CVR Partners, LP (UAN) Earnings Call Transcript & Summary

Good afternoon. I'm Roger Spitz, and I cover high-yield chemicals and paper and packaging sectors at Bank of America and have the pleasure of this afternoon of hosting a fireside chat with CVR Partners', Executive Vice President and Chief Financial Officer, Tracy Jackson; and Richard Roberts, Senior Manager of Financial Planning and Analysis and Investor Relations of both CVR Partners and CVR Energy.

The current fireside chat will focus on CVR Partners. Stacy and Richard had kindly agreed to do a separate fireside chat with high-yield energy analyst, Gregg Brody this morning. So this will just be on the fertilizer business for the next half hour. As you'll see in the conference portal, there are some slides that will mainly serve as background or unless Tracy or Richard need to refer to it. But we are jumping straight into Q&A. As such, if you want to have questions, if you have questions to be asked, please type them into the conference portal, where I'll see them and be able to ask the questions. Other than that, though, I will start with some questions while we wait for investor questions. Starting with 2020 CapEx was given as -- $18 million to $21 million was the guidance. Can you speak to how we should think about 2021 CapEx? And what is maintenance CapEx, please?

Sure. I think it's fair to say that the 2020 CapEx numbers will come in, in the range with no surprises there. The 2021 numbers are prepared, and we will review a final time with our Board of Directors later this month and get approval. So we're not sharing those numbers now specifically with anyone, but they will not be out of the line with what you would be expecting, given our historic CapEx ranges.

Got it. How about a maintenance CapEx number?

Yes. Well we have those numbers, maintenance cap in '18 was -- 2018 was $16 million and in 2019, was $18 million. And we've reduced our range, I think, in the third quarter to say we were in the $13 million to $15 million range. And we'll be right around in that same bid teams for 2021.

Okay. So ongoing CapEx and maintenance CapEx are not dissimilar. And we have -- our first question is how do you plan to deal with your capital structure?

Well, so capital structure is predominantly focused on what we're going to do with that debt tower that's maturing in 2023. We began evaluating the potential to call that debt tower back in 2018 and have continued to look at it. My recommendation was to do this last year. And then the call premium, again, sell again this June. The Board at the time wanted to wait until 2021 -- or 2020 for the potential of an improved rate profile. And then the world fell apart on us. And that did not become available at that call drop. So now I think we are looking for some stabilization. The rates have been kind of all over the board. And I don't want to be out in market with that kind of volatility. So we'll wait now until the premium falls away completely, and we can call at par in June of next year. That way, we're not looking at an associated payback period for that call premium and hopefully there will be an improved rate structure available to us because really the benefit of an early refi is trying to capture and improve debt service profile. It really is the swing between us being able to pay a distribution or not pay a distribution. So we're focused on reducing that debt service cost and that's going to come in the form of a reduction in the overall rate structure.

Okay. So we can expect once you go to the par drop in June 2021 is when you'll start thinking about refinancing those bonds?

Yes. Well, I'll be thinking about it all the way up to that point and watching the market so that's ready on that day or after that date.

Right. Right. Right. It was turn a phrase, surely. We're all thinking about it. Going back to some of your operations. Starting with East Dubuque and this really gets to -- I want to chat with some of the turnarounds. How often does East Dubuque undergo a planned turnaround and what is the typical cost? And when is the next scheduled turnaround at East Dubuque?

So we typically -- and within a period of not typical. So I'll speak from a typical perspective and then what is done. We typically do a turnaround each year, alternating between the plants. And those range somewhere between 6 and 8 -- $6 million, $7 million, $8 million, maybe a little bit more depending on what equipment is in there. But sub-10, for sure. We're usually down for less than a month in any given turnaround. The last one, we were scheduled to do was the Coffeyville turnaround this fall, which we deferred to next year. And we really just did that out of an abundance of caution because you all understand that when you do a turnaround, you bring a number of outside parties on-site and influx of people, and that was just not feasible under the social distancing requirements that we had. So we felt like with the opportunity to defer it, we would take that opportunity and it preserves cash for us. So as of right now, we'll look to do a Coffeyville turnaround next year. And then we'll look to do an East Dubuque turnaround in 2022. So will be a little bit longer cycle for East Dubuque than it has been in the past. And there are certainly opportunities that present itself for various reasons to do maintenance capital you would typically do in a turnaround that will do as necessary if there's any risk indicators that say we need to do that. But otherwise, that's our go-forward plan. So in a normal world, we'll be spending $7 million to $8 million a year. We'll be doing a turnaround every single year. It will be very ratable. It will rotate back and forth between the plants. And we've just been trying to roll with the punches, given the current environment.

