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

Good morning. My name is Theresa Chen. I'm one of the equities analyst here at Barclays covering refining and midstream. Our next presenting company is CVR Energy. CVR Energy is a petroleum refining and nitrogen-based fertilizer company. It has 2 [indiscernible] continent refinery strategically located near Cushing [indiscernible] with a combined capacity of 207,000 barrels per day. CVR Energy also operates 2 fertilizer manufacturing facilities serving the Southern Plains and Corn Belt. With that, it is my pleasure to welcome Dave Lamp, CEO; and Richard Roberts, Investor Relations.

Thank you, Theresa. Welcome, everyone. Thank you for participating, and thanks to Barclays for putting together this virtual conference. And we appreciate your interest in CVR Energy. We have here an eye tester of forward-looking statements. I won't cover much, but you know the market changes, and this is a statement that helps us with the FLS and others that protects us should the market change. From oil -- or from the CVR Energy's standpoint, we have really not changed our mission much at all. We're really aiming to be a top-tier North America petroleum refiner and nitrogen-based fertilizer company, and we really measure ourselves by safe, reliable operations, superior financial performance and profitable growth. Our values are really what we -- how we want to accomplish our mission, and they're very important to us, and core safety and environmental performance are integral to our business, and we've done a lot of steps to improve CVR's performance in this area. We won't say we're done yet. We have more to go, but we're well on track to be where we should be responsible -- safe responsible operation. From a company overview, Theresa mentioned, we have a Petroleum segment and a Fertilizer segment. We're in the Mid-Con, Group 3 exclusively. Our Wynnewood Refinery and our Coffeyville refinery are located in the rural areas of Kansas and Oklahoma. And have direct access to the Anadarko Basin and as well as the Permian Basin via basin pipeline. And Canadian crude via the Canadian pipelines coming down from Hardesty. The Fertilizer segment is 2 plants. One is -- and these are nitrogen-based fertilizers really serving the Corn Belt largely and industrial customers in those areas. One is located in Illinois -- excuse me, in Iowa. The other is in Coffeyville, Kansas, integral to our refinery operations. And have some synergy between the 2, particularly in pet coke supply. Our Illinois -- Iowa plant is fed by natural gasoline and -- or excuse me, natural gas and is well positioned from a truck market standpoint to feed the Corn Belt in Illinois, Iowa and Minnesota and Wisconsin. Looking at our strategic priorities, really, it's all around a safe operating, controlling costs and maintaining our balance sheet liquidity. We have really done -- taken a lot of steps with the virus that's come upon the United States and the rest of the world as really trying to preserve our balance sheet and liquidity is #1. We had -- we're fortunate to raise some capital early in the year right after the first of the year. And we did that largely because we saw some opportunities that -- from an M&A standpoint that we're fortunate to get it done before the virus really hit. And that's put us in a pretty strong balance sheet position. Our real focus is on leveraging our strategic location and using our proprietary gathering system to deliver high-quality and cost-efficient crudes to our refinery. Today, we are gathering approximately 124,000 barrels per day. That has -- that went as low as about 30,000 barrels per day during the early days of the pandemic, but has rebounded nicely since then. And we continue to grow that volume as time goes on. Believe it or not, there is still some drilling going on in the Anadarko Basin, although you hear there's really nothing. And there are some new wells coming on that we very much participate in. But our strategic location there is really around the quality of the crude that we can gather and how that compares to the domestic suite or the Cushing common stream and what our other competitors are forced to run without a gathering system. Of course, we're always looking to reduce our RIN exposure and continue to increase our blending within our system. And then are looking at renewable diesel, which I'll cover a little bit here later at Wynnewood to further offset RIN exposure from a company standpoint. And then in this environment, particularly with low cracks and high RIN prices, reducing lost opportunities is the name of the game and improving our capture rates is what we're all about. We have done a pretty good job of reducing our lost opportunities over time and continue to work to drive those down. From a Petroleum segment standpoint, again, we're located near Cushing and the STACK/SCOOP plays, which is the Anadarko Basin. We have 207,000 -- roughly 207,000 barrels of capacity across these 2 refineries. Our average complexity is around 11 or 10.8, around 11 average. And we're located in Pad 3 and -- excuse