Vertex Energy Inc (VTNR) 2023 Q2 法說會逐字稿

Good morning and welcome to the Vertex Energy Second Quarter 2023 Earnings Conference Call. (Operator Instructions) Please note this event is being recorded.

I would 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 second quarter 2023 results conference call. On the call today are Chairman and CEO, Ben Cowart; Chief Financial Officer, Chris Carlson; Chief Operating Officer, James Rhame; 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 on our call and the press release issued today. Today's call will begin with remarks from Ben Cowart; followed by an operational review from James Rhame; a financial review from Chris Carlson; followed by a review of our commercial strategy by Doug Haugh. At the conclusion of these prepared remarks, we will open the line for questions.

With that, I will turn the call over to Ben.

Thank you, John, and good morning to those joining us on the call today. During the second quarter of 2023, market shifts in refining margins, combined with startup expenses associated with our renewable diesel facility, impacted profitability at the Mobile facility. While several factors associated with the startup and optimization of our RD facility affected financial results for the quarter, the primary limiting factor on expected financial performance is attributed to the volatility of market conditions for refined fuels and products.

Without compromising safety or quality, our goal is to maximize profitability in these ever-changing market conditions. To that end, Vertex has been laying the groundwork for strategic pathways that we believe can help us accomplish our performance goals as an energy transition company. This broader strategy, centered on creating a vertically-integrated renewable fuels focused company is built on 3 key principles, which our team will elaborate on in greater detail throughout the call. First, our commercial strategy; advancements in our feed origination and product marketing strategy are crucial to capturing opportunities along the full value chain. These are core competencies that Vertex has developed over more than several decades, and we have recently made significant progress here as Chief Commercial Officer, Doug Haugh, will address on the call today.

Second, continued operational excellence in the form of reliability and attention to safety. The reliable, smooth operations of our facilities provides the consistency and visibility required to execute on our strategic vision and continue to scale the business going forward. Our operational team continues to perform exceptionally well, which Chief Operating Officer, James Rhame, will cover shortly.

Third, capital efficiency. Our focus on the efficient use of capital through continued balance sheet improvement and enhanced risk management strategies remain a key priority for the business as we continue to grow, which our Chief Financial Officer, Chris Carlson, will discuss. Going forward, we will continue to develop and leverage expertise as we build on our accomplishments today and execute a much larger vision for the future of Vertex, with the commitment to providing our stakeholders with an increasingly clear view of the path ahead.

With that, I'd now like to hand the call over to James Rhame, our Chief Operating Officer, who will provide an update on our operations during the quarter.

Thank you, Ben. Good morning, everyone. I'll begin with a brief report on our health, safety, and environmental performance. The second quarter of 2023 was a clean quarter with 0 OSHA recordables and 0 incidents of environmental noncompliance recorded across the entire company. Additionally, Mobile saw 0 process safety events. I want to commend our team for their continued commitment to excellence in protecting our people as well as the environment during an extremely busy period.

Marrero had a successful turnaround during the second quarter in which we executed a full rebuild of the evaporator during the outage. Since taking the outage, Marrero has exceeded the budgeted capacity utilization. Our conventional fuels operation team at the Mobile facility successfully navigated several challenges during the quarter, including equipment failure and supply disruptions, mitigating further potential impacts to our day-to-day conventional business. Second quarter conventional throughput volumes at the Mobile refinery averaged 76,330 barrels per day, or 102% of stated operating capacity. This strength in conventional throughput is attributed to our team's ability to procure feedstock despite pipeline outages.

Direct OpEx per barrel for the second quarter was slightly above our initial expectations at $4.23 per barrel. This was largely driven by incremental cost associated with the repair of the RD unit feedstock pumps as well as the additional effort associated with reengineering the startup sequence of the renewable diesel unit. Our finished products such as gasoline, diesel, and jet fuel accounted for 61% of our total product yield during the second quarter 2023. With the completion of the renewable diesel conversion project now behind us, we believe that this yield profile is an accurate representation of the expected yield profile going forward. On a combined basis, our fuels gross margin per barrel during the quarter was $7.34 per barrel. On a conventional fuels-only basis, our fuel gross margin per barrel was $8.03, reflecting a capture rate of 34%. The erosion in our reported fuels gross margin per barrel during the quarter was driven by a combination of several facts.

First, first quarter compared to second quarter refining margins were compressed due to approximately 25% drop in the crack spread. Second, our reduction in crude prices of approximately $8 per barrel during the quarter impacted our inventory position. Third, the base refinery encountered yields impacts due to RD unit's operational downtime and startup. Regarding the RD unit conversion, there was $20 million in cost associated with the RD unit startup, most all of which were onetime costs. These costs included margin downgrade, fixed costs associated with the pumping systems, and feedstock devaluation that occurred prior to successfully getting the feedstock intermediated. Vertex renewable diesel conversion set the industry pace for safety, cost, and schedule. The unit achieved on-spec status just 14 months after the site acquisition. And within 15 months after the acquisition closed, it was at full operating rates.

