Greetings, and welcome to the CVR Energy First Quarter 2024 Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Richard Roberts, Vice President of FP&A and Investor Relations. Thank you, sir. You may begin.

Thank you, Christine. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy First Quarter 2024 Earnings Call. With me today are Dave Lamp, our Chief Executive Officer; Dane Neumann, our Chief Financial Officer; and other members of management. Prior to discussing our 2024 first quarter results, let me remind you that this conference call may contain forward-looking statements as that term is defined under federal securities laws. For this purpose, any statements made during this call that are not statements of historical facts may be deemed to be forward-looking statements. You are cautioned that these statements may be affected by important factors set forth in our filings with the Securities and Exchange Commission and in our latest earnings release. As a result, actual operations or results may differ materially from the results discussed in the forward-looking statements. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise, except to the extent required by law. This call also includes various non-GAAP financial measures. The disclosures related to such non-GAAP measures, including reconciliations of the most directly comparable GAAP financial measures, are included in our 2024 first quarter earnings release that we filed with the SEC in the Form 10-Q for the period and will be discussed during the call. With that said, I'll turn the call over to Dave.

Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. Before I discuss our results for the quarter, I want to address an incident at the Wynnewood refinery that occurred over the weekend, early Sunday morning, during severe weather in the area. The Wynnewood refinery experienced a fire that was later extinguished later that morning. No employees or contractors were injured and we are in the beginning of the process of restarting portions of the refinery. We are still assessing the extent of the damage, and we expect to provide additional details when they're available. Turning to our results. Yesterday, we reported a first quarter consolidated net income of $90 million and earnings per share of $0.81, EBITDA was $203 million. Our solid results for the quarter were driven by continued declines in the prices of RINs and increased crude oil and refined product prices in the quarter, offset by lower crack spreads and fertilizer prices were relative to the prior period. We are pleased to announce that our Board of Directors authorized the first quarter regular dividend of $0.50 per share which will be paid on May 20 to shareholders of record at the close of the market on May 13. Our annualized dividend yield of approximately 6% yesterday, based on yesterday's closing price, remains best-in-class among the independent refineries. In our Petroleum segment, combined total throughput for the first quarter of 2024 was approximately 196,000 barrels per day and late product yield was 101% on crude oil processed. During the quarter, we completed the planned turnaround at the Wynnewood refinery. We currently do not have any additional turnarounds planned until Coffeyville's turnaround on a crude unit cat cracker and alky and other associated units currently scheduled for the spring of 2024, '25. Benchmark cracks…

Thank you, Dave, and good afternoon, everyone. For the first quarter of 2024, our consolidated net income was $90 million, earnings per share was $0.81 and EBITDA was $203 million. Our first quarter results include a reduction to quarterly RINs expense due to a mark-to-market impact on our estimated outstanding RFS obligation of $91 million, a favorable inventory valuation impact of $37 million and unrealized derivative losses of $24 million. Excluding the above-mentioned items, adjusted EBITDA for the quarter was $99 million and adjusted earnings per share was $0.04. Adjusted EBITDA in the Petroleum segment was $67 million for the first quarter, with the decline from the prior year period, primarily driven by lower product cracks in Group 3. Our first quarter realized margin adjusted for inventory valuation, unrealized derivative losses and RIN mark-to-market impacts was $10.46 per barrel, representing a 54% capture rate on the Group 3 2-1-1 benchmark. RINs expense for the quarter, excluding the mark-to-market impact was $45 million or $2.52 per barrel, which negatively impacted our capture rate for the quarter by approximately 13%. The estimated accrued RFS obligation on the balance sheet was $294 million at March 31, representing 449 million RINs mark-to-market at an average price of $0.66. As a reminder, our estimated outstanding RIN obligation excludes the impact of any small refinery exemptions. Direct operating expenses in the Petroleum segment were $5.78 per barrel for the first quarter compared to $5.90 per barrel in the first quarter of 2023. The decrease in direct operating expenses was primarily due to lower natural gas and electricity prices. On a per barrel basis, our direct operating expenses were elevated in the first quarter of 2024 and the prior year period due to lower throughput rates as a result of planned turnarounds. Adjusted EBITDA in the Fertilizer…