me, Pad 2, Group 3. From a marketing standpoint, we basically are connected to the -- we have 2 racks at each refinery, and we're connected to the Magellan system and the New Star system, and have the ability to market across any one of their terminals anywhere in that system. As far as rack volumes go, we're probably in the 20 -- 15% to 20% range. The rest is sent through the Magellan system through bulk customers and local racks. These assets are pretty high-quality assets in terms of the refining margin we experienced. The top left graph shows you margin versus many competitors. We typically rank either #1 or #2 or somewhere in that range. In terms of cost, which is the top right-hand side, we're in the middle of the pack, and we continue to drive those numbers down with -- the pandemic has given us new motivation to reduce those numbers even further. In terms of total throughput, you see the effects of the turnaround we had in Coffeyville in the -- as the pandemic started. Our timing for that was pretty perfect. Except for the pandemic, there was a very low margin. In fact, we missed the negative margin read time frame at the start of the turnaround. And the only negative was that we had to deal with the virus during the turnaround. So that did end up costing us a little bit more money on the turnaround. But we're very high-yield on distillate and very high-yield on gasoline and distillate overall. As far as the macro goes, we have some charts here that kind of show you the U.S. gasoline demand. While diesel has recovered largely back to similar numbers as before the pandemic, gasoline has not. The big real story here, though, is jet fuel demand and what that's done. The alternative for jet fuel is diesel, and that's made the diesel cracks collapse to almost equal to the gas cracks. As far as inventories go, gasoline has been drawn down, but diesel remains off the chart in terms of high inventories. In our markets, the Magellan side, the gasoline inventory is approaching the 5-year average, still above of last year's. And distillate is just slightly above where it historically was. Crack spreads have been challenging. And the way I like to talk about it now is that there really is very little crude differentials that anybody can benefit on from a price standpoint, there is from a quality standpoint, and that's where we differentiate ourselves. And also, the futures are really indicating a mild recovery from here going forward. The real story to me is, I was hoping that schools would open and that would be another tranche of increase. But largely, it looks like demand is really flatlining, on gasoline at least, maybe similar on diesel, although diesel is still at a historical average. It's jet fuel that tells the story. It's probably down 60%, 70% and kind of holding. And that really, with the inventory overhang and the low crack spreads and high RIN prices, that makes a really challenging environment. And we're really competing on our operating cost with the rest of the fleet. I don't see a lot to change that in the short term. Something's got to clear the inventory overhang. And what it's really have -- we've had announcements of about almost a little shy of 900,000 barrels of capacity that's going to be taken off or is off of refining -- refineries that have shut down or going to shut down in the future. That's probably not enough, probably needs to be another 1 million to go to really clean up this market. Assuming no dramatic increase in demand, which is hard to see with -- unless a vaccine comes into play that -- and that even that will take time. Or schools open or the states reopen in the populated parts of the country. Because of that, we've basically put a lot of the projects that we were looking at in terms of refining, which were all designed to improve capture rate. For the most part, they weren't capacity increases. But this was an isom at the -- addition of an isom at the Wynnewood refinery and the addition of a second isom and naphtha hydrotreater at the Coffeyville refinery on hold. And we still have those in our pocket, but what I see with the macro going forward, refining is probably not the place you want to put your money, except for sustaining capital basis. And that's where we come into play with renewable diesel. To us a little bit, this is an option that takes away crude processing capability, but on the other hand, can mitigate RINs fairly effectively. Renewable diesel earns 1.7 D4 RINs for every gallon produced. And if we're looking at 100 million gallons a year of production out of our Wynnewood hydrocracker, and that would earn us about 170 million RINs out of about our obligation of slightly over 300 million RINs a year. The conversion of the hydrocracker at Wynnewood is a very capital advantaged, around $1. We're estimating about $100 million to do that. Most of that is infrastructure around rail to be able to rail in the bean oil as well as rail out the diesel to California, which is some kind of valuable assets to us, assuming renewable diesel is short-lived. And in that, we could load diesel out and move it to higher-value