Greetings, and welcome to the CVR Energy First Quarter 2024 Conference Call. 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 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 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% 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 and 2025. Benchmark cracks softened during the first quarter with the Group 3 2-1-1 averaging $19.55 per barrel compared to $23.66 per barrel for the fourth quarter of 2023. First quarter average RIN prices declined from the fourth quarter and ended the quarter at approximately $0.68 on an RVO weighted basis. While we're thrilled with the Fifth Circuit's decision in November vacating EPA's denial of Wynnewood's small refinery exemption petitions for 2017 through 2021 and remanding those petitions back to EPA. EPA's egregious conduct continues. They still have not acted on Wynnewood's small refinery exemption petitions for 2017 through 2021, though 90 days have passed since the issuance of the Fifth Circuit mandate, nor has EPA ruled on EPA's small refinery exemption petitions for 2023 due last month. We will continue to push for a court ruling to force EPA to do its job and follow the law. The D.C. Court of Appeals heard our arguments in the small refinery exemption denial cases for a few other small refineries a few weeks ago. While we expect the ruling will take some time, we were pleased with how the hearing went. We also continue to wait for a response from the EPA regarding our petition for rule-making related to the RFS. We believe the law is clear that only obligated parties who overcomply with their RFS obligations can generate excess RINs and may sell those RINs only to other obligated parties who need the RINs for compliance. That EPA allows non-obligated parties to exploit the RIN market for profit is just wrong. It's not just wrong, it violates the law as written. If EPA does not respond to our petition, once again, we will see them in court. For the first quarter of 2024, we processed approximately 7 million gallons of vegetable oil feedstocks at our Wynnewood renewable diesel unit, and the throughput in the quarter impacted by a planned catalyst change. The HOBO spread improved from the fourth quarter of 2023, but lower soybean oil prices, although prices for these 4 RINs remain depressed as a result of EPA's continued mismanagement of the RFS program. As a reminder, our renewable diesel business is currently reported in our Corporate and Other segment. In the Fertilizer segment, we achieved consolidated ammonia plant utilization of 90%, which was also impacted by some planned downtime in the quarter at our Coffeyville facility. Nitrogen fertilizer prices in the first quarter of 2024 remained fairly steady compared to the fourth quarter of 2023 pricing. We saw strong demand for ammonia with favorable weather conditions during the quarter. Now let me turn the call over to Dane to discuss our financial highlights.

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 segment was $40 million for the first quarter, with lower feedstock costs and direct operating expenses somewhat offsetting the decline in prices relative to the prior year period. The partnership declared a distribution of $1.92 per common unit for the first quarter of 2024. As CVR Energy owns approximately 37% of CVR Partners common units we will receive a proportionate cash distribution of approximately $7 million. Cash provided by operations for the first quarter of 2024 was $177 million, and free cash flow was $121 million. Significant uses of cash in the quarter included $61 million for cash taxes and interest, $59 million of capital and turnaround spending, $50 million for the fourth quarter 2023 regular dividend and $11 million paid for the noncontrolling interest portion of the CVR Partners' fourth quarter 2023 distribution. Total consolidated capital spending was $51 million, which included $36 million in the Petroleum segment, $5 million in the Fertilizer segment and $8 million for the RDU, primarily related to the pretreatment unit. Turnaround spending in the first quarter was approximately $39 million. For the full year 2024, we estimate total consolidated capital spending to be approximately $225 million to $250 million and turnaround spending to be approximately $55 million to $65 million. Turning to the balance sheet. We ended the quarter with a consolidated cash balance of $644 million, which includes $65 million of cash in the Fertilizers segment. Total liquidity as of March 31, excluding CVR Partners, was approximately $831 million, which was comprised primarily of $580 million of cash and availability under the ABL facility of $251 million. Looking ahead to the second quarter of 2024. As Dave mentioned, we are still assessing the extent of the damage from the fire at Wynnewood. We will provide an updated outlook for the Petroleum segment and the renewable diesel unit once the impact of the incident is determined. The Coffeyville refinery continues to operate as planned. For the Fertilizer segment, we estimate our second quarter 2024 ammonia utilization rate to be between 95% and 100%, direct operating expenses to be approximately $50 million to $55 million excluding inventory impacts and total capital spending to be between $15 million and $20 million.

