CVR Energy, Inc. (CVI) Earnings Call Transcript & Summary

Good morning, everybody. This is Gregg Brody from Bank of America. It's my pleasure to introduce Tracy Jackson, the CFO of CVR Energy. This fireside chat is going to focus on CVR Refining, the refining business within CVR Energy. I'm going to pass it over to Tracy, who's going to provide just sort of an overview of the state the company. And then I'm going to pick to Q&A as part of this fireside chat. Tracy, the mic is yours.

Thank you, Gregg. Good morning, everybody. Just want to start with reiteration of our focus continues to be on safe and reliable operations. We are all operating in a challenging crack environment, focused on cost reductions and ensuring that we are as efficient as possible with our capital and available cash. We've spent quite a bit of time evaluating our capital portfolio over the last couple of quarters and are preparing to announce with year-end results. The capital spending plan for 2021. I know what everyone is eager to ensure that we present that. But I'm not prepared today to deliver those numbers yet, I can say that they will be conservative. You can expect them to be within or below what we've been spending in the past, there won't be an upside surprise there. We are very comfortable and confident in our balance sheet right now. We have adequate cash available to us, and we're comfortable that, that liquidity will carry us through at least the end of next year, if not beyond, very comfortably, even if the challenging crack environment continues to persist. I think we've all begun to see the supply and demand portfolio for the -- at least the Continental U.S., balancing a bit. We're within single digits on demand destruction for both diesel and gasoline. And we're really just waiting for what hopefully will be advanced therapeutics and vaccinations to help open up the travel portfolio, which will bring back even stronger distillate and jet demand profile, which we really believe are the key to improving the trajectory of the cracks in the out months. We also -- and I know I'll probably get quite a few questions on M&A on today's call. We do remain focused on looking at diversifying our business. We're careful that we don't just say EBITDA diversification because we also are interested in geographic diversification. Ultimately, that will build the strength that we think we need in order to make sure that we weather these storms even better than we feel we're weathering the current one. With that, Gregg, I'll just turn it back to you, and we can walk through some questions.

That's a great introduction. And so you touched on having enough liquidity to manage through next year. At the very least. Could you just walk us through how much cash you think you need per quarter or just to run the business? And then at current strip, what do you expect our burn to be on a per month basis or a quarterly basis?

So I'll talk from a very macro will, and Richard will probably chime in with any details that he feels are relevant, and I encourage him to do that. When I think about adequate liquidity, and it's interesting, I think we're all having to go through a mental shift right now because prior to this pandemic, we could, as an industry, look back over time and say, "We really need to weather a period of 2 to 3 months of breakeven or negative gross margin." And I think this pandemic has proved that while that may have been a good historic theory to plan for cash available on hand, it's sort of broken that model because we're going on multiple months running here of sort of a breakeven crack environment. And I still think the fundamentals exist. So we will continuously ensure that we have cash available on hand to pay our quarterly -- or sorry, our semiannual dividend, not dividends, interest payments. And we'll also ensure that we continue to invest in the sustainable CapEx profile. So because one of our core values, our #1 core value is safe and reliable operations, we're simply not willing to give up that sustaining CapEx. We feel like it's safety and reliability focus that come out fall away even in a negative margin environment. Beyond that, we want to ensure that we have minimum cash to be able to pay. We have, I think everyone understands, the significant dependence on our gathered crude barrels. So we tend to keep an eye on what settling 1 month forward of those gathered crude barrels is to ensure that we can do that prompt settlement without any liquidity crunch that's driving us to draw on anything. We also tend to look at our normalized turnaround spend. So that -- and we do a large turnaround every 4 years at each facility, and we do a small turnaround every 4 years, but they alternate years between the 2 facilities. So if that's not complicated enough. We'll cover it later. So the sum total of all of that really doesn't fluctuate much, except for the lease crude payable, which is dependent, of course, on crude prices. I would say right now, that number is probably somewhere between [ $150 to $225 ]. It just depends on what crude is doing? Is it rising or falling? And how do we see that projection is going to look like over the next quarter. So it was a fairly long and complex question -- or answer to your question, but hopefully, gives everybody a full picture of how we think about what that available cash balance needs to be.