Since commencing initial production of RD on May 27th and achieving our targeted Phase I production rate during the initial test runs, we have observed stable performance and reliability of the facility along the throughput curve. As we continue to operate, we are focused on optimizing the unit through the pursuit of pathways approval for alternate feedstocks to improve LCFS credits by improving the carbon intensity, which allows us to unlock the full value of the asset which Doug Haugh will elaborate upon following a financial update from Chief Financial Officer, Chris Carlson, to whom I will now hand the call over.

Thank you, James, and welcome to those joining us on the call today. For the 3 months ended June 30, 2023, Vertex reported a net loss attributable to common shareholders of $81.4 million, or $1.03 per share, versus a net loss attributable to common shareholders of $67 million, or $0.99 per share, in the second quarter 2022. Included in this quarter's net loss on a GAAP basis is a onetime noncash interest expense in the amount of $63 million, which reflects the recent convertible note exchange transaction we executed in June. We reported an adjusted EBITDA loss of $34.2 million in the second quarter of 2023 versus EBITDA income of $71.3 million in the prior year period. The adjusted EBITDA loss for the quarter reflects the combination of weakness in refined product margins as well as the impact of incremental costs associated with the repair and startup of our RD facility during the quarter. Total capital expenditures for the second quarter 2023 were $30.5 million, in line with our prior guidance issued on May 9.

Turning to the balance sheet. As of June 30, 2023, the company had total cash and equivalents, including restricted cash of $52.1 million versus $95.1 million at the end of the prior quarter. Vertex had total net debt outstanding of $275.3 million at the end of the second quarter of 2023, including lease obligations of $162.1 million, implying a net debt to trailing 12-month adjusted EBITDA ratio of 3.6x as of June 30, 2023. While shifts in market pricing had a negative impact on the profitability of the conventional refining business during the quarter, prices have materially improved from the lows experienced earlier in 2Q. The Gulf Coast 2-1-1 frac spread has materially improved from the lows of approximately $18 per barrel in 2Q to over $35 per barrel as of the end of July. Additionally, market pricing for refined products outside of the benchmark, such as Jet A has also recovered substantially, improving 40% from the lows witnessed in 2Q '23. As a result, our current liquidity situation remains adequate to satisfy our near-term obligations and capital plan for the remainder of 2023.

We remain focused on upgrading the overall capital efficiency of our balance sheet. During the second quarter, we successfully executed on a cashless equity conversion for approximately $79.9 million of our 6.25% convertible notes for an aggregate of 17.2 million shares of common stock. This is expected to drive approximately $5 million in annual cash interest expense savings and remove the longer-term need to meet the obligation of principal in cash upon maturity. Refinancing of the remaining $15.2 million of convertible notes as well as the $150 million in term loan debt outstanding remains a top priority of our financial strategy.

Keeping in mind the prepayment prohibition clause on our term loan, which expires on October 1 of this year. We maintain an opportunistic view on refinancing this debt with more efficient, less expensive sources of capital, consistent with our strategic focus on our balance sheet and maintaining longer-term capital efficiency. Looking at the third quarter of 2023, with the successful conversion of our hydrocracker to renewable diesel production now complete and considering the lower complexity of the Mobile facility, less than 50% of our expected future product yield profile now falls within the current benchmark product composition. We, therefore, believe it is far less useful as a tool for forecasting expected profitability of our conventional refining operations and will no longer provide specific guidance on expected capture rates.

For the third quarter 2023, we anticipate total conventional throughput volumes at Mobile to be between 74,000 and 77,000 barrels per day. Our expected yield of conventional products is expected to be comprised of between 59% to 63% finished products, such as gasoline, diesel, and jet fuel, with the balance in intermediate and other products such as VGO. OpEx is expected to be $3.60 to $3.80 per barrel for the quarter, and we anticipate total capital expenditures for the third quarter to be between $20 million to $25 million.

I'd now like to turn the call to Chief Commercial Officer, Doug Haugh.

Thank you, Chris, and good morning. Now that we've achieved commercial production and sales of RD and proven the unit to run at designated rates with yields at or better than target, we have quickly shifted our focus to accelerating the deployment schedule of our multi-feedstock supply and production strategy. We are accelerating this through primarily 2 factors: 1, the new plan has demonstrated operational stability over a wider range of throughput rates than we'd originally anticipated at acceptable conversion rates, providing valuable insight into the optimization of the facility; 2, the economics of producing RD from RBD soybean oil are currently unattractive under prevailing market conditions. While the RD unit and our supply system are multi-feedstock capable, we had initially anticipated a longer break-in period to stabilize and streamline operations, while utilizing RBD during this initial period. With diligent work from our supply, engineering and operations teams, we were able to introduce Distillers Corn Oil, or DCO, into our feedstock blend last week and have advanced a combination of 8 different feedstock blends through our feedstock approval process in the last 6 weeks.

