Greetings, and welcome to the CVR Energy first quarter 2022 conference call. At this time, all participants are in 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 Financial Planning and Analysis 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 2022 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 2022 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 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. Let me also remind you that CVR Partners completed a one-for-10 reverse split of its common units on November 23, 2020. Any per unit references made on this call are on a split-adjusted basis. This call also includes various non-GAAP financial measures. The disclosures related to such non-GAAP measures, including reconciliation to the most directly comparable GAAP financial measures, are included in our 2022 first quarter earnings release that we filed with the SEC and Form 10-Q for the period and will be discussed during the call. That said, I'll turn the call over to Dave. Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. Yesterday, we reported first quarter consolidated net income of $153 million and earnings per share of $0.93. EBITDA for the quarter was $278 million. We posted higher results in both segments on a year-over-year basis as fundamentals in refining and fertilizer sector continued to improve during the first quarter. We are pleased to announce that the board has authorized the first quarter dividend of $0.40 per share, which will be paid on May twenty-third to shareholders of record at close of market on May thirteenth. At yesterday's closing price, this annualized dividend would be $1.60 per share, representing a dividend yield of over 6%, which is currently the highest annual dividend yield among independent refiners. For our petroleum segment, the combined total throughput for the first quarter of 2022 was approximately 197,000 barrels per day, with Wynnewood undergoing its planned turnaround during the month of March. This compares to 186,000 barrels per day for the first quarter of 2021, which was impacted by some weather-related outages. The planned turnaround at Wynnewood began at the end of February and was completed on schedule in the first week of April. We also completed the conversion of the hydrocracker to renewable diesel service. The renewable diesel unit has begun operations and is currently running at half rate as we work out the bugs and work towards certification of renewable diesel product. Benchmark cracks increased through the quarter. The Group 3 2-1-1 crack averaged $22.20 per barrel in the first quarter as compared to $16.33 in the first quarter of 2021. Based on the high end of the proposed 2022 RVO levels, RIN prices averaged at approximately $6.11 per barrel in the first quarter, an increase of 13% over the first quarter of 2021. The Brent-WTI differential averaged $2.98 per barrel in the first quarter compared to $3.18 in the prior year period. Diesel cracks surged in March and averaged $39.25 per barrel for the month. Light product yield for the quarter was 99% on crude oil processed. Our distillate yield as a percentage of total crude throughput was 42%, and we continue to operate our refineries in max distillate mode. In total, we gathered approximately 114,000 barrels per day of crude oil during the first quarter of 2022 compared to 112,000 barrels per day for the same period last year. As we have stated, we have started to see an increase in drilling activities in our area, and our gathering rates have been above 120,000 barrels per day recently. Although supply chain issues remain a hurdle in increasing production quickly, it is encouraging to see producers starting to ramp up activity in the MidCon. In the fertilizer segment, we faced some unplanned downtime at both plants during the quarter, with consolidated ammonia utilization coming in at 88%. During the upcoming turnarounds at both facilities this summer, we expect to address the issues that caused some of the unplanned outages over the last two quarters. Price realizations for the first quarter of 2022 increased again, reflecting the latest price increases that began in the fall with the onset of the energy crunch in Europe and Asia. The recent conflict in Ukraine has driven increased concern over global fertilizer and grain supply and has strengthened prices further and increased our confidence in the longevity of this ag cycle. Now let me turn the call over to Dane to discuss additional financial highlights. Thank you, Dave, and good afternoon, everyone. For the first quarter of 2022, our consolidated net income was $153 million. Earnings per share was $0.93, and EBITDA was $278 million. Our first quarter results include a negative mark-to-market impact on our estimated outstanding RIN obligation of $19 million, unrealized derivative gains of $6 million, and favorable inventory valuation impacts of $136 million. As a reminder, our estimated outstanding RIN obligation is based on the original 2020 RVO, the high end of the proposed 2021 and 2022 RVO levels, and excludes the impact of any waivers or exemptions. Excluding the above mentioned items, adjusted EBITDA for the quarter was $155 million. The petroleum segment's adjusted EBITDA for the first quarter of 2022 was $48 million, compared to $27 million for the first quarter of 2021. I would like to highlight that within our adjusted EBITDA for the first quarter of 2022, we recognized a $12 million expense related to potential future legal obligations that shows up in the other expense line. The year-over-year increase in adjusted EBITDA was driven by higher throughput volumes and increased product cracks, offset somewhat by elevated RIN prices. In the first quarter of 2022, our petroleum segment's reported refining margin was $16.75 per barrel. Excluding favorable inventory impacts of $7.51 per barrel, unrealized derivative gains of $0.28 per barrel, and the mark-to-market impact of our estimated outstanding RIN obligation of $1.08 per barrel, our refining margin would have been approximately $10.04 per barrel. On this basis, capture rate for the first quarter of 2022 was 45%, compared to 51% in the first quarter of 2021. RIN's expense, excluding mark-to-market impacts, reduced our first quarter capture rate by approximately 22%, compared to a 24% reduction in the prior period. RINs expense for the first quarter of 2022 was $107 million or $6 per barrel of total throughput, compared to an expense of $178 million or $10.62 per barrel for the same period last year. As a reminder, our reported RINs expense does not include the impact of any waivers or exemptions. Our first quarter RINs expense includes a $19 million mark-to-market impact on our estimated accrued RFS obligation, which was mark-to-market at an average RIN price of $1.37 at quarter end, compared to $1.34 at the end of 2021. For the full year 2022, we forecast an obligation based on the high end of the proposed 2022 RVO of approximately 175 million RINs, which includes approximately 105 million RINs generated from renewable diesel production, but does not include the impact of any waivers or exemptions. Derivative gains in the petroleum segment totaled $8 million for the first quarter of 2022, which includes unrealized gains of $5 million, primarily associated with crack spread derivatives. In the first quarter of 2021, we had total derivative losses of $32 million, which included unrealized losses of $43 million, primarily associated with the crack spread hedges that were closed at the end of the third quarter. The petroleum segment's direct operating expenses were $5.57 per barrel in the first quarter of 2022, as compared to $5.89 per barrel in the prior year period. On an absolute basis, direct operating expenses were flat with the first quarter of 2021, primarily due to increased share-based compensation and labor expenses offsetting other operating expense reductions. For the first quarter of 2022, the fertilizer segment reported operating income of $104 million, net income of $94 million or $8.78 per common unit, and EBITDA of $123 million. This is compared to first quarter of 2021 operating losses of $14 million, a net loss of $25 million or $2.37 per common unit, and EBITDA of $5 million. There were no adjustments to EBITDA in either period. The year-over-year increase in EBITDA was primarily driven by higher UAN and ammonia sales prices and higher sales volumes. The partnership declared a distribution of $2.26 per common unit for the first quarter of 2022. As CVR Energy owns approximately 37% of CVR Partners common units, we will receive a proportionate cash distribution of approximately $9 million. Total consolidated capital spending for the first quarter of 2022 was $50 million, which included $19 million from the petroleum segment, $5 million from the fertilizer segment, and $26 million on the renewable diesel unit. Environmental and maintenance capital spending comprised $23 million, including $18 million in the petroleum segment and $5 million in the fertilizer segment. We estimate total consolidated capital spending for 2022 to be approximately $209 million-$239 million, of which approximately $131 million-$146 million is expected to be environmental and maintenance capital. Our consolidated capital spending plan excludes planned turnaround spending, which we estimate will be approximately $80 million-$85 million for the year for the recently completed planned turnaround at Wynnewood and in preparation for the planned turnaround at Coffeyville in 2023. Cash provided by operations for the first quarter of 2022 was $322 million, and free cash flow was $281 million. Significant cash uses in the quarter included $41 million for CapEx and turnaround spending, $30 million for interest, $65 million for the remaining redemption of the remaining CVR Partners' 2023 senior notes, $36 million for the non-controlling interest portion of the CVR Partners' fourth quarter distribution, and $12 million for CVR Partners' unit repurchases. Turning to the balance sheet at March 31st, we ended the quarter with approximately $676 million of cash. Our consolidated cash balance includes $137 million in the fertilizer segment. As of March 31, excluding CVR Partners, we had approximately $755 million of liquidity, which was primarily comprised of approximately $539 million of cash and