So on a monthly basis, you're saying at [ $150 to $225 ]?

Yes. Of cash balance, not cash generation. No, I'll take that. I'm 12 and say I need that annually.

No, I got it. You just to run the business, you need to have that there. So theoretically, if you generate cash, that would offset that number. Right?

Right. But I'm not on -- not every month.

Yes. And now the burn element is a function of the crack spread and what your capture rate is and just as operating cost efficiencies or inefficiencies. Could you -- what is -- based on strip today, what type of burn are you looking at on a monthly or quarterly basis?

I'll typically provide that on a monthly basis. I think you can look back and it's so early in the morning to get grouchy about RINS, but I'm going it's going to happen. Right now, I think we can say we're working in a breakeven environment at that $6, $7 margin on Group 3. Of course, when you take the OpEx of $4 out of that, then you're looking at a cash burn of whatever our throughput looks like on a monthly or quarterly basis. So we are -- that's 1 of the reasons we're very focused on our cash savings and our cash improvement initiative. So I think you've seen all year long, our operating cash expense per barrel falling. And we're continuing to focus on that, and we think it will be somewhere around $4 a barrel. That can move obviously based on how hard we're running and the utility impact of natural gas, which thankfully for us is not that big of a swing. So it's a difficult question to ask in this current -- or answer in this current environment, I think it's sufficient to say that with the cash balance that we ended the third quarter with, we're very comfortable that even in a breakeven margin environment, we have sufficient cash and liquidity to get all the way through the end of next year.

And Gregg, I think if you look at the third quarter, there's pretty good evidence of that. So we actually built cash on the balance sheet in a pretty terrible refining environment. Part of that was a working capital benefit to be fair, but even still ex-working capital, it would have been a very small cash draw. So hopefully, we're looking for a better environment next year than what we saw in the third quarter. But even if things do stay that challenged, I think we've shown that we can weather this without burning through a significant amount of cash.

And I think we're already starting to see that the margin environment next year will be better. We're seeing $13 -- $12, $13 cracks in the second and third quarter next year, which is more indicative of kind of that shoulder month and summer bump that we would like to see in every year.

So that's helpful. And so $12 to $13, if you take the $6-$7 breakeven plus $4, you're producing -- you have operating cash flow? Right?

Yes.

You said -- so the working capital benefit you had in the fourth quarter -- excuse me, third quarter, do you think that there's an opportunity to generate more cash from working capital? Or is that behind us?

There's -- I mean, every quarter, there's an opportunity. I don't see -- I'm trying to think about what we're doing from a gathered barrel perspective. And I think we articulated in the second quarter that they had largely come back online and that at the end of the third quarter, we were seeing those stabilized and could see some of that pulling back a bit through the end of the year. So with the volume side of the equation stated, it really is price dependent. And if we see crude prices rise through year-end, then of course, we'll have a working capital benefit from that. So based on everybody's forward view of what crude is going to do and what we think we're going to do on volumes. That's really our biggest swing in our working capital number.

Got it. And you touched on the outlook for crack spreads a bit and what needs to happen to recover. So I guess is -- so the -- you mentioned for 2Q and 3Q is showing some improvement next year. How do you see it improving even more from there? Is it just simply transportation picks up for jet fuel or for fine? Or what else are you looking at to get a sense of how things can improve?

Well, at a very high level, I think it's consumer confidence. It's people's willingness to once again, leave their houses and move about the country, whether it's on a plane or on a train, I feel like I'm in a Dr. Seuss novel now. And I don't know even if we have the advanced therapeutics and the vaccinations available. That's certainly going to take care of a swath of the population. But there's going to be people who are not confident about taking a vaccination right out of the gate. And so there's a portion that will stay locked up now. I think with maybe the presidential election determine sometime here in the next week or 2, finally. And we can start the transition process. It will depend on what happens with our international partners and trade. What happens with the tariff profiles. How the relationship moves forward with China. And all of those factors are going to weigh on 1 side or the other on -- I think there's opportunity still for things to improve in all of those respects, and we see things unlock a little bit more that gets our, really, transportation, fuel draw up higher than it has been.