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 the 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 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 barrels per day. This is an important part of our strategy given the uplift we usually experience by bringing in neat barrels to the refinery gates. I'm pleased to announce that the Board recently approved a distillate yield improvement project at the Wynnewood refinery. Through some modifications to the vacuum tower in our diesel hydrotreating unit, we believe we'll be able to increase distillate production at the Wynnewood refinery by approximately 2,500 barrels per day. We completed tie-in work for the project during Wynnewood's recent turnaround project, and we currently expect final completion in the first half of 2025 at a capital cost of less than $15 million. We are also studying a similar project at Coffeyville, which if approved by the Board and successfully implemented could be completed in 2026. Turning to the Fertilizer segment. We had good ammonia sales in the first quarter with favorable weather conditions, allowing farmers to apply ammonia earlier in the year. We expect strong demand for spring with planting expectations currently at 90 million acres for corn and 87 million acres for soybeans. We currently do not have any additional downtime planned for either fertilizer facilities until 2025. The pretreater for the renewable diesel unit began operations in the first quarter, and we expect to reach planned production rates during the second quarter. We are optimistic that the combination of new catalyst load in the RD unit along with the PTU when operational, would result in improvements in our renewable diesel product yield, catalyst life and resulting economics. We continue to explore opportunities in the renewable space and are currently in discussions related to the potential conversion of the Wynnewood renewable diesel unit up to 100% SAF. As we have discussed previously, our focus in exploring this project would be the structure of the offtake agreement such that would significantly derisk a margin that could justify the capital we need to invest. On a larger potential project at Coffeyville, we expect to have the project scope, cost and development plan ready to take to the market by the end of the year. We still believe there will be a market for renewable diesel and sustainable aviation going forward despite EPA's continued mismanagement of the RFS regulation. Finally, in March, we issued a Form 8-K announcing that we were routinely considering and currently considering potential strategic transactions both in refining and potentially related to CVR Partners. While we have nothing to disclose and certainly provide no assurances that we could successfully close any such transactions, there are some very interesting and transformative opportunities out there for both our refining business and CVR Partners. Looking at the second quarter of 2024, quarter-to-date metrics are as follows: Group 2-1-1 cracks have averaged $20.67 per barrel and Brent-TI spread at $4.48 per barrel and the Midland differential of $1.42 over WTI. Prompt fertilizer prices are approximately $600 per ton for ammonia and $300 per ton for UAN. As of yesterday, Group 3 2-1-1 cracks were $21.01 per barrel, the Brent-TI spread was $5.77 per barrel and WCS was $13.21 under WTI. RINs were approximately $3.06 per barrel. As always, we continue to strive to operate our plants in a safe, reliable and environmentally responsible manner and explore opportunities to grow our renewables business. We will continue to focus on maximizing free cash flow, which underpins our peer-leading dividend yield. With that, Operator, we're ready for questions.

Our first question comes from 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 which then spread a little bit as it got hot. I think our response was excellent from a community standpoint, our employees' standpoint, and contractors' standpoint. But it's an unfortunate event that we're sometimes exposed to. If you recall, the town of Sulphur, which is probably about 15 miles from us, experienced a very bad tornado. The 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. My second question is, it seems that your PTU is now operational at your RD facility. Can you explain what you aim to process from refined soybean oil to unrefined soybean oil? Are you planning to include tallow and other materials? Do you believe this will significantly impact 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 on actual renewable diesel. We're very encouraged with 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. The results of the pretreater look really good at this point, and we're starting this run with the pretreater up. The catalyst performance is already looking very good, with yields of 90-plus percent on renewable diesel, and much less byproducts than we had seen before that. So I'm really optimistic that we'll pick up not only the ability to run untreated corn oil and soybean oil, but maybe some other options for some other things. Right now, we're really focused on corn oil as a substitute for 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 with 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. We put in a transloading facility ahead of third-party put it in, and we're underwriting it with tariffs. Our plan is to load up to 120,000 barrels per month, which is our capability of the transloader. We will go 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 Grand Junction, even Denver occasionally, and other places like Salt Lake City and Phoenix on occasion. So that'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 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. Then you have unloading fees and loading fees on the front side. So that's a good rule of thumb.

