Greetings and welcome to the CVR Energy first quarter 2024 conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. 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 to 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 reconciliation of the most directly comparable GAAP financial measures, are included in our 2024 first quarter earnings release that we filed with the SEC in 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. 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 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 relative to a prior period. We are pleased to announce that our board of directors authorized a first quarter regular dividend of $0.50 per share, which will be paid on May 20th to shareholders of record at the close of the market on May 13th. Our annualized dividend yield of approximately 6% yesterday, based on yesterday's closing price, remains best in class among the independent refiners. In our petroleum segment, combined total throughput for the first quarter of 2024 was approximately 196,000 bbl per day, and net 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 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 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 remanded 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 exemptions petition 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 oral arguments in the small refinery exemption denial cases for a few other small refineries a few weeks ago. While we expect a ruling will take some time, we were pleased with how the hearing went. We also continue to wait for a response from EPA regarding our petition for rulemaking related to the RFS. We believe the law is clear that only obligated parties who over comply with their RFS obligations can generate excess RINs, and that they 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'll 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, with throughput in the quarter impacted by a planned catalyst change. The HOBO spread improved from the fourth quarter of 2023 with lower soybean oil prices, although prices for D4 RINs remained 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 is 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 for the fourth quarter of 2023 pricing, and 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 on 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 marked-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 marked-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 31st, representing 449 million RINs marked-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 on 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 non-controlling 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 of 2024, we estimate total consolidated capital spending to be approximately $225 million-$250 million and turnaround spending to be approximately $55 million-$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 fertilizer segment. Total liquidity as of March 31st, 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%-100%, direct operating expenses to be approximately $50-$55 million, excluding inventory impacts, and total capital spending to be between $15-$20 million. That's Dave. I'll turn it back over to you. Thank you. 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-cycle. 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 five-year averages. W e 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 wild card. We also continue to monitor the startup 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. remains steady and is trending above the five-year average levels recently, while diesel 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 MMbpd. With crude prices in the $85 per barrel range, we expect continued strength in shale 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 bbl 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 and our diesel hydro treating unit, we will believe we'll be able to increase distillate production at the Wynnewood refinery by approximately 2,500 bbl 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 facility until 2025. The pretreatment unit 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 with the combination of new catalyst load in the RD unit plus 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 to structure the offtake agreement such that it would significantly de-risk a margin that could justify the capital we need to invest. On the 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, 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 to explore opportunities to grow our renewable 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. Thank you. We will now be conducting a question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we pull for questions. Thank you. Our first question comes from a line of Manav Gupta with UBS. Please proceed with your question. Good morning, guys. 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 the community standpoint, our employee standpoint, our 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, and 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. So just was trying to make sure. M y second question is, looks like your PTU is now going to be up and running. Is it running at your RD facility? Help us understand how it are you looking to transform from refined soybean oil to unrefined soybean oil? Are you looking to do some tallow and stuff a nd 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 even buying treated feed or refined, deodorized, and degummed feed. It still had a lot of impurities in it in the forms of metals and phosphorus and other things. T he results of the pretreater look 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%+ 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 the 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. W e 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 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 break-even. Thank you. Very helpful. Thank you. You're welcome. Our next question comes from a line of Matthew Blair with Tudor, Pickering, Holt. Please proceed with your question. Thank you. G ood afternoon, Dave. I wanted to follow up on your comments regarding—I think you mentioned something about railing gasoline to the West Coast. So just wanted to confirm that you are railing gasoline to California and capitalizing on the higher margins in that space. A lso just curious, can you make that CARB spec, or is it a blended spec a nd what kind of volumes are we talking about here? Thanks. Sure. As I mentioned, I said to the West, not necessarily to California, b ut no, we put in a transloading facility. I had a 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 bbl per month, and that's our capability of the transloader, b ut 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 pretty sure we could make some of it to some degree if we had the segregated tankage b ut 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 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-$0.40 a barrel or sorry, a gallon? Well, normally, anytime you move anything by rail, it's $6-$8 per barrel. So that's a good rule of thumb. Depends on how far you go and where you go. So then you have unloading fees and loading fees on the front side, b ut that's a good rule of thumb. Sounds good. T hen 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. W e'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? Thanks. Yeah. 