Chris Carlson: Yes, this is Chris. Good question. So, I mean, we do currently have a company-wide focus on cost reductions along with SG&A expense. One thing you’ll note in Q1, you did see a 5% reduction in SG&A year-over-year. So, while I’ll say this is probably directionally where we will be, we are continuing to be very focused on reducing SG&A and cost in the business.
Sameer Joshi: Got it. Thanks for that. I’ll take other questions offline. Thanks and good luck.
Operator: Next question comes from Eric Stine from Craig-Hallum. Your line is now open.
Eric Stine: Good morning, everyone.
Ben Cowart: Good morning.
Eric Stine: Hey, so I’ve been jumping around on calls. I apologize if I missed this. But did you quantify your estimate of what whether it’s in Q1 or what it would have been in fiscal 2023 from an EBITDA perspective without the losses from renewable diesel?
Chris Carlson: Yes. So we take the loss, you’re asking without the losses of renewable diesel.
Eric Stine: Yes, without the losses what – I mean, what should we or – just curious if you quantified what the incremental EBITDA would be or what you would expect given this action you’re taking.
Chris Carlson: Yes. So we did a similar exercise, Eric, but mostly around the fuel gross margin approach. And what we did was we looked at the hydrocracker the last time it was in service. We took those yields and applied it to Q1, which provided the benefit and distillates, which would be your gas, diesel and jet. In addition, it provided the benefit in volumes from eliminating the yield loss that we experience when it’s not in service. And that gave us about a $40 million benefit on gross profit – fuel gross margin.
Eric Stine: Got it. And I would assume then you’re also taking out the elevated OpEx per barrel for the renewable diesel unit given that, I guess thinking about how this looks, maybe in fourth quarter, when the RD unit has been converted, direct OpEx per barrel should be dramatically less.
Chris Carlson: Yes. Your OpEx per barrel is going to be less, you’re going to have less variable expenses such as logistics and other items. So yes, you’re going to see some benefit across the board.
Eric Stine: Got it. And then as we think about this, obviously you had not brought on the full 14,000 barrels per day that you were planning. So we should think about this here. You’re roughly adding 8,000 barrels per day when all is said and done. Should we think – I was unclear. Should we think about kind of a similar mix of finished products? When up and running you also had some commentary about some upgrades to increase VTO output or just upgrade it. So maybe if you could just provide some details, that’d be great.
Chris Carlson: Yes. So what you’ll see if you go back on this hydrocracker, it was about a 40% to 50% conversion unit and one – and its shortage, its constraint was hydrogen and stripping ability. So once the finally get the hydrogen unit up and an additional stripper, then we’ll see significant upgrade in the hydrocracker itself and see a larger yield of diesel and less VGO, it’ll go to about a 60-plus percent conversion unit versus the 40% to 50% we get today.
Eric Stine: Okay. So I mean you’re – you see, you’re looking at, you’ll be at what low 70s barrel per day? I mean…
Ben Cowart: This is specifically hydrocracker, not the crude throughput we’ll hold crude running in the average 75,000 barrels a day when all up and running. That doesn’t change.
Eric Stine: Okay. Got it. And then last thing, just on the strategic initiatives that have been ongoing with BofA, I mean, I would assume there’s a component of the people that maybe you’ve been talking to that were more interested in the conventional refinery. Curious, what this move potentially does in the strategic alternatives or options that you discussed on the call? Does that encompass what you’ve already been doing or are you taking additional steps?
Doug Haugh: So, Eric, the pause and pivot certainly paints a good, much better picture on our financials as we work on these strategic alternatives. So it’s – I think everybody sees the current market for renewable diesel. So there’s no surprise there. I think it’s well received by any alternative party this kind of looking at the business at this point in this process. And really believe no dissension on this decision or anything there. So when you look at renewable opportunities, they’re more long-term as this process is unfolding. And then we also have the ability to demonstrate the true profitability of the asset just under this pivot strategy, taking advantage of the hydrocracker and the feedstocks that we control. So we’re really setting a kind of a base of cash flow that we’re running this process by. So it allows us time and allows us more optionality and broadens interest in the alternative process that we’re running.
Eric Stine: Okay. Thank you.
Operator: Our next question comes from Donovan Schafer from Northland Capital Markets. Your line is now open.
Donovan Schafer: Hey, guys, thanks for taking the questions. So the first question I want to ask is for running down the inventory levels for the RD operations. How should we think about or expect that to impact your cash position? So on the one hand, you’ll be monetizing what’s in inventory, and that generates cash without the need to turn around and then buy additional feedstock and replace it. But then on the other hand, I believe there is an inventory facility linked to this that would need to be paid down as well. So does everything just kind of net out or does this, do you end up coming out ahead or behind a little. Just what do you think the net impact on your cash position will be after running down that inventory?
Chris Carlson: Yes. Thanks. This, Chris, good question. Basically, the way we look at it is it’s going to be neutral because as you noted, we’ve got a financing arrangement with the inventory. So as we run that down and clear it, there’s not a lot of margin in it today, as noted. And then as we clear out of the financing arrangement, we’ll get a little bit of cash back on that. But when you offset it against the negative margin, I would view it as neutral.
Donovan Schafer: Okay. That’s helpful. And then with the – I think Ben responded to an earlier question about the hydrocracker unit saying, it’s a 40% to 50% conversion rate from the VGO coming off the primary distillation, converting that to diesel or refined products when it goes through the hydrocracker, and that can be increased to 60%, I believe you said, with additional hydrogen. So I guess, the question. So the question is, does this mean the plan is to proceed with the Phase 2 where I forget the name of the partner you have there, but that the additional hydrogen that was originally intended to be plumbed into everything to take the hydrocracker up to 14,000 – from 8,000 to 14,000 barrels, is that still going to happen? And then that available hydrogen ends up giving you this improvement on the hydrocracker, is that what’s going on?