These include technical tallow, DCO, canola, and crude degummed soy, processed through a nearby pretreatment unit under a tolling arrangement. The reason I mentioned 8 and not just the 4 different feedstock types is because we must run each supplier and origination point through our feedstock approval process before it becomes approved for use in blends run through the RD unit. This process is robust and includes quality assurance and quality control steps at each critical step along the supply chain. I specifically want to thank the engineering and laboratory staff at the Mobile site and the supply and trading team in Mobile for advancing our feedstock schedule by months with the hard work and diligence required to do it safely while maintaining the quality we need to protect our catalyst life longer term.

With approvals in place, we've obtained attractively-priced commercial supplies of crude degummed soy, technical tallow, canola, and DCO for this quarter. These feeds will be included in our feedstock blends for the remainder of this quarter and optimizing a feedstock diet consisting of significant percentage of these lower-cost feeds is a key priority for our RD team. In parallel with these current optimization efforts, our feedstock development team is sourcing supplies of other lower CI and lower cost alternatives in the UCO and fats, oils, and greases market, while they build a longer-term supply of agricultural oils produced from cover crops. This combination of near-term optimization and longer-term feedstock development builds on the 20-plus year history of Vertex of developing, sourcing, and scaling alternative feedstocks.

To enable and support these feedstock optimization and development efforts, we have 500,000 barrels of tankage and logistics capacity in Mobile that provides dedicated storage for each family of feedstocks as required by the EPA. This infrastructure also provides us the necessary blend tank capacity needed to optimize the blend prior to final injection in our pipeline to the refinery day tanks that feed the RD unit. Our feedstock supply system provides us with the capacity, flexibility, and capability needed to optimize our mix of many alternative feedstocks using a combination of truck, rail, and barge logistics with the dedicated storage and blending tanks that a multi-feedstock supply strategy requires.

In addition to the feedstock supply system, we have added storage capacity to our deepwater products terminal utilized to load vessels with RD for supply to the West Coast of North America. With these additions, we now have 450,000 barrels of RD storage piped directly from our RD unit to our Blakeley Island terminal where it's manifolded together and piped directly to our deepwater dock. This system performed well loading our first shipment last month with rapid loading rates that minimize dockside time for the vessel and eliminate unnecessary demurrage or delay for deepwater vessels. We added the additional storage to ensure that we can more easily maximize volumes loaded to each vessel, which in turn, minimizes our freight cost per gallon.

In closing, I would just like to thank our supply, engineering, and operations teams for allowing us to safely advance the schedule of this work and for obtaining excellent operational and safety results during a hectic startup and commissioning period. This team is demonstrating that we can build upon a solid operation with an advanced feedstock supply system that allows us to optimize available margins. While advancing those plans are a key priority for all of us at Vertex, the ability to do so starts with safe and reliable operations, and we're grateful for the team for delivering those conditions.

Thank you for your time and attention today. We look forward to taking questions following some final remarks from Ben.

Thank you, Doug. Over the past year, our focus has been on executing the biggest development project in the 22-year history of Vertex. We knew we owed it to the market to deliver on our target of successfully transitioning the Mobile refinery and completing the renewable diesel conversion project. As Doug and the team have laid out, we have the assets, we have the operational capability, and with our expanded team's expertise, we're well positioned to execute a strategy that has been taking shape since the close of the acquisition of the Mobile refinery.

We are currently drafting our 5-year plan and are looking forward to publishing this in 2024, following finalization and Board approval. For now, as I stated in the beginning of the call, we will build on our achievements to date and pursue areas of greatest opportunity, which we believe are in feedstocks, logistics for products, marketing, balance sheet improvement, and risk management. The progress we've made to date is exciting. We know we have a lot of work to do in terms of translating this to shareholder value. As always, we are grateful for the shareholder support that allows us to continue executing our vision as a vertically-integrated energy transition company.

Thank you for joining us on this call today. We look forward to providing you more information and updates in the near future. With that, we will open the line for questions. Operator?

(Operator Instructions) The first question is from Noah Kaye with Oppenheimer.

So nice job on the reliability and just the throughput at Mobile, and hearing that's the new normal is very encouraging. Understand the logic around not providing a capture rate going forward given the product slate. But can you give us some directional guidance? I think, Chris, you were alluding to this in your prepared remarks on where you think margins can go as we look out here in the third quarter and the back half. Clearly, they should go up, based off of where the benchmark is and some of those other prices. But can you help us put a little bit finer point on it because I think we just want to get our bearings here from the sell side?

Good question, Noah. So yes, I would say definitely, as I noted, we're seeing improved margins in the third quarter, especially over what we saw in the second quarter. And as far as the percentages of yield and what we're going to see out of the refinery, that's what we're going to present going forward from a yield perspective.