Got it. And that turnaround cost of $6 million to $8 million, is that the cost of the turnaround, or does that include any lost EBITDA or [ due ] stages so that you try not to have a material EBITDA impact during turnaround?

So we do try and build inventory going into a turnaround so that we don't have an EBITDA impact. There's certainly the potential to have that if it goes longer or the market spikes or there's a run on products while we're down, but we do what we can to minimize and store product into a turnaround to defer or remove some of that impact. The $6 million, $7 million, $8 million does not include any lost profit opportunities that may result from a turnaround.

Okay. And do you capitalize and amortize or is this what is going through the direct operating expenses, so you expense them?

We expense as if.

Expense as incurred.

Yes.

Got it. Okay. And then another question that's come up is on UAN pricing. With -- what is your expectation for UAN pricing to improve in 2021?

We've actually already begun to see some of that pricing improve. We have priced a large portion of our sales through the end of the year other than what we're doing on a spot basis. But we do see some of the early contracts that our peers are entering into and that we are entering into being in the $20 a ton more than what we're at now. So it certainly looks like NOLA is seeing a pricing improvement, we would expect to follow that.

Got it. And another question is, can you help us understand the demand dynamic for UAN, especially that Trinidad-based UAN facilities have been off-line for a few months now.

Yes. So one of the things that we benefit from up in East Dubuque is that it is a long, long way for somebody to try and import and take that product up river and that's why you see a pricing benefit versus East Dubuque and Coffeyville. Coffeyville was a little bit more exposed to the NOLA injection point where most of those imports come in, but we still have an advantage if nothing but for transportation, but it's usually wider than that. One of the things I think that's been compressing prices this year has been just strategic pricing decisions by the peer group. I mean we are very microscopic in comparison to some of the peers, and they really kind of set market that we participate in. And their -- some of the strategies we've observed is that they're holding their pricing low to discourage any imports from creeping into the market. So I don't know that Trinidad being down for the last several months has really had as much of an impact as those peer companies making pricing decisions for the market as a whole.

Thank you. And here is another question. Can you tell us the EBITDA generating capacity of East Dubuque and Coffeyville facilities? I think they want to know how the EBITDA breaks down between the 2 facilities.

We do not disclose at that level of detail.

Got it. In terms of direct operating expenses, if you break out the turnaround cost that we just spoke about, the $6 million to $8 million, what is the annual -- a typical annual direct operating expense recognizing things like, obviously, energy and utility costs are difficult to estimate.

I'm going to let Richard answer this question because he was just doing a whole bunch of analysis. He's saying that it's in hearing from me.

It is. So if you look back at other components to our operating costs every quarter that gets pretty difficult to model as inventory impacts. So unlike we're continually producing and selling the product at about the same time. In the fertilizer business, it's much more seasonal and lumpy. So we could be producing a ton of product in 1 quarter and not selling it until the next quarter. And so when we sell the product is when we actually recognize the cost to produce it. And so those direct operating expenses can fluctuate between quarters and not be representative of production, if that makes sense. And so if you listen to our conference calls, we'll tell you what OpEx was for the quarter, and then we'll also tell you what it was, excluding inventory and turnaround impacts to kind of give you a normalized sort of underlying DOE. And that is generally about $40 million a quarter plus or minus a couple of million bucks, and it's a pretty consistent range.

Okay. And so your -- as you build and use and consume or build inventory, that is actually moved through direct operating expense then?

Yes. As we build inventory -- the easiest way to think about it is, as we build inventory, costs that would have been running through the income statement are really a component of the build-in inventory. They -- in order to have matching because you don't -- you're building inventory, you don't have a revenue profile associated with that ton, you put that on the balance sheet. So it's not until we actually sell and draw inventory down that the associated cost to produce that inventory run through the income statement. So production could have been in the prior quarter or it could have been in the current quarter for what's running through the income statement in any given quarter.