Sounds good. As a follow-up, do you anticipate any changes to your WCS exposure as TMX increases? Or do you expect to receive similar volumes, particularly from the Express pipeline? We've also noticed that the WCS futures curve is widening to about $15 a barrel by the end of this year. Is this primarily due to expectations of sustained production growth in Canada?

Yes. Right now, the primary factor is the line fill, which is removing around 4.5 million barrels from the market permanently. This adjustment brings the prices down to the $13 range where they currently stand. I anticipate that prices will widen slightly once the line fill concludes. Most of the barrels that will be replaced are those that were previously sent offshore from the Gulf of Mexico, so I do not foresee any issues in securing barrels. We do not operate at full capacity on the pipelines, leading us to sell a substantial amount in Cushing, and we intend to maintain that strategy. I see no reason this won't continue given our current production levels. The real advantage of TMX is its potential for the future, as it provides Canadian producers with an outlet they lacked previously. Unfortunately, the cancellation of Keystone removed the opportunity to provide that capacity to the United States instead of directing it towards the West and the global market. Nonetheless, I believe the benefits will still be present, indicating an increase in 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 as an eventual exit strategy. As far as other M&A, there are 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. There are 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 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 some of the parts for fertilizer? Is it just the equity coming back a little bit? Or are there other drivers?

I believe you might have heard about the recent transaction proposed for the Wever plant with OCI, which has an estimated value that's roughly double what UAN is currently worth. This has generated interest, and we are exploring potential opportunities that may arise in the future.

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 is our lack of diversification. In the past, we pointed to the West as our desired area. 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, that's all you've got, particularly Group 3, you're subject to the realms of the market with nothing to offset it other than fertilizer. 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, in 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 in real time that would say that things should turn more positive as we work our way through the summer?

We recently experienced two very mild winters, with some claiming it was the mildest ever in the U.S. However, we encountered significant weather events in our markets that raise questions about climate change. The more substantial issue is the sluggish industrial activity and the slow movement of goods across the country. On a positive note, we have increased our renewable diesel content in the mix to nearly 5%, up from less than 1% a year and a half ago. This shift is impacting the California market and likely affecting other areas as well. Nonetheless, when considering the feasibility of electric vehicles in the heavy trucking sector, the situation remains challenging, and renewable diesel offers a far superior alternative. I believe the market can adapt; a slight uptick in manufacturing or industrial activity would lead to a rebound in diesel demand. That's essentially our perspective.

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

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

Can you repeat it again, Paul?

If there's a good transaction that an acquisition target that you think is really good for you, how far will you 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 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.

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 12 months after you close the deal?

I'll leverage 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 deleveraging? Yes, but probably not too aggressively beyond where our current targets are.

Okay. Second question. Dane, can you tell us what your remaining hedging position for the rest of the year is? And also, Dave, when you talk about the second quarter, the RD will be reaching 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. We'll sneak up on that, probably the next load increasing it to maybe 6,000, and then we'll go from there.

Yes, on open derivative positions, Paul. So for 2024, we're at about 8% of gasoline and diesel production. One thing I want to caveat is that production rate does assume a full run rate of Wynnewood, so we have to adjust what that would look like with any downtime associated with the fire. And for 2025, we're about 4% of total gasoline-diesel production. That's 100% of that is diesel production. So 9% on diesel production for 2025.

Dane, you mention 4% in gasoline and diesel, but that's solely due to diesel, so it's actually 9% in diesel and 0% in gasoline, correct?

Yes, that's correct.

And is the position for the second quarter right now 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 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.