Thank you, Dane. In summary, market conditions were challenging for much of the first quarter, particularly in the Petroleum segment as refined product inventories were elevated coming into 2024 and distillate demand has been weak with a warm winter and depressed industrial activity. We would characterize current crack spreads as just above mid-cycles. Starting with refining, elevated maintenance activity and unplanned downtime in the United States over the past few months helped clean up inventories, with gasoline and diesel inventories, both near or below 5-year averages. We believe there's additional maintenance work yet to be completed in the United States, Europe and Asia, and the impacts to global refining supply from recent drone attacks on the Russian refineries remains a wildcard. We also continue to monitor the start-up of new global refining capacity expected this year, which could offset some of the supply impacts just discussed. On demand side of the equation, gasoline demand in the U.S. remained steady and is trending above the 5-year average levels recently. While distillate demand remains soft. Looking more specifically at the Mid-Con, refined product demand in Group 3 has remained steady although inventory levels are elevated relative to the U.S. as a whole. As a result, the basis in the Group 3 is unusually wide for gasoline and we have been increasing our fuel by rail shipments to the West through our new transload facility at Coffeyville. The Brent-TI differential has averaged nearly $5 per barrel so far this year, supported by crude oil export volumes averaging over 4 million barrels a day. With crude prices in the $85 per barrel range, we expect continued strength in shale oil production volumes which should be supportive of our crude oil gathering business. For the first quarter, our crude oil gathering volumes were approximately 130,000…

[Operator Instructions] Our first question comes from the line of Manav Gupta with UBS.

You are considered a good and safe operator, and I understand you're still evaluating what happened over the weekend, but help us understand a little bit what is it? A weather-related event, exactly what went wrong over the weekend which caused some of the issues that you're seeing?

Well, we don't know exactly all the facts yet Manav, but it appears like we got hit by lightning in one of our process areas. And that lightning caused the impending fire and then that spread a little bit as it got hot. I think our response was excellent to it from a community standpoint, our employee's standpoint and contractor standpoint. But it's an unfortunate event that we're sometimes exposed to. If you recall, the town of Sulphur, which is probably, I don't know, 15 miles from us experienced a very bad tornado. That storms were really bad that night, and lightning was flying all over the place, and we think we took a direct hit, but you never can be sure as it happens so fast.

Right. So there's literally nothing you would have done about it, right? So just was trying to make sure. And my second question is looks like your PTU is now going to be up and running -- is running at your RD facility. Help us understand how -- what are you looking to transform from refined soybean oil to unrefined soybean oil? Are you looking to do some tallow and stuff? And do you think that does make a material difference to your renewable diesel profitability?

Well, there's no doubt that we've been catalyst starved with the unit without a PTU. We've had pretty short runs and poor yields, I'll call it, on actual renewable diesel. We're very encouraged with the -- even buying treated feed or refined deodorized and degummed feed but still had a lot of impurities in it in the forms of metals and phosphorus and other things. And the results of the pretreater looked really good at this point. And we're starting this run with the pretreater up. And the catalyst performance is already looking very good yields of 90-plus percent on renewable diesel, and much less byproducts that we had seen before that. So I'm really optimistic that we'll pick up not only ability to run untreated corn oil and soybean oil, but maybe some other options for some other things. But right now, we're really focused on the corn oil as a substitute for the soybean oil. And we think that the margin on that right now is probably in the $0.80 range per gallon on a pretreated basis. So if we look at the first quarter, we ended -- we still -- we had a margin of about $0.65 a gallon, which if we could have run more barrels, we would have probably shown a profit on that unit. As it is, we were just kind of breakeven.

Our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt.

I wanted to follow up on your comments regarding I think you mentioned something about railing gasoline to the West Coast. So I just wanted to confirm that, that you are railing gasoline to California and capitalizing on the higher margins in that space? And also just curious, can you make that carb spec? Or is it a blended spec? And what kind of volumes are we talking about here?

Sure. As I mentioned, I said to the West, not necessarily to California. But no, we have -- we put in a transloading facility ahead of third party put it in, and we're underwriting it with tariffs. But our plan is to be able to load up to 120,000 barrels per month and that's our capability of the transloader. But we'll go probably wherever the margins are the best. As far as making carb, we really haven't looked at that much, although I'm probably pretty sure we could make some of it to some degree if we had the segregated tankage. But we haven't gone that far yet. If California continues to get shorter and shorter, it might be an attractive move. But the arb is open to other areas such as a Grand Junction even Denver occasionally and other places like Salt Lake City and Phoenix on occasion. So there's where we're focused mostly.