Okay, we can try to follow up offline. Maybe if we can try to get a little more clarity on RD production. Clearly you're doing a lot of work around sourcing the alternative feedstock, having run into the reality of RBD economics here. Just given everything you said, when should we expect the company to start profitably generating renewable diesel production and sale?

Well, I think we're going to optimize the mix that we outlined today for this quarter. I think there's the margin environment similar to along with crack spreads has improved this quarter versus last quarter just on any feedstock mix, right? So I think we should all be encouraged by that. It looks like we commissioned a unit and produced. At the bottom. Of course, we hope for the near term that's the case, and the margin environment this quarter looks positive.

Sorry, I just want to get a little bit of a clear answer to that. You've got peers guiding to renewable diesel production for the back half of the year, at least in volumes. I understand they have different feedstock blends. But maybe you can help us better understand at least the steps that you need to take to get alternative pathways approved and whether or not you see a pathway here to actually materially increase production using RBD.

Yes, I think that we're going to -- the main focus though is this quarter is getting those pathway approvals, right? So you have to actually run each of those in quantities enough to get the approvals for LCFS. So that's the focus right now. Our run rates are going to be based on the available margin, right? And what we found with the units, which James can speak to more clearly than I can, but the operating range of stable production with good conversion rates is wider than we anticipated, which is good. So we're not forced to run the unit at higher production rates if there's no margin available. So that's what we're exploring. That's why we're not providing guidance on throughput on the RD unit yet, similar to what we've done with conventional. We hope to be able to do that in forward quarters. But right now, having weeks of production time under our belt, we're not going to make that commitment just yet.

That's helpful. I guess if I could sneak 1 last 1 in. Just how should we be thinking about managing the balance sheet and the cash generation profile for the back half? I assume there'll be some focus on decreasing inventories. You do have some CapEx here in the guide for 3Q. Maybe you can speak to balance sheet management, cash generation, and potential additional capital sources, if you need to expand your liquidity?

Yes. Again, good question, Noah. I think as everybody knows, the last 12 months, we've put tools in place for day-to-day working capital, 1 being an intermediation agreement on the conventional side; and then also in the recent quarter, another intermediation agreement for the RD side of the business. In addition, we've retired, the majority of the $155 million convertible bonds that was out there. And as you heard last quarter, we're ahead on CapEx for Phase II. So as we look forward in the next 2 to 3 quarters, our CapEx spend is expected to go down, all of which really put us in a great position to look out and to refinance the overall business heading into the fourth quarter and first quarter?

The next question is from Eric Stine of Craig-Hallum.

So just sticking with renewable diesel, just to be clear, the 8 feedstocks that you mentioned, are those approved, or is that still in process? And then I know this doesn't necessarily matter until you get LCFS approval for those pathways, but can you just give an idea of maybe, I don't know, if it's a blended CI score or how the CI -- carbon intensity would compare to soybean oil?

Yes, we can't give you direction on the CI averages at this time. The CI scores on the feedstock categories themselves are -- it's all public information in terms of the standard CI score that you can ascribe to those. We certainly hope that our particular LCF pathways, once approved, will improve on those public benchmarks. We have no reason to believe they wouldn't. But if you want to have a basis for calculation, I'd look to those, either the CARB numbers or the (inaudible) numbers, however, you look at qualifying those, Argonne's got a spread on those as well. But yes, the approval process I spoke to is from our internal engineering team, right? So we first have to know, okay, we've obtained feed, we know we can run it, which goes through our quality control process. It's 1 thing to know that a particular type of feed which we've engineered for is workable; then we have to actually get commercial quantities of the feedstock and make sure that it meets those specs, right, because the big fear is contaminating or poisoning your catalyst, right? So we've got to keep those safeguards in place and then make sure that we run through that rigorous approval process on each of these origins and each of these types.

So that's the that's the treadmill the team is on right now to keep up at that pace. We've got many additional blends that we've got to get through in the next couple quarters to make sure we can fully optimize the margin environment that gets presented to us because we don't know, at any given time, which of those feedstocks is going to be advantaged in the forward part of the curves in terms of cost. So our goal operationally is to make sure that we are prepared both with the infrastructure, the pipeline configuration that we've got between the infrastructure and RD unit, and that all the engineering and lab works been done to qualify all of those blends. So if a particular feedstock presents a really good buying opportunity to market, we can act very, very promptly, get that into our blend, and know that we can do that safely and reliably. That's really the work that's going on right now with the feedstocks.

Got it. And understood. I obviously have got access to the various CI scores. I guess I was more getting at, as more comes in and as you see availability what that mix might be. But I guess that's more of a to be determined going forward, so I guess I'll leave it at that. Then maybe last 1 for me. So, obviously, the production, a lot of it is falling outside the 2-1-1 (inaudible) capture rate going forward, and I guess understandable. But any thoughts on maybe changing the way that you talk about this, not the 2-1-1 anymore, maybe it's a different crack spread, or anything along those lines, because I'm just envisioning when you do your quarterly update, what are those metrics that you're going to give and does that truly give transparency into what the quarter is looking like, whether it's a week or 2 after quarter end.