markets pretty effectively out of Wynnewood. We really have 4 phases to this renewable diesel for us. One is the conversion of the Wynnewood hydrocracker. And then two would be transition to feedstocks with a lower carbon intensity. We're starting out with a strategy around recoup our investment early by capitalizing on the blenders credit, the blender's tax credit that is in place until the end of '22. And by starting this up and having it in service in full production by June of '21, we can capture and recoup virtually all our investment within that period just by the blender's credit, not to mention RINs or the low carbon fuel standard credits. The phase 2 would be to build a pretreater for feedstock, and this would allow us to branch out the feedstock options to inedible corn oil, animal fats, used cooking oil, all the rest of the ag-type materials that are available for that can give you varying degrees of carbon intensity. We would look at sizing that unit for both refineries as we have -- as you can see in Phase 4, we have a similar project that we could do at Coffeyville, which is even larger that -- because we have 2 hydrotreaters -- 2 large, high-pressure hydrotreaters we can do the same thing at Coffeyville, and we would look at sizing that pretreater to handle both. The Phase 3 of this would be to recoup some of the lost refining capacity should cracks improve. We can expand the distillate hydrotreater by adding a second reactor and recoup approximately 70% of the capacity lost by taking the hydrocracker for renewable diesel production. And as I mentioned, the Coffeyville has a similar type project. Both refineries are long hydrogen. We have hydrogen plants that we currently don't use that can be used to make renewable diesel. As you know, renewable diesel requires a lot of hydrogen, and both refineries have CCRs, continuous catalytic reformers, which produce a lot of excess hydrogen as well as the 2 steam methane reformers that allow us to make hydrogen on demand. So a many-year transition here to do this. And this does have an opportunity cost to it in the form of what you are losing on the refining side. But the way we're viewing it is, it's an option that allows us to -- when renewable diesel is profitable, RINs are profitable or high, we can mitigate ours and switch back and forth easily at both refineries with a simple catalyst change on the affected unit. We don't burn any bridges to go back to refining, and we can play it as an option pretty easily. As far as the economics go, I'd like to summarize renewable diesel as if you look at it from a raw material cost and the HOBO spread standpoint, you have a negative gross margin of approximately $1 to $1.50, depending on the HOBO spread and the operating cost. And you recoup all that back plus more with the blenders tax credit, low carbon fuel standard credits and RIN prices. And typically, today, that's running in the $3 range a gallon. So you end up with about $1 to $1.50 margin, depending on a lot of factors in there. We really have about a lot of work to do to get this done. It looks feasible to be able to have our plan up and running by the '20 -- by June of '21 without any problem. There are some long lead items that will take a little bit of time to procure and we may phase those in over a second catalyst change in that exchange catalyst on this fairly frequently. So it gives us the option to add the proper metallurgy over time. You can look at the sensitivities on that slide -- previous -- go back once and return again. The sensitivities too are quite big for pretreatment and the blender's credit. The blender's credit is one that does expire at the end of '22. But if you look at over the history of the RFS rule, the government has supported it in one form or another on a retroactive basis over the years, and I see no reason that won't continue. It will probably be at a lower level than $1. But even with that, it's a significant driver in the project. Okay. From capital expenditures and turnarounds, we're continuing to drive these numbers down. As I mentioned, our emphasis on capital is not in the refining side. It's in the renewable diesel, and that will continue for some period of time. We're driving our sustaining capital down below $100 million a year and turnarounds are up in the air. We do have another turnaround in Wynnewood that's planned for fall of '21. That's about probably an $80 million to $100 million turnaround, and we'll have a decision to make at that time, as most refiners will have, should the cracks not exist, how we will fund that turnaround. And that will be a watershed event of how exactly we handle that. We are talking about simplifying Wynnewood if we go renewable diesel in that we have access to condensates, a lot of condensates in the Anadarko Basin. And we've very successfully run those with a very little yield penalty. And we can simplify the refinery quite a bit by changing our schemes and just cat crack all the heavies off of those condensates and reduce our operating costs more and our sustaining capital and our turnaround costs even further.