And then, Gregg, too, I think the other part of the equation that is encouraging is on the supply side, right? So one of our favorite things of our CEO is at the best cure for low prices is low prices. And what you see in this market is that things just don't work down here. And that's why you've seen a number of foundry closures announced in the U.S., even more globally. And frankly, that's probably the key to a bigger recovery in the market is having more supply offline because, to Tracy's point, demand is sort of going to do what it's going to do based on what's happening in the world, and we can't really influence that. But as an industry, we can influence supply. And so I think the longer that things stay challenged, the more likely it is you see that some of that marginal capacity comes offline and get the market into balance that much quicker.

That leads perfectly into my next question, which is -- so clearly, producers have rained back utilization, but there's also been rationalization. Can you just kind of frame this for us? How much has occurred so far and how much more do you think will happen? And does CVR play a part in that at all?

I'm going to answer your last question first, no. I think we have very advantaged refineries in that. We have advantaged crude supply with low transportation cost to get our feedstock to us. And as well as a very efficient product distribution system that we're directly connected to, which again, drives low transportation cost to get our product out into market. And you couple all of that with our low operating expense per barrel, especially in just the independent group. But if you even compare us across the portfolio of all refining and marketing, where we're not -- it's not shabby to be at $4 a barrel of operating cost. We have the cost advantage in the group. And so we expect that further rationalization to come from elsewhere. I think we have about 3 million barrels globally that have been announced over the next 2 to 3 years. How much of that is domestic, 1 million.

About 1 million.

About 1 million. I think we'll see another 0.5 million to 750,000 come offline, maybe here in the U.S. that's certainly what we need. It's whether the management teams that are running those refineries can have the intellectual honesty to say we're not competitive. Which is hard, and I don't envy them because you're not only making that decision from a cost perspective, but the communities that those assets are in and the impact that, that's going to have, which is always weighs on all of us. So where we'll see more, when that will come and how quickly, is probably dependent on if the curves really improve the way that we're seeing the forwards look right now or not.

And that's -- you mentioned 0.5 million more to 750,000 in the U.S. is -- do you have a global number? How much more needs to rationalize?

Not really.

Maybe just moving on to capture rate. The fun part, using historical numbers to try to forecast the future. How do you think about your ability to source crudes today and the dynamics that you're considering with changing crude prices and how that may affect your capture rate relative to your historical rate?

Don't you love it when you ask a question, and then you don't get the answer that you want because I'm going to go totally off tangent and say, I don't think we worry about our crude procurement at all when it comes to our capture rate. The biggest driver of our capture rate right now is frankly, RINs and the fact that we have as much announced new capacity coming online for renewables over the next couple of years. And RINs continue to run-up and consume available, what tiny margin is available in inordinate percentage amounts, demonstrate that the law is not being applied and/or was not well written and something is broken and needs to be fixed. And I don't -- I'm not going to sit here and profess to have even the right answer or certainly, what should be fixed. But the fact that anybody and everybody can participate in the RINs market and drive it up and not just obligated parties is part of our challenge. The fact that the Tenth Circuit Court gave a completely erroneous opinion in our observation. And as we've appealed to the Supreme Court, obviously, we intend to continue to pursue some sort of more amenable because it's not just there is the new administration or not, but we will get some sort of resolution and clarity. But the largest element and component, which is a ridiculous statement in the refining business, the largest expense that we have in our margin affecting our capture rate is RINs.

We lost you there for just a little bit there, Tracy. So I think you were talking about the Tenth Circuit is completely erroneous. And kind of last ship from there until the last part where you just said a biggest part of our cost capture rate is RINs?