Yes. So what we're trying to give you is really more of what our yield structure is as we go within ranges. And this way they're commercially available or available in the market versus current plus forward strips, and doing that should allow you enough -- we hope enough insight to be able to look for what the guidance will be. And so we're giving you crude rate, capital, yield, and what did I miss? That's it.

Yes. I think it's probably good to add that we're benchmarking off of LLS crude posting, so I think you need...

Yes. LLS posting, CBOB, Gulf Coast, [VGO] Gulf Coast, and ULSD. That covers...

Okay, I'll take the rest offline.

That's most of everything we have.

It should be actually better than what we trying to do with 2-1-1, especially with the hydrocracker out of service or moved to RD service, sorry.

The next question is from Amit Dayal of H.C. Wainwright.

Just on the repairs and the costs associated with that, how much of this was anticipated and how much actually went into the repairs for that 20 million that incurred in 2Q?

Yes. So what I described was what I put the start-up cost, which was, of course, delayed further from what our original plan was when we damaged the pump. So none of the cost -- about 1/3 of it was just straight repair costs and what the team had to do to get the pumping system to work. And with that, we also brought in expensive startup material and downgraded, and that was about another 1/3 of it. And that startup material was what was required, especially as we restarted. That was our plan. However, we did not plan for the way that the team had to adjust to be able to start up safely and make sure we get through the initial commissioning phase. And then the inventory devaluation occurred because we knew we had to get way out in front of this unit to make sure we had feed in case we did start up. But during that time, we did get a devaluation of the bean oil.

Understood. And then I may have missed some of the commentary around the feedstock and the RD production. Just to clarify, are we still producing at 8,000 barrels per day given our feedstock process that's going on in terms of finding the most optimized pathways, et cetera?

No. To be clear, we're going to vary the production rate based on a couple of factors, the biggest of which is margin opportunity. So if there's very, very attractive margins, we will max rates within safe limits, of course. And then we're finding the optimum rate on each blend and each mix that we feed to the unit, which is going to take some trial and error. We need to ramp the unit up and down to do that against each blend that we want to optimize with. So that's why we're -- and I appreciate the earlier question as well, but that's why we're not providing the same throughput guidance yet on the RD unit that we have for the conventional. So we hope to do that in the future. We hope everybody understands that we're past commissioning and we run at design rates. We know that unit can do it. Now it's what's the operating envelope that's available to us to optimize with.

So when will we be able to maybe provide this guidance, fourth quarter or early 2024?

I think there's certainly some opportunity for fourth quarter, but I would feel much more comfortable with next year I think heading in. We've fully got the system run in. We've got the optimization plan done. We know what our conversion rates are at each of those blends. And then we can get much firmer guidance, and we'll have a little bit more forward look on the feeds at that point because we'll know what our recipes are going to be with more certainty going forward. So we'll actually be buying those feeds on a forward basis much more consistently, so that will give us our run rate forecast a lot more stable than what we have right now.

Got it. And just last 1, regards inventory, it looks like we sold some inventory into the quarter. I'm just trying to bridge the logic of trying to sell more inventory during tighter market conditions. Just any color on how we are managing that side of the business and what maybe drove -- and maybe I didn't understand this correctly, but if we did sell more inventory into the quarter, just trying to understand the logic behind that.

So just to be clear, if you're looking at last quarter to this quarter, in the last quarter call, we did discuss inventories building around RD, especially around the feedstocks that we brought in. We did have some other inventory builds at the end of last quarter at our Marrero facility which the majority of that has started to sell during Q3, so that's the shift that we're seeing in inventory at the moment. So again, a lot of that is driven by the RD startup.

The next question is from Manav Gupta of UBS.

So I wanted to understand the 2Q capture a little better. Was the fact that you have a slightly higher diesel yield and a high jet fuel yield, and those products were discounting to gasoline also a drag on your capture in the 2Q?

Yes, particularly jet.

Jet was big difference between 1Q and 2Q?

Okay, so it was jet. That's what I thought it was jet. But jet has recovered and so has diesel. So, again, I don't want a guidance, but if it was basically jet and diesel trading at a big discount to gasoline, those 2 have reversed, right?

Yes. And I wouldn't say it's a discount to gasoline, more as a discount to their traditional position versus gasoline that had been in the prior quarter. So you saw a realignment in the second quarter of distillates versus gasoline. Not entirely anticipated with driving season hitting and gasoline going through its seasonal adjustment, but certainly that impacts out of the 2-1-1 translates into a capture rate for us in a big way. So I think that's why we're trying to move your view from a capture rate at a gross level against 2-1-1 to more of an understanding of the actual yields, particularly given how much jet we make, which is a substantial portion of our production.