Got it. Okay. We have another question, is the strategic importance to CVR partners to the parent and opportunity for consolidation in the nitrogen fertilizer space?

Well, we're much more likely to have somebody buy us than we are to go out and buy incremental assets or another entity. And we would certainly entertain that. But I think that CVR Partners strategic benefit to Energy. CVR Energy has certainly been proven this year when the refining segment has struggled to have positive cash flow or EBITDA generation in the positive range. And all of a sudden, fertilizer is 100% of their EBITDA profile. So I think their benefit of the diversification achieved has been highlighted this year.

Yes. One question comes up since potentially doing a stock -- an all stock transaction, it can get complicated in the bid-ask spread is, would you contemplate a deal that would be a stock swap? Or such a transaction structure would not necessarily work for you?

Well, because the ownership interest is held by Energy and if Energy sold its interest they would be looking to get out of the fertilizer business. You get into the relative value question that is fairly complicated to answer and define. I don't know that, that's something that we would necessarily be interested in. But we certainly would have the conversation and see where they were coming from and go from there.

Got it. Another question is what is Coffeyville's exposure to the natural gas prices?

Well, Coffeyville's main supply is pet coke. And while it does use natural gas in the production process, it's not a major driver of costs. So I don't have a per ton basis of natural gas for -- it's pretty small. Their largest component is going to be the pet coke cost.

Got it. So the natural gas at Coffeyville, I assume, is not a feedstock, it is simply to turn pumps and things like that?

Yes, it's a fuel.

It's a fuel. Another question coming in is, does implementation of potential renewable project that Coffeyville impact the fertilizer business, specifically, the Coffeyville plant gets pet coke from the refinery, so will the supply be impacted with conversion to renewables?

Well, right now, fertilizer -- Coffeyville fertilizer gets less than 40% of its supply from Coffeyville refining. And so it may impact it by a percentage, but it's not going to be a material component of their supply portfolio. They have current suppliers that are all across the Mid Corn and delivered via river and land. And so there's -- they have good supply diversification and a fairly low dependence on Coffeyville refinery at this point.

And then just to be clear, too, Roger here, if we did a renewable diesel project at Coffeyville, it would be similar to what we're doing at Wynnewood. So it wouldn't be a total conversion of the refinery. It would be taking select units and converting them to renewable diesel, but the rest of the refinery would still be in traditional hydrocarbon processing operation.

Got it. Another question. Could the Coffeyville plant be converted from utilizing pet coke to using coal?

That is something that I believe has been looked at in the past, but it is not cost-effective and it's not something that we're looking at right now. A more common question is can it be converted to natural gas. And we were looking at, can we convert one of the gasification facilities to a natural gas feed instead of a pet coke feed, and that made sense when you were looking at natural gas down in the $2 or below range but with natural gas running up here into the third quarter through, it doesn't really make economic sense at this point.

Which begs the question if you're willing and able to answer it is -- and I guess, it depends on pet coke costs and natural gas costs, but is -- Coffeyville or East Dubuque, which is the lower cost facility to make like fertilizer? And again, I recognize it depends on that ratio. Or maybe the better question is at what natural gas price are you sort of breakeven?

$3 a ton. So if natural gas is $3 for the production of a ton, then we're breakeven. So there was a point in time this year where it made more sense to produce at East Dubuque. And there was a point in time where it was more cost effective to produce at Coffeyville, but both are fully supplying markets that keep them at as high a capacity as we can run as possible. So while they may have a cost advantage or disadvantage, we're going to keep running the facilities at capacity or as close to as possible.

Just to make sure I understand, and you said producing natural gas at $3 a ton, did you -- I thought you didn't mean $3 a million BTU was breakeven. You meant a ton of UAN?

A ton of ammonia.

Of ammonia?

Yes. $3 cost associated with natural gas is a breakeven for my pet coke cost at Coffeyville. So you have to take that MMBTU cost and convert it and there's a lot of factors in between getting to that $3 per ton cost burden.

Okay. Let's see, some other questions coming in. What is the output of pet coke prices -- what is the outlook of pet coke prices? And how do you plan to hedge against pet coke volatility?

