate whatever’s coming our way.

Okay. Thank you very much for taking the questions.

Thank you, Brian.

Thank you. Your next question comes from Jason Gabelman from TD Cowen. Please go ahead.

Good morning. Thanks for taking my questions. I wanted to revisit the third-party pre-treatment agreement and I wanted to confirm one, there is an agreement in place with a third party pre-treatment facility. And if so what are the amount of volumes that that covered for you and what is the fee you have to pay to access those feedstocks?

Yes. I think to clarify, we are in pre-qualification of those pre-treatment processing capabilities. So there’s agreements being negotiated. Those negotiations are subject qualifying the processing capabilities of the plants that we’re working with. And those will vary by feedstock. We won’t know what the yield loss will be in pre-treatment until you run the molecules through the plant and have proved production. We’ve got to get through that phase, which we’re starting now. And to clarify, it’s not one facility. We don’t want to be dependent on any one single point of failure in the supply chain. So we will pre-qualify multiple facilities and our – on that pathway now. And those are also positioned to allow us to access different feedstocks, right, ranging from the tallows and greases market as well as the DCO market, right? So the chemistry and metallurgy necessary to process all those is different. So in all likelihood this will be multiple pre-treatment contracts and facilities not a single clear.

Got it. Maybe I’ll ask just for a clarification on that. What’s the target in terms of the amount of volumes you expect to access from those facilities and when would you expect to have those agreements finalized?

I would expect that volumetrically we are trying to position pre-treatment capacity equal to our production capacity, right? So the dance there is to sequence those to match the ramp up rate that James achieves with the plant and also, the step up from Phase 1 to Phase 2. But as we look at developing that supply chain and continuing to pre-qualify these facilities and the feedstock feeding them the production plan is to match the production capacity at the plant. So now whether we do that on every barrel or not is optionality that we want to have in hand. It may not be optionality we use every day. If you look at the value of those feedstocks at the moment, there’s not terribly attractive margins associated with the pre-treatment capacity because the feedstocks have come into a different point of equilibrium on the price of the finished product. So you want some flexibility bill to ramp those up and down. That’s one of the advantages we see of contracting it versus constructing it is we don’t have fixed capital that forces us to run it when it’s uneconomic.

Okay. Understood. And my follow-up just on capital expenditures for the project I think when you set out to build this renewable diesel facility, you envisioned having a third-party build the hydrogen plant and it seems like you may be committing some capital to that and that’s what Phase 2 is, which wasn’t initially envisioned. So I guess with Phase 2, what do you expect the total cost of the renewable diesel project to be and is there any adjustment to previous guidance for full year 2023 CapEx? Thanks.

Hey Jason, this is James. So what we’ve done, there’s two things we’ve done on our capital and we are following and supporting our hydrogen provider with it on capital. So I don’t have a final number to you there yet, but we have moved some of the capital out from underneath them and executing ourselves because we – number one, we have the capability to do it. Number two, we have the cash, and number three that really unloaded our hydrogen supplier to allow them to just focus on the unit itself. And so we are also getting the site ready for that to be delivered. We’re doing the silver work ourselves, putting the pilings in which start in the next week or two, and then in turn, we’ll move that facility in it’s already been delivered to the port of Mobile and we will be moving in and after that. So that’s really what you’ve seen changed in our point of view on what work we’re going to self execute versus what we would them to do. And so that’s changed a little bit but we are subject to them and where they are on their project to make sure we know exactly where we are as we get the final investment decision there on their piece of the work.

Okay.

You want to say…

Okay. If I could maybe sneak a third one in I know there’s been in the past some hope to improve the capital stack and refinance some of the debt and address some of the convertibles. Any update you could provide on that front on maybe how you’re thinking about things unfolding on the balance sheet and timing around that would be helpful? Thanks, guys.

Yes. Good question. I think our near-term focus obviously we were able to pay a little bit down on the term bit during Q1. Currently the focus is getting the RD unit up and running, utilizing our current cash has working capital around the inventory and then we will start looking at what are our options to really clean up the balance sheet and get things structured the way we want long-term after that.

All right. Got it. Thanks.

Thank you, Jason.

Thank you. There are no further questions at this time. You may proceed.

Okay, everybody, thank you very much for joining us this morning on this call. We’re very pleased with the performance of the company and the business disappointed with the pump delay. We see that as a bump in the road not a major concern for the company. Our team is on top of it, we’ll deliver the production as we discussed. And we really look forward to as Chris said, we’re prepping to turn our balance sheet into a very strong balance sheet. We have been very reliable in our operations of the site, so we’ve really put a lot of things to bed. We’ve built our team out. I’m very excited to have Doug here at the table with us. He brings a whole new perspective around our feed origination and our finished product strategy. So all of that’s good. We’re actively developing our energy transition platform. That’s really our focus. That’s the core of our company. We’re not coming into Mobile and acquiring a carbon asset to be another independent refinery. We’re coming in to pull that asset into an energy transition platform and continue to develop the opportunities around that. And there’s a lot left to come. So I’ll leave it with that. And thank you everybody again for being on the call. We look forward to a progress report as we start this unit up and really close this part of our development journey with this RD plant and then we’ll go forward. Thank you.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines. Thank you.