The next question is from Brian Butler of Stifel.

Just on the conventional again. At the current prices, is conventional profitable? Is it past breakeven?

Yes.

Yes.

So if we were to run at current prices for a quarter, the conventional would be profitable. I just want to be clear on this because I guess what's your...

Yes.

Yes. So the expectation is on a long-term basis, you're able to manage this at some level of profitability. Am I correct?

Absolutely. Brian, 1 of the things you see us doing now that we've moved the hydrocracker in the renewable diesel service and is dedicated to renewables, it's how do we continue to try to get yield improvements inside of the refinery? We've already captured a few of those. We've got more coming than we expect within the next couple of years to replace that income generation, not only within the fence line, but really 1 of the reasons that Doug's here is to help us make sure we get the best netback all the way with our products that we are now selling outside of our shale facility. And that's what you see Doug and his team doing is really making sure that we're getting -- we're capturing good netbacks on every 1 of our molecules as we try to improve the yields across the refinery inside the fence line.

Yes, that's right, James. It's twofold, right? It's what we can do inside the fence line on yields and then it's what we can achieve commercially in the market for all the production of the refinery which there's ongoing optimization opportunities and margin capture opportunities there. So I think the -- and also it's not just the second quarter market conditions but the unit going through commissioning, we have to run conventional different as well. So it's not -- the 2 aren't disconnected, but that's why we're -- the yield guidance, going forward, we believe is accurate on the current facility and, yes, it's profitable at today's crack, certainly.

Let me just (technical difficulty) think about the third quarter that we're in and what we're looking at as far as forward curves, the fact we've added roughly 10,000 [barrels] a day production on the conventional side really positions us well as we look ahead. That's added value that we originally really didn't anticipate that we're really pleased about.

Yes, the teams continue to optimize (technical difficulty).

Lot of good on a go-forward basis.

Okay. And then on the renewable diesel, if my understanding is correct, the changing of the feedstocks, you're not running at 8,000 barrels per day, and at some point, I'm guessing you get there, but is that a fourth quarter or is that a first quarter 2024 event?

Yes. So to be clear, again, (technical difficulty) earlier question, we are not running at 8,000 barrels a day and we're not currently providing guidance on throughput for the third or fourth quarter at this time. To be clear, the unit is fully capable of operating at that level. That's what we've proven out with the commissioning process. And we're very, very pleased with the conversion rates and the throughput capacity of the units performing above design target. So we're pleased with that. But this is the necessary work we need to do to position the unit for the long-term success and also the market conditions don't tell you to run hard. So we're going to optimize against the available margin and find the optimum operating envelope that the unit provides us to do that.

All right. And so on this uncertainty around the feedstock on the renewable diesel, does this limit your ability to get a CI score for the LCFS? Does that now get pushed from an expectation that you were going to get a score in the fourth quarter now to sometime in 2024?

No, in fact, that is the work that we're doing now. If anything, we've accelerated versus delayed in that regard. So the pathway approval requires us to run some commercial quantities of each of the feeds that we seek pathway approval on. And then to move from the default score to an approved pathway, we've got to submit all of those details on each run through the CARB process that's required to achieve those pathway approvals. So now, look, we don't control the schedule of that. They can get backlogged as some of the other regulatory agencies have been of late. But for what we can control, we are marching forward at all pace.

All right. And you've already received authorization to sell the RINs in your other tax credits, is that correct?

RINs are -- yes, we've been (inaudible) approval is the -- we've secured that. RINs have already traded and been produced and filed, so.

Okay. And then as we wait on solving the feedstock on renewable diesel, is the hydrogen expansion project slowed or is that still expected to continue to move forward?

Yes, it's still expected to move forward mid-year next year is when we plan on bringing it in. We're doing the capital work around it where we tie into it as is Matheson who is doing all the foundation work right now.

The next question is from Donovan Schafer of Northland.

So the first question I know -- I did miss some of the prepared remarks, juggling calls, so apologies if you've already covered any of this. But you've moved away from providing a capture rate, talked about jet fuel as a big part of that. Your "other categories" includes intermediates like VGO, LPG, and other items. That's also a significant piece, I think 37% of the yield this quarter. So I'm curious if in this quarter if you can give us a sense of the magnitude of the significance of the impact that had on the capture rate? Was it really pretty much all on the jet side and that held steady or didn't make a big difference, or was it mostly jet but there 60:40 like mostly jet, but there was still a big impact from changes in that other category?

And then and then going forward, I appreciate the logic of moving away from the capture rate. It probably makes a lot of sense. We might need some help figuring out how to follow something like VGO in particular, (technical difficulty) product that gets traded between refineries and whatnot. There's not a great public -- we don't really get public prices that get reported. So I'm wondering if you can help us think through what we would track or what we might look at to estimate where that other category is going that's like more than 30% of the yield.