Is there a good rule of thumb for the rail costs associated with that, like maybe $0.30 or $0.40 a barrel -- or sorry, a gallon?

Well, normally, any time you move anything by rail, it's $6 to $8 per barrel. So that's a good rule of thumb. It depends on how far you go and where you go. So then you have unloading fees and loading fees on the front side. So -- but that's a good rule of thumb.

Sounds good. And then my follow-up, do you think anything will change on your WCS exposure as TMX ramps? Or do you expect to receive the same volumes on -- I think it's at least the Express pipeline. There might be one other -- and we've noticed that the WCS futures curve, it widens out to about $15 a barrel by the end of this year. Is that just from expectations of continuing production growth in Canada?

Yes. I think mostly what you're seeing right now is the line fill, which is taking, what, 4.5 million barrels off the market permanently. And that's what brings it down to the $13 range which it is at today. I would expect it to widen back out a little bit once the line fill is complete. And I don't think -- I think most of the barrels that are going to be replaced are the ones that were going offshore out of the Gulf of Mexico. So I don't anticipate any problems getting barrels. We don't run all we can move on the pipes. So we end up selling quite a bit in Cushing. And we plan to continue that effort. I don't see any reason why it wouldn't continue where the production is today. I think the real benefit of TMX is really for the future, however, it gives the Canadian producers an outlet that they didn't have before. And unfortunately, the Keystone got canceled, which would have given that capacity to the United States rather than shipping to the West and the rest of the world. But I think still, the effect will be there, and that means more Canadian crude in the future.

Our next question comes from the line of John Royall with JPMorgan.

So I was hoping for some additional color on refining M&A in light of the 8-K. Could that impact some of the things you would otherwise do on the organic side, particularly thinking about the bigger projects you're considering with RD? Is it sort of an either/or with M&A or could both be done at the same time?

Well, John, remember that our larger RD project, our SAF project, however you want to call it, is really banked on our contribution being our Wynnewood operation of renewable diesel or SAF. What we are doing is, what equity we're providing, the location, the land, the permits, the design, all the rest will operate it for or whatever. But we will not do the project without a partner that is strategic in nature and is interested in the space, with the idea that we would IPO that company out as an eventual exit strategy. As far as other M&A, there's some very intriguing deals out there that are transformative for our company as well as others. And I think as we've always said, we look at everything, and we continue to look at everything. And like I said, some unique opportunities in the refining space that really made us pick up our pencil again and look at it again. So more to come on that.

Great. And then a follow-up, sticking with the 8-K. On the potential strategic options for UAN, I know this is something you looked at about maybe about a year ago. Now it looks like the idea of potentially separating UAN is back on the docket. Can you talk about the type of transaction that could potentially take place there? And what's changed between then and now in terms of being back and looking at the some of the parts for fertilizer? Is it just the equity coming back a little bit? Or are there other drivers?

Well, I think you probably heard about the recent transaction that's occurred with -- or it hasn't closed yet, but it's been proposed for the Wever plant with OCI that kind of mark-to-market a pretty big value, pretty much twice the value of what UAN is today. So that's what kind of sparked the interest in it and we're just exploring opportunities that, that might incur going forward.

Our next question comes from the line of Neil Mehta with Goldman Sachs.

Dave, just building on the M&A comments that you have made and in the 8-K. Are there characteristics that you say define what would be a successful M&A transaction for you on the refining side, whether it's specific regions? And as you think about potential M&A, do you have a preference for packages versus single assets? Just trying to get a context of the framework by which you evaluate success as you consider different options.

Yes. Sure, Neil. I think one of our biggest impediments to our stock price, I think, is our lack of diversification. So we've in the past, have pointed to the West is our desired area. But I don't -- I think what we need is size and scale and diversity of our refining fleet, and any of these actions and the available transactions would scratch that itch. So I think that's mainly what we're looking for. When you sit here in the Mid-Con and that's all you got, particularly Group 3, you're subject to the realms of the market with nothing to offset it other than fertilizer. So -- if you look at the size of our fertilizer business compared to the rest of it, it's relatively small. So any diversification we can do there is a benefit to the stock and the shareholders is my point of view.