Well, you missed the same, the largely just more ramping about RINs and saying that we have to have some sort of correction of how the law is being administered and the decision profile that we've seen thus far because it should -- in the refining industry, we should not have an expense that's starting to rival our per barrel crude cost.

So just for perspective, as you speak about that. So RINs impacted 3Q. Can you quantify how much it impacted your capture rate? And has it gotten better or worse since then?

I think we said something in the script. It was 20-something percent.

It was 23%.

I'm sorry, 23% of your -- of the...

Of the benchmarks. Our realized margin as a percentage of the Group 3 2-1-1, and that's our capture rate. And if you think about what drives the capture rate, right? So you have a benchmark that is 50% gas and diesel. So obviously, you have some mix effect there, first of all, we actually produce. To the extent we're paying more or less for crude and WTI. That will be an impact to the extent we're producing premium fuels, like premium gasoline, that's a benefit to capture and you get your transportation costs in there and some other odds and ends, which are generally fairly small amounts. So the fact that RINs was literally almost 1/4 of the benchmark for us on a capture rate perspective is historically so far out of whack. And very untenable.

And I don't know, our capture rate was like 55% or something like that in the third quarter. So if you just take RINs and say 23% more than that, you're back in what is a more normal range in a low crack environment. But it's just inordinate. It's an inordinate burden that not only ourselves but many others are bearing.

So I know you're pursuing a diesel -- renewable diesel project. How does that help offset this? And what else do you think can help offset this RIN in [indiscernible] places?

Yes. So I think we covered in the third quarter also that our renewable obligation each year is around 300 to 320 million RINs. The renewable diesel project that will come online in July of next year will generate on an annual basis, about 170 million RINs. On top of that, we blend about 60 to 70 million RINs just in the natural course of business over the rack. So the renewable diesel will put a pretty significant dent in our overall obligation. And it is a factor in why we're pursuing building the facility at Wynnewood.

That's helpful. So just in terms of your cost structure, you've talked about how your costs are low at $4 per barrel. And is there a way to -- do you think -- how much could those come down further? How -- and then how should we think about how much of your costs are variable versus fixed?

Richard is going to correct me. But I think our variable run is somewhere between 25% and 30%, and our fix is around 70%. They can come down. We're not running at full capacity. So if we ran at full capacity and we didn't change our cost profile, then we're obviously going to get a per barrel number that's lower. They will go up a bit because of that variable component. But I think we could see the refinery managers would strangle me if they were in the room. I would like to see them achieve something sub $4. But I think our target is $4 is where we want you to be trying to run at, and we'll consider things that may move that on an ad hoc basis.

And then the renewable, just to come back to the renewable project, how much are you spending on that? And then how do you think about what that generates in terms of EBITDA or, I guess, offsetting the RIN exposure?

Okay. That's it. I love that. It sounds like an easy question, but it's not. So we intend to spend about $100 million. I think it's important to point out that within that $100 million, about $70 -- $65 million to $70 million is associated with the logistics asset to be able to get the soy oil to the facility, store it and then store the renewable diesel segregated from the existing diesel watt. The remaining $30 million is really just the conversion of new -- upgrading metallurgy, adding incremental connectivity to the hydrogen facility and other streams that will be going back and forth between the refinery and the renewable diesel facility. So it is a very efficient project in terms of return. If you take the logistics off the table if we already had that, we would only be spending $30 million really to be able to produce renewable diesel. And we're benefiting really, in large part, by already having a hydrogen plant on-site that we can use 100% of the capacity, or close to it, to generate that renewable diesel. That's one of the distinctive differences between our plant and the other plants that you've heard announced. How we think about the revenue generation right now is highly dependent on how much that soy oil is going to cost us to get it into the facility. So in general the margin, and we call it the Hobo spread, which I hate, but I'll buy-in because everybody is using it. But the heating oil bean, oil spread is a negative number. It's somewhere between $1 to $1.50 Richard is nodding his head, so I'm not too far off base. That $1 to $1.50 negative is acceptable to us because really all of the different government programs that give us an EBITDA profile from the generation of the RINs, which every time RINS go up, it generates really more revenue for the renewable plant now. And remember, every gallon is a gallon of renewable diesel generates 1.7 RINs. So it's an exponential effect for us. The blenders credit, which we know expires at the end of '22, and that's why we're eager to go online by July of next year. And then the opportunity to shift this renewable diesel out to California and capture that LCFS credit or sell it at the facility and build the LCFS credit value into the price that we're selling at either or and all of those improve the -- what was a negative margin on the actual crack of the product. The bottom line gives us a $3-ish benefit per barrel.