availability under the ABL of approximately $371 million, less cash included in the borrowing base of $155 million. During the quarter, CVR Partners redeemed the remaining $65 million of 2023 9.25% senior notes outstanding, completing its targeted $95 million debt reduction plan. With the refinancing of the senior notes in June of 2021 and the $95 million debt paydown, the annual debt service costs at CVR Partners will be reduced by approximately $26 million per year, a reduction of over 40%. Looking ahead to the second quarter of 2021, for our petroleum segment, we estimate total throughput to be approximately 195,000-210,000 barrels per day. We expect total direct operating expenses to range between $95 million and $100 million, and total capital spending to be between $30 million and $40 million. For the fertilizer segment, we estimate our second quarter 2022 ammonia utilization rate to be between 92%-97%, direct operating expenses to be approximately $55 million-$60 million, excluding inventory and turnaround impacts, and total capital spending to be between $12 million-$17 million. For renewables, we estimate second quarter 2022 total throughput to be approximately 3,500-4,500 barrels per day, and direct operating expenses to be between $2 million-$4 million. With that, Dave, I will turn it back over to you. Thank you, Dane. In summary, refining market fundamentals have improved considerably since the beginning of the year, with the conflict in Ukraine further tightening what was already becoming a tight market. In the United States, refined product demand is essentially in line with five-year average levels, while inventories for gasoline distillate jet fuel are nearly 10% below five-year averages. Exports of refined products have increased over the past month to over 2.5 million barrels a day, an increase of over 1 million barrels per day from the beginning of the year. As we approach the summer driving season and a fairly heavy maintenance period for the industry in the second half of the year, we believe the near-term outlook for refined products is constructive. The combination of natural gas advantage of the U.S. versus Europe and Asia, the loss of Russian distillate exports, and the rationalization of global refining capacity has resulted in significantly improved cracks, particularly diesel cracks, despite near record high RIN prices. With the MidCon, demand for gasoline and diesel is in line with pre-COVID levels, and inventories have tightened since the beginning of the year, which has significantly improved the basis in the Group Three. Distillate inventories in the Magellan system are nearly 25% below the five-year average levels, pushing Group Three distillate cracks to near $60 per barrel for the month of April. We are also seeing a pickup in the drilling activity in our gathering area. Supply chain issues remain a constraint on the faster ramp-up of new drilling, but we're encouraged to see the level of interest increasing. As I've stated a number of times, the key to sustained widening of the Brent-WTI differentials is an increase in shale oil production in the United States. With conversations starting to turn to the need for U.S. energy independence and a call for increased domestic crude production, we believe our assets are well-positioned to benefit from higher shale oil production. The outlook for the fertilizer business continues to be very positive also. The conflict in Ukraine is further tightening the market that was already struggling with low inventories and supply issues since the fall. With low fertilizer inventories in the United States, ongoing export constraints from China and Russia, and Europe continuing to face high energy costs that are driving up the cost of fertilizer production, we do not see an easy fix for fertilizer supply issues in the near term. Over the past four quarters, CVR Partners has paid down $95 million of high-interest debt and bought back 12 million of units and announced a distribution of over $12 per unit. Our net 37% interest in CVR Energy's share of the distributions for the past four quarters is nearly $50 million. As I previously mentioned, during the turnaround at Wynnewood, we completed the conversion of the hydrocracker to renewable diesel service, and we continue to make progress on the pretreatment unit. We have ordered long-lead equipment and are currently in the permitting phase. Due to the ongoing supply chain issues, we are now targeting an in-service date for the pretreater in the second quarter of 2023. We are also continuing to develop our overall renewables strategy beyond these two projects, including the reorganization of the company to segregate the renewables business, as I discussed in our last earnings call. The reorganization plan has been approved by the board and new entities have been created for the various assets. We have completed scope definition on the potential Wynnewood renewable diesel conversion project, which could include the production of sustainable aviation fuel. The future of that conversion will depend on, among other factors, the development of the expansion of the LCFS program to other states or the conversion of