Yes. And the follow-up is just distillate. You have a distillate heavy mix here, which has been a huge tailwind over the last couple of years. It has softened a little bit here more recently and part of that does seem to be seasonal. But has anything changed in your structurally bullish distillate and diesel view? And are you seeing anything real time that would say that things should turn more positive as we work our way through the summer?

Well, we had -- we came off of two very mild winters, frankly. Some people say it was the mildest winter ever in the States. I don't know because we had some severe weather in our markets that makes me wonder if -- how much the climate is really changing. But that said, I think the bigger impact is -- really is the industrial activity and just the movement of goods around the country has just been kind of anemic. That said, if you just look at -- the other thing I'd add to it, we're up to almost 5% now of renewable diesel in the pool. That was less than 1%, 1.5 years ago. So it's really come on and it certainly is changing the California market, but it's probably affecting everywhere to some degree. Now that's -- all that said, if you look at the practicality of EVs in the heavy trucking industry, it's poor at best and renewable diesel is by far a better solution. So I don't think that the market can't handle that. It's just -- if we have a little bit of any kind of manufacturing and industrial activity, diesel demand will pick right back up. And that's kind of our view.

Our next question comes from the line of Paul Cheng with Scotiabank.

Dave or Dane, that in the event if there's a good transaction in refining, how much of the debt now you will be willing to put on in terms of the balance sheet that -- I mean, how should we look at it?

Can you repeat it again, Paul?

If that's a good transaction that an acquisition target that you think is really good for you. How far you will be willing to stretch your balance sheet?

Yes, Paul, it would obviously depend on the target and what the earnings power of that target would be. We've always kind of said we're comfortable between the 1 and 2x levered ratio. So depending on the target, I don't think our -- we want to change our debt profile materially long term. So I'd still use that as a benchmark over the long haul.

And we want to use our equity to some degree, Paul. So...

Right. But I mean that, Dane, I understand your long-term leverage target you haven't changed. But in terms of the short-term, how far are you willing to go? What is within an acceptable level of that, say, within the 12 months after you close the deal?

I'll lever off what Dave said. It really would depend on the depth of the equity market. Is there a scenario where we'd potentially stretch if there was a very clear path of delevering? Yes, but probably not too aggressively beyond where our current targets are.

Okay. Second question. Dane, can you tell us that what is your remaining hedging position for the rest of the year? And also, Dave, when you talk about the second quarter, the [ RD ] will be reaching the capacity. Are you talking about reaching the run at 100% because previously, I think you've been talking about running maybe more like in the 70%. So I just want to make sure I understand your comment on that.

Yes, Paul, on the RD side of it is we're planning to run this run at 5,000 barrels per day, which is about 75 of renewable diesel compared to our nameplate of 100. So we're probably a little higher in the numbers you said, but right in that angle. And what we're trying to explore here is catalyst life and find the optimum in that. And we'll sneak up on that, probably the next load increasing it to maybe 6,000, and then we'll go from there. Your other question...

Yes. On open derivative positions, Paul. So for '24, we're at about 8% of gasoline and diesel production. But one thing I want to caveat is that production rate does assume a full run rate of Wynnewood. So we have to -- once we know more, we'll be able to appropriately adjust what that would look like with any downtime that's associated with the fire. And then for '25, we're about 4% of total gasoline-diesel production. That's 100% of that is diesel production. So 9% on diesel production for '25.

Dane you say 4% in -- 4% in gasoline and diesel, but that's because it's all in diesel, so it's 9% in diesel and 0% in gasoline, right?

Yes, that's correct.

And is the position for the second quarter right now is making money or losing money?

Making money for the second half.

For the second quarter right now. Is your divested position in the second quarter is making money or losing money?

Yes, we're making money. It's in the money right now, Paul.

Thank you. We have no further questions at this time. I would like to turn the floor back over to management for closing comments.

Again, I'd like to thank you all for your interest in CVR Energy. Additionally, I'd like to thank our employees for their hard work and commitment towards safe, reliable and environmentally responsible operations. We look forward to reviewing our second quarter 2024 results in our next earnings call. Thank you.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation, and have a wonderful day.