And do you -- when you report this, will you blend it into your capture rate? And effectively showed just an improved capture rate? Or will you break it out separately? Or you're not sure yet?

No, I know. I would love to say that it's not material to the overall profile, but given that refining has been 0 this year, it's going to be material. And more importantly, and I know nobody cares about accounting, but the segment rules really say, how does your chief operating decision-maker want to review the business. Bottom line is, Mr. Lamp wants to see all of that broken out. And so we will be showing a separate segment and my Chief Accounting Officer is going to kill me for declaring that here on this call. But we'll have a separate segment that you guys will see the full profile of what the renewable business is doing versus what the refining versus the fertilizer. Did we lose you?

Gregg, did we lose you?

Hi, Tracy, I'm back with you. You're missing me there. Just -- my phone hung up. So hopefully, I don't leave you hanging there too long. Maybe just -- that's really helpful. Maybe just with our remaining time, you're talking about M&A. So can you talk about, first, what your plans are with Delek? I know you've said this previously, but it's helpful for the room just to hear it. And then, how -- you indicated that geographic diversity was important. So can you maybe talk us about the opportunities out there that you're seeing? I'll leave it with that question.

Okay. Our Delek investment has been all over the board for us since we made it in February of this year, and we made that investment in February because we felt like they were undervalued, and they rose out of that initial investment in them. And then with the rest of the industry, we all plummeted. We've hung on to it. We're back in the money. We look at it as a source of cash, if necessary and an otherwise good investment in a peer company. I would like to say that we're not going to go to Delek and offer a significant premium to buy them out. We see that situation as more a merger of equals. And we invited conversation, and we are awaiting a response, and I'll leave it at that. And if and when something else more attractive comes up, we'll consider whether we continue to hold that position or not. We do continue to evaluate opportunities not only in our PADD, but also in PADD IV. No, I can't give you details and specifics. One would be a very similar type structure to what we have now, very nichey, with advantaged supply, ready access to markets. It would give us the geographic diversification we're looking for, but it also comes with an asset profile that would give us some revenue stream diversification as well. Another is quite a bit different and larger and would be a challenge. And so we will, and we are looking at something in our own PADD that diversifies our revenue profile, obviously, not a geographic diversification, but it does continue to aid in our ability to bring advantaged supply to the market and move our supply efficiently around our refineries. So I'm not going to really -- I know Dave loves to get into the details, but I'd like to follow the rules a little bit more. Well, maybe just -- I'll ask a follow-up.

Well, maybe just -- I'll ask a follow-up and perhaps you can answer it. If it doesn't follow the rules, I'll take it as -- I'll take your answer as you can't answer. So you're saying -- diversifying your stream a little bit. Are you basically talking about gas stations? Or is there something else that -- that you mean by that?

Well, I don't think that we want to get into running retail stations. I mean, it's such a low-margin environment outside of cigarettes and twinkies and gas. And it brings a whole host of litigation with it and complexity and compliance challenges. But I think if we could bring things that increase our ability to place our product from a wholesale perspective or improve our transportation profile and allow us to more efficiently, more cost effectively move supply to the refineries, we would consider those, and we are considering those.

So more logistics assets. I got it. I got you. So you have your own gathering system today. And would you consider selling that? And just remind us how much of that is your -- is moving, are you moving for third-party -- or excuse me, how would you think about the third-party valuation of that asset?