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 a nd that's what brings it down to the $13 range that it's at today. I would expect it to widen back out a little bit once the line fill is complete. 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'm not anticipating any problems getting barrels. We don't run all we can move on the pipes, so we end up selling quite a bit and cushioning a nd 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. Unfortunately, Keystone got canceled, which would have given them that capacity to the United States rather than shipping to the West and the rest of the world. I think still, the effect will be there, and that means more Canadian crude in the future. Great. Thanks, Dave. You're welcome. Our next question comes from a line of John Royal with J.P. Morgan. Please proceed with your question. Hi. Good afternoon. Thanks for taking my question. So I was hoping for some additional color on refining M&A in light of the 8K. C ould 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 or 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 sweat equity. We're providing the location, the land, the permits, the design, all the rest. We'll operate it for 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. I think, as we've always said, we look at everything, and we continue to look at everything. Like I said, some unique opportunities in the refining space that really made us pick up our pencil again and look at it again. More to come on that. Great. T hen follow-up, sticking with the 8-K, on the potential strategic options for UAN. I know this is something you looked at maybe about a year ago, and 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? Well, I think you've probably heard about the recent transaction that's occurred with or hasn't closed yet, but it's been proposed for the Wever plant with OCI that kind of marked the market a pretty big value, pretty much twice the value of what UAN is today. So that's what's kind of sparked the interest in it, and we're just exploring opportunities that that might incur going forward. Great. Thank you. You're welcome. Our next question comes from a line of Neil Mehta with Goldman Sachs. Please proceed with your question. Thanks, Dave. Just building on the M&A comments that you have made in the 8-K, are there characteristics that you would say define what would be a successful M&A transaction for you on the refining side, whether it's specific regions? A s 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. Yeah. 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, pointed to the West as our desired area, but I don't, I think what we need is size and scale and diversity of our refining fleet a nd any of these actions and the available transactions would scratch that edge. 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. Yeah. Nice, Dave. T he follow-up is just distillate. Do 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 a nd 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 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 how much the climate's really changing. But that said, I think the bigger impact 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 and 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% a year and a half 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, all that said, if you look at the practicality of EVs and 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 industrial activity, diesel demand will pick right back up a nd that's kind of our view. Okay. Very helpful. Thanks, Dave. You're welcome. Our next question comes from a line of Paul Cheng with Scotiabank. Please proceed with your question. Hey. Good morning, guys. Good afternoon, guys. Dave or Dane, in the event if there's a good transaction in refining, how much of the debt load 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 there's a good transaction, an acquisition target that you think is really good for you, how far will you be willing to stretch your balance sheet? Yeah, 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 2 x leverage ratio. So depending on the target, I don't think we'd want to change our debt profile materially long-term. So I'd still use that as a benchmark over the long haul. W e'd want to use our equity too to some degree, Paul, so. Right. But I mean, Dane, I understand your long-term leverage target you haven't changed, but in terms of the short term, how far you're willing to go? What is within an acceptable level of debt, 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 what our current targets are. Okay. Second question. Dane, can you tell us what is your remaining hedging position for the rest of the year? A lso, 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. Yeah, Paul. On RD side of it, we're planning to run this run at 5,000 bbl 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'd said, but we're right in that angle. W hat we're trying to explore here is catalyst life and find the optimum in that. W e'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? Yeah. On open derivative positions, Paul. So for 2024, we're at about 8% of gasoline and diesel production. The only thing I want to caveat is that production rate does assume a full run rate of Wynnewood. So 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. Then for 2025, we're about 4% of total gasoline diesel production. 100% of that's diesel production, so 9% on diesel production for 2025. Dane, you say 4% in total in 4% in gasoline and diesel because it's all in diesel. So it's 9% in diesel and 0% in gasoline, right? Yeah. Yeah, Yeah, that's correct. 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 derivative position in the second quarter making money or losing money? Yeah. We're making money. It's in the money right now, Paul. Okay. With you. Thank you. You're welcome. 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.