the renewable fuel standard to an LCFS-type regulation. Overall, we are looking at any economic opportunity within our existing refining and fertilizer business that can drive a reduction of carbon emissions, and we believe our geographical location in the Farm Belt provides us with a unique position long term. Looking at the second quarter of 2022, quarter to date metrics are as follows. Group 3 2-1-1 cracks have averaged $43.25 per barrel with a Brent-WTI spread of approximately $14.19 per barrel and a Midland differential of $0.88 per barrel over WTI. The WTL differential has averaged $0.27 under WTI, and the WCS differential has averaged $14.24 per barrel under WTI. Fertilizer prices remain strong as well. Ammonia prices are over $1,200 per ton, and UAN prices are over $550 per ton. As of yesterday, Group 3 2-1-1 cracks were $57.42 per barrel. Brent-WTI was $2.41 per barrel, and WCS was $15.03 under WTI. Assuming the high end of the proposed 2022 RVO, RINs were approximately $8.50 per barrel. Group 3 diesel cracks are over $83 per barrel. In April, EPA made a seemingly symbolic yet unlawful announcement to revoke small refinery exemptions granted for 2018. However, the EPA is not requiring those refineries to purchase or redeem RINs to meet the 2018 obligation. This announcement had no impact on the price of RINs, which remain stubbornly high as we continue to wait for EPA to rule on small refinery exemptions for 2019, 2020 and 2021, as well as finalizing the RVO for 2020, 2021 and 2022. We continue to be perplexed by how a federal agency can repeatedly short its obligations under the law to rule on small refinery waiver exemptions and issue RVOs in a timely manner. As we have continually stated, we believe Wynnewood's obligation should be exempt under the RFS. We have filed petitions for small refinery exemptions for 2019, 2020 and 2021, and we'll soon be filing for 2022. Until these outstanding issues are resolved by EPA or the courts, we will likely continue to carry a RIN obligation on our balance sheet as we believe we are legally entitled to relief and will continue to prepare to assert our rights wherever and whenever possible. The chaos caused by EPA's persistent refusal to comply with the RFS rule as intended by Congress does not only hurt small and merchant refiners. While we disagree with EPA on which participants in the value chain are able to pass through the cost of the program, EPA has stated repeatedly that it is the driving public who ultimately foots the bill for higher prices at the pump. We estimate this cost to be as much as $30 billion for 2021 alone, as much as $0.30 per gallon, which isn't even paid to the government. We believe high RIN prices help no one but Wall Street traders, big oil, and big retail blenders, some of who have publicly admitted to holding RINs until prices rise and only selling to obligated parties opportunistically. Hopefully, consumers will take notice and demand that EPA and the administration lower gasoline prices immediately by fixing the broken RFS. Meanwhile, our focus is on safe, reliable operation of our assets in an environmentally responsible manner to ensure we are ready to capture market opportunities as they develop. 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 poll for questions. Thank you. Our first question comes from the line of Phil Gresh with J.P. Morgan. Please proceed with your question. Hey, good morning, Dave. First question. Good morning, Phil. Good afternoon, I guess. First question is just on the announcement of the dividend here. You talked about obviously the annualized, you know, rate, which would be pretty high. Is that to suggest that dividend is going to be the new kind of run rate from here or and/or, you know, just any thoughts on just a general return of capital framework that you're trying to achieve? Well, I think you've heard us say many times that you know, our business model is to return cash to shareholders in as many ways as we possibly can and any available cash. I think this just demonstrates that strategy. You know, the board will look at it every month, every quarter and make a decision. Obviously we wouldn't have reinstated if we didn't have some confidence in the business. You know, the shape of the curve going forward looks very positive to us. I think we went back to our original strategy of returning money to shareholders. Yep, understood. Okay. The second question I just wanted to ask you gave the update on the PTU and the other delay there. I was hoping you could just talk a little bit more broadly about your view of fundamentals now as you start up the facility with without the PTU. You know, do you feel comfortable with the margin environment here? There's so many moving pieces right now between what's happening in diesel prices, so SBO prices, LCFS. Just curious what your latest thinking is on the fundamental picture. Well, I think, you know, it's a very interesting market. You know, when we made the call to make the conversion, it was a much different picture than what it is today. On the other hand, you know, where the price of RINs are right now, it appears to us that we can make money with the