Well, we have generated -- we've taken those assets and outlined for them if we were in market moving for third parties, what would we be charging, and it generates an EBITDA profile that looks something along the lines of $65 million to $75 million. And so you can apply whatever multiple, I mean, I'm starting to question whether multiples even apply anymore. We have all these lovely historical multiples, but what's the right answer. We used to apply 10x, 11x, 12x on a logistics asset. Well, that was when we had tax advantages and a normal world, and we don't have that anymore. Frankly, there's capacity all over the place. So it's 10x the right way to value that say, average $70 million of EBITDA? I'll leave that up to you guys to decide. As to whether we would sell it, I think, never say never, right, in this industry, you never know. We're certainly not looking to sell it. It does allow us to be very cost efficient. One of our metrics we monitor quite closely is what is our cost per barrel or per mile of movement versus what we could do with a third party, and we are consistently below that, which also helps with our transportation cost advantage. So the short answer is no. We wouldn't really sell it. Could we? Yes. But because it's so tied to the supply to the refineries, it would be a difficult mental parting, I think, for our operations teams.

That's helpful. And then the last question I have for you is just, obviously, the fertilizer business is in a separate entity. What's your thoughts on that entity staying stand on overtime?

So I'm going to keep my CVI hat on and answer the question. We look at that business like we look at every other business and look at the valuation, and we think it's been significantly undervalued for quite some time. And if I was in a normal environment, I would have been encouraging our Board to consider whether CVR partners was something that we should be using our excess cash on the balance sheet to invest in. We're not in a normal environment, and it doesn't make sense right now to take that excess cash and deploy it in that manner. And so we'll continue to monitor you. We've since done a reverse split to get them going to put my partners hat back on. So we put -- we've done a reverse split to reattain compliance with the New York Stock Exchange listing. We -- I think everybody is aware, we have received the deficiency notice because we were trading consistently $1 per unit on a 30 day average. And we had until January 1 to cure in some manner, and we ultimately determine that reverse split was going to be the most efficient way to achieve that. So since we've done that, which we did the week of Thanksgiving, it's traded up out of that. And perhaps, we've broken the model, the stigma or whatever was dragging it down. We've also seen improved pricing since that happened. And so it could be that as well. So what was a pretty attractive investment in an undervalued asset is dwindling away in an environment that I still don't want to deploy my excess cash. So it's a wait and see right now. That's how I think about it.

Got it. I do have one question here from somebody relating to that segment. The question is with record corn and soybean production over the past few years, we have seen a persistent oversupply of nitrogen fertilizer causing producers like your subsidiary to lose money. What is your outlook on any improvement in fertilizer margins and profitability? This is an investor's question.

I think those are great questions. I'm not sure that I completely agree with the conclusion that, that is -- that we've had record production over the last several years. I think this year is a good example where the USDA grossly missed what the production profile would look like. And we've drawn through reserves pretty significantly. And we -- as a result of that, are expecting a very healthy planting season in the spring, the coming spring, which will draw on those nitrogen products. We've also had the impacts of the European tariffs, which have driven imports into the country and have weighed on the overall abundance of supply and thus pricing. And now we have some of our competitors and peers in the industry applying pricing dynamics and methodologies to try and keep those imports out of the market. So I think there's a lot more complexity to what has been weighing on this than simply we've overproduced. I believe that the increase in capacity that we saw come online in the [ 16, 17 ] range, had been healthily absorbed by the farming community. And I don't know that the dynamics that we've been facing are quite that straightforward. But I would invite them to join the fireside chat for partners later today, and we can dig into all of that more.

Well, I figured that the question was asked, so I just gave this person the floor, but I would encourage that person as well to listen into the separate fireside. Look, Tracy, we've overrun our time, and I appreciate you making time for this conference and participating. And just in general, just if -- hopefully, next year, we'll see you in person. And normally, I would ask for a round of a applause, but we can't do that at this time to say thank you. And If you have any closing comments, please say them. Otherwise, have a great day.

No. Thank you very much. Thank you for having us, and we appreciate the invite, and we look forward to seeing you in person someday.

Same here. Take care and thanks again.

Bye-bye.