[indiscernible] some questions.

Yes. So on fertilizer, let me go to that real quickly. Our fertilizer is nitrogen-based, as I mentioned. I won't go into a lot of detail here, but the general trend of nitrogen consumption in the United States and the world is up and to the right. And if you look at it in terms of the farmer standpoint, it's probably a fairly low-cost yield improver that they work to cut other costs first before they cut the fertilizer cost. And it does have a dramatic effect on the yield of corn, particularly. And with the 95 million acres of -- in corn production today and growing, and we think that this business is -- has a long-term future. It is a little oversupplied today just because of when it's a typical chemical -- I'll call it, a chemical cycle is about 6 to 8 years. It was overbuilt in '17 and still absorbing that capacity that's been overbuilt worldwide. But it has been benefited here lately by the low natural gas price. And it's really got a future in that -- and the farmers need this to really continue to increase their yield per acre. With that, Theresa, I think we're ready for some questions.

Theresa, we can't hear you.

Sorry. Great. Thank you, Dave. Maybe we can first talk about the renewable diesel side of things. Can you just remind us of where you are in the execution and development of your project, the first phase, as far as committing engineering goes? And how you're managing the execution risk related to that, given that this isn't really your traditional wheelhouse. And also, what it would take for you to get comfortable to greenlight the further phases of expansion.

Well, I think the one big parameter we have right now to get over is the election. Not that, that would change the decision, but it might influence it to some degree. But to beat the time frame we're at, we're buying, right now, long lead equipment and completing engineering. We've done a good month, 1.5-month study of what we believe the cost is, and we're still hovering around that $100 million for the initial phase. But taking a look at what happens with the election, I think if Democrats are successful at winning the presidency, you'll see more pressure for climate change and regulations and action that probably bodes well for renewable diesel. On the other side, if it's Republicans, I think it's probably less pronounced, but I don't know that they're going to fight it either because it's -- the train's left the station and people -- the electric expect something to be done. I think there is a scenario where if the Democrats take the Senate and the House and the presidency that, that would accelerate even quicker. And you'd see renewable diesel probably penetrate the market even faster. That said, we are marching forward, and permitting should not be an issue, although it's not -- we don't have the permits in hand yet, but that's the next order of progress here, long lead equipment and complete engineering and get the permits.

Got it. And when you view the supply and demand framework in the outer years, just on a state-by-state basis or the potential for Canada to adopt a federal mandate, what are your thoughts there? Do you have that assumed in your baseline expectations? Any color there?

Yes. Well, I think this is -- renewable diesel is going to be no different than refining. There's these big arps that open up, and guess what? They get filled. I don't think renewable diesel will be any different, and that's why we're treating it as an option. We're not -- we can jump in and out of the market as -- depending on what RIN prices are, depending on what the credits are selling for, and depending if there's a blender's tax credit. And depending on what refining cracks are also. If you look at historical type '18, '19 numbers, where we had an $18 average crack in the group 2-1-1 group 3 crack, the opportunity cost for RINs have to be very expensive and the blender's credit has to be $1 to even justify running renewable diesel. So our strategy, again, is to recover our capital within that first 1.5 years and treat it as an option from there out. And it takes about, as I mentioned -- I think I mentioned, 20 days to change catalyst, and all -- that's all the switching costs you really have to go back and forth from one to the other.

Okay. So low capital and pretty quick turnaround to do so.

Low capital pretty quick.