Well, so pet coke has continued to become more and more scarce as the Mid Corn refiners all move to as light a slate as they possibly can. But the price sensitivity to that is relatively inelastic because pet coke is a byproduct as a refining process. And it's really something that the refiners are trying to figure out how to get rid of. And so they'll price it to be able to move it. And they certainly know that we need it and can take advantage of that. But our risk management has really been on diversification of our supply options. Worse comes to worse, the largest coke production locations right now are along the Gulf Coast. We could rail it up. There is feasibility in that. But the vast majority of coke that's produced along the Gulf just gets put on barges and ships and sent overseas. So that would increase the cost profile, but I don't see that as a need right now because there's still sufficient coke -- pet coke production at the refineries in and around us in the Mid Corn.

You have to keep in mind, too, when you think about production slice lightening, there's a finite level to which refineries can do that. Refiners are geared to run a certain dye of crude. And so refineries that are built to process a certain amount of heavy crude can't just completely stop doing that without significantly cutting their rates. So I think whatever level providers have been able to get down to on light crude is probably about the upper end, just given the pricing dynamics. So we wouldn't expect a material shift from here. I don't think it could lighten up very much more.

Got it. So some questions have come in going back to the $3 a ton ammonia. And again, it wasn't -- I'm not sure I quoted either, it's not $3 a million BTU, it's $3 a ton? Or I guess the question is -- and your answer was we need to do a little more work to figure out what is the natural gas price. But maybe you could state again where there's a -- what is the breakeven price or how to think about the breakeven price of natural gas pricing to figure out where Coffeyville is lower cost than East Dubuque.

So Richard's got me back on track and said it's $3 an MCF.

An MCF, okay.

Yes.

An MCF is reasonably close to million BTU.

Right.

So just to be clear, if $3 is, I think it is -- I think it's only less than 10% off. If -- for natural gas prices below $3 an MCF, East Dubuque produces ammonia at a lower cost than Coffeyville does, all else being equal?

Correct.

Okay. Perfect. Perfect. Okay. Looking at the question I had on SG&A, for the years 2017, '18 and '19, SG&A on the books was around $25 million each year. 2020 looks like may come in at roughly $20 million. Was there some onetime positive $5 million advantage in 2020, or is 2020 the new annual run rate for SG&A?

I wouldn't necessarily take 2020 as the new annual run rate. There's a couple of factors at play, one of which is you'll recall that we had falling unit prices throughout the year until just tier post split. And as a result of that, any stock-based compensation or unit-based compensation would have been generating benefits, unfortunately, to the income statement in terms of estimated payout rates. The other impact that we had is a reduction in force, which didn't impact the fertilizer segment materially, but they did have individuals who were let go. And then we -- at the beginning of this year, we reassessed our allocation methodology and our cost allocation to partners to ensure that given the changes in the business profiles on both sides, that we still have the right allocation, and that led to a small reduction in the overall total of SG&A that's allocated down to the partners. So there have been some long-term changes, but there's been quite a few, I don't know, episodic 2020 impact that I don't think will be sustaining.

Got it. I don't know if you have this offhand, but can you say how many tons of pet coke are required to make a ton of UAN or if you'd rather on an ammonia basis, whatever you have it on hand?

Richard gave me this answer. I didn't know it. It's roughly half a ton of pet coke to a ton of ammonia.

Perfect. Another question from the line is UAN has a buyback authorization in place but isn't currently paying a distribution. How do you justify buying back shares if you can't pay a distribution? And how much capacity do you feel you have core buyback?

So we had that authorization. I think we got that in the second quarter of this year. And we've executed against that in the second quarter and then temporarily suspended it. I would say that the rationale that behind the scenes with Mark and I is, in 2019, we paid very healthy distributions coming out of the year and really saw very little benefit in terms of overall EV or value in the stock. In fact, we continue to slide out of last year down into the sub dollar unit range, put us in the deficiency position we had to cure last week. And so when we're looking at the deployment of cash, we feel like a repurchase at least has -- gives us the opportunity to share the returns that we do have with fewer unitholders coupled with, hopefully, a reduction in our debt service cost, creates an opportunity in the future where fewer will benefit more.

Got it. Actually, the time line went by very, very quickly. I think it's been very interesting discussion. Tracy and Richard, thank you very much for chatting with us for the past half hour. And also thank you for doing investor one-on-ones. Very much appreciated. Thank you very much.

Absolutely. Thank you.

Thanks.

Bye.

Bye. Bye.