All right, let's first start with your first question, so what was the impact? So roughly -- I'll answer the yield component of it. It was roughly $1 a barrel impact just on yields and crude devaluation was another dollar a barrel during this quarter. Top of it, we saw the jet drop by about $30 relative to crude across the quarter. Quarter 1 to quarter 2 it was still healthy. However, it was a significant drop, and those all affected the capture rate. All right. So that's question 1. Question 2 was really around VGO.

Yes. Let me say this around VGO. We're focused on the key products, which is gasoline, diesel, jet, where you can actually go get those index pricing and do your evaluation against LLS crude. As you said, Donovan, VGO is a...

Large piece of our yield structure.

It is, and there's not a big index to go draw from publicly to try to figure that out. So you got to -- that's why we're not making it part of the guidance because it has the ability to bring a big positive or bring a negative at the same time, depending on what those markets do. So as you said, that VGO trades between refineries. And the rule of thumb, James, I guess when it's either 6, yes.

60:40, 70:30 versus CBOB price is our rules of thumb.

Gas, diesel.

Gas, diesel.

Yes. So either 70 gas-30 diesel or 60 gas-40 diesel, everybody has their own choice on what they use to figure that out. So I think we're probably tracking it closer to a 60:30 today.

Yes. It has moved away some recently due to some cat cracker outages recently in the market. But that generally has worked pretty well for us long term.

We'll leave that up to you, Donovan, but that's probably the best guidance we can provide to you there.

Okay. And then my second question is on the cost that you incur for RINs on the fossil fuel side. So it looks like, unless I just misrecorded things, it looks like the cost of RINs actually went up from $2.51 a barrel in Q1 to $3.66 a barrel in Q2. When I look at the EPA's dashboard showing these pricing, I believe it's D6 RINs that you guys typically purchase. You maybe have the option to do D5 if you see that as advantageous for any reason. But in any case, the pricing for those seems to decline from the first quarter to the second quarter. So I'm curious what caused for you guys to increase. Was there a change in the commitment -- obligations for you guys where you had to do more RIN -- purchase more RINs than you would have in the past based on yield and mix. Or is there a timing delay between what I would see like on the EPA's pricing dashboard versus what you experienced? Just trying to understand the difference there.

Yes, I'm not sure how that -- I'm actually not familiar with the EPA dashboard price, but the spot price in the RINs market has, by our experience, increased a bit during the quarter. It didn't go down.

Specifically D6s.

Yes, and...

Okay. So you saw D6s go up on a yes per RIN that actually increased and is it regional -- there's regional pricing?

No, but it's not a liquid -- it's a liquid market, but it's not like traded index, right? So all (technical difficulty) transactions, right?

So you got that back to -- run rates were up, so you're incurring greater RVO obligation with those run rates, so that's a factor, but if you're dividing up per barrel, I understand Interesting you account for that, but yes, the RIN cost was higher.

Okay, yes. There's probably just something. I think the EPA dashboard is just like a sampling or something. It's not a complete dataset, so that might just be part of the issue there. Okay, that's helpful. That clarifies things a bit. I'll take the rest of my questions offline.

(Operator Instructions) The next question is from Jason Gabelman from TD Cowen.

I wanted to go back to the renewable diesel project and just clarify a couple of points that you've touched on during the call so far. So I understand you're not providing throughput guidance and it sounds like you may run under 8,000 barrels a day. I guess I'm wondering is that a function of not having the LCFS approval yet or is it a function of just other market dynamics going on? And what I'm trying to understand is if you were in a position where the asset was fully operational and everything was lined out, would you still be running under nameplate given market conditions?

Yes, I think it's a combination of both. So you've got -- obviously, you can look at the CBOT on soy to see that unbelievable [run up] during the quarter, right? So feedstocks have skyrocketed. Even when you're not using soy, everything trades off of soy, right? So it drags the whole complex up when you've got that kind of move. And that's in addition to the operational parameters that we've talked about already, but that's a big factor. And you don't have the additional margin opportunity of the LCFS pathways available to us right now, right? So there's no -- normally yes, if those were all in place for your question, we would run to capture those. They're not in place, so you're not going to run and not capture those yields, obviously, against the very, very high feedstock costs, so.

Got it. And my follow up also on the project is, can you discuss if you're utilizing the third-party pretreatment units yet? If not, when we should expect that to occur? And then maybe just touch on, I know you've mentioned in the past there are some unique logistical benefits to the renewable diesel project. If you're able to quantify any of those that are more difficult for the market to quantify themselves, that would be great.

Yes, I think the -- yes, we are, as of now, utilizing pretreated feeds. We've put our first barges through the initial pretreatment facility. As we've mentioned, I think, on earlier calls, we do intend to utilize multiple facilities, commissioning on the second 1 is about a month behind by our partner, so we're looking forward to that, but that's in hand and ready to roll on the feedstock plan for us. So we'll start to benefit from not just the base spreads between bean oil and the other feeds that we've described, but the spreads between that and the crude feeds of those same categories. So those economics will continue to be available to us now in this quarter and going forward. So that's certainly a big part of the plan as we've described the last few quarters. So that's now in place. And I think that it's going to be a big benefit as we continue to optimize the blends.

And then how much of those 2 pretreatment units, what is their capacity relative to the size of the 8,000 barrel a day facility that you have?

I don't want to speak for those producers. They have nameplate capacities that they're working towards and representing. We don't have the commercial operating experience with them yet to know that those are -- where those units will run. So our approach from a feedstock portfolio standpoint has been that we have the capacity available from a pretreatment standpoint to treat all of our feed at these run rates -- at the Phase I design run rate. So that's the premise. That's the approach. That's the strategy on the feedstock portfolio. We can't confirm for you at this time that those PTUs will run at those rates. We have no reason to believe they won't. But again, we're not going to -- can't commit to what they can achieve until we see them do it. But we have been pleased with the initial results. We're excited about continuing to work with them and I'm very positive in their progress at this point.

Got it. And then anything on the logistics side that you could comment on, have things been running there as expected, where you're seeing some benefits above what a generic renewable diesel plant would do?

I think the biggest benefit we have is optionality. We have the logistical optionality in mode. So we can take truck, rail, or barge. And we have really good optimization capability between feeds in terms of segmenting each family as required by EPA before we blend. So all that infrastructure is in place, and it really just gives us the optimization levers we need to pursue the lower-cost feeds, whichever category they arise in which is obviously not entirely predictable as 1 might guess. So that's the infrastructure that's in place and allows us to do that optimization. In terms of modeling that or benchmarking that, we'll look for public information that we could provide going forward on that, but there's nothing obvious right now. But I think the simple way to think about it is that infrastructure allows us to buy a better basis than we would otherwise achieve versus the [Board].

This concludes our question-and-answer session. I would now like to turn the conference over to Ben Cowart for closing remarks.

Thank you, operator, and thank you, everybody, for joining us on the call today. It's really been a landmark quarter for the company, definitely not happy with the market headwinds we faced and bottomed out on some of the spreads. It's really good looking ahead to see the third quarter bounce back like it's done. So we're very positive about that. We see a lot of good market conditions as we look to the end of the year. I'm really pleased with the delivery of this RD facility on plan and the way the company and the team has projected that work, deliver that work has been monumental and commendable to the efforts of our people. And so we're very proud of what has been accomplished there.

I want to talk about the systems that's been deployed. So as Doug mentioned, all of the third-party infrastructure, all the pipelines, all the connections, all the tankage, all the barging and the ships, and all the logistic assets, all have been deployed and tested in the second quarter, so that was a big undertaking. Our EH&S performance, the site had historic accomplishment from a safety environmental compliance in its history. So that's thanks to the team and to the organization to stay focused on what's most important, very proud of that.

The leadership, Doug coming in around our trade team's now in place, we've got the people, we're acquiring feedstocks, we're opening up new relationships every day so the market is very excited about our facility being online, so that's positive. Our working capital facilities that we've been able to establish with Macquarie across the conventional business and now in the second quarter the RD business that provides good working capital for the business. And then the fact we've pivoted again in the middle of all this work, we accelerated our Phase II with the pipeline system that we brought forward. We spent the capital early. That is really allowing us to move our pretreatment and all our advantage feedstocks up in front of our plan, so we're ahead of plan when it comes to that and it's a good thing. We didn't see the soybean prices accelerating like we did, but we're well prepared. We're right where we're supposed to be to just stay ahead of that curve.

I think what's most noteworthy, as I look at the business, is the fact we closed this transaction April 2022 (inaudible). We took on a monumental challenge to build RD plant and build it out quickly, safely, and deliver on that, which we've done. But we only had $100 million at close in cash. And we've had unbelievable amount of tailwinds from the conventional business from the time we closed. Now the second quarter doesn't count because we have a little takeaway. But when I look at the balance sheet, we're $200 million plus of capital that's been deployed into the Mobile refining asset. Between the conversion, the remaining working capital that we have in inventory now to run the business, and then to take and reduce our debt by $150 million through the conversion mainly of the bonds, that's a major shift on our balance sheet. We've been very focused on that. We look at now the value we've created around the asset compared to what we started with, I think we'll see as we get close to the opportunity to recapitalize our debt and see our RD margins start to really flow into the business. The refinery has served as a major platform, and it's gotten better. Quarter by quarter, month by month, our people have developed across the business.

So I'm very excited about the business. I believe we've got a lot now we can rest on when we look ahead. The work is done. We've delivered on what we said we needed to do. So we see this quarter as transition. It doesn't define how the business moves forward by any means. And I do believe that we can start talking about the future plans of the company and that's what we're looking forward to. So really appreciate everybody's time, appreciate the support to us and to the company, and we look forward to our call in the third quarter. Thank you.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.