current structure. We are giving up an opportunity cost in refining because as you know, we're cutting a little bit of crude rate to accommodate this, the RDU. In general, it looks profitable to us and, you know, you gotta remember, we bought a lot of this feedstock that we're running now several quarters ago because we did delay that the conversion probably six months in the original piece. A lot of what we're processing now was bought quite a while ago. Of course, how that will flow through the P&L is yet to be seen. The good news is the unit's up and running and very stable and we're very close to certification of the material as carbon dated as you have to do on all the various paperwork you have to file is almost complete. Whether we'll ramp up the rate or not is still an open question and how fast we'll do that. Right now, I think, we're firmly in the camp that we're gonna run it through this cycle of catalyst life and then take a look at it again when we have to order and replace another load of catalyst. Yeah, that makes sense. I guess, just to kinda clarify, as I think about where LCFS prices are now, obviously they've come down a lot. Do you feel like the economics of running RD have appropriately accounted for that lower LCFS price, you know, such that you feel aside from the inventory that you're getting at the lower price, that you feel good about the run rate potential of the business? Well, it's you know, it's a lot better with the pretreater in service, I think. You know, but you know, there's still you know, we're projecting that you know, between $10 million and $30 million of something this year. You know, exactly what it'll be, I don't know 'cause the thing is moving around like. It's even worse than the oil business, frankly. It's just the swings in the market are just incredible. A lot of it's right now is driven by the diesel differentials and what's happening there on the cracks. You know, I will tell you that this business has commoditized a whole lot quicker than I thought it would've. It's you know, you're looking at feedstock prices that are almost pricing just. It doesn't matter which one it is. They're almost pricing with bean oil. You know, some of the CI is being given up into those prices, what it appears to be. As Low Carbon Fuel Standard credits go down, you know, what's happening is basically the D4 values have gone up and kind of offset that. What happens when the blender tax credit runs out is a whole 'another animal. You know, whether that gets extended or not is still an open issue. We're still positive on the business. We put a fair amount of money into it, and we're gonna give it a run and see how we do. We're still very pretty confident we're gonna be able to source some other feedstocks that are gonna be advantaged just because of our location. We're not ready by any stretch of the imagination to throw in the towel on it. Well, I appreciate the volatility and the complexity. Thank you for your thoughts, Dave. You're welcome. Our next question comes from the line of Carly Davenport with Goldman Sachs. Please proceed with your question. Hey, good afternoon. Thanks for taking the questions. Wanted to just touch briefly on kind of the cost environment. OpEx came in a touch higher this quarter than we had expected. Can you just talk a bit about what you're seeing from an inflation perspective out there, whether that's on the OpEx side or also on the CapEx side, and how you're working to manage any of those cost pressures? Sure. I'll make a couple comments and maybe Dane can elaborate some more. We did have a one-time charge in our OpEx this time that is not recurring. That was about $12 million. You know, other than that, natural gas is a headwind. I'll remind you it's about every dollar is worth about $11 million to us in EBITDA on a run rate basis. So we're up, you know, almost double in the first quarter what it was in the previous quarter. You know, we also probably had some stock-based adjustments that since our stock has run up and particularly our UAN stock, our unit price has gone up quite a bit. That runs through the P&L. Dane, I don't know if you have anything to add. Yeah. I'll just clarify. The accrual that was made was another income line item. The escalation that we saw in OpEx was primarily associated with the run-up of both UAN and CVI through three thirty-one, in OpEx and SG&A. Understood. Thanks for that color. The follow-up was just on kind of the operational side, the guidance for volumes for 2Q looks strong as you guys don't have, you know, the lack of the maintenance at Wynnewood coming through 2Q. Can you just talk a bit how things are trending from an operational perspective at refining and ultimately to the extent that you run well and can capture these strong margins that we're seeing on the screen, kind of where you think EBITDA power could be as we think about the 2Q, 3Q setup? Sure. As far as operations goes, you know, we're running our plants wide open as much as we can, subject to other things that are thrown at us, like weather and other events. We did build some inventory during the Wynnewood turnaround that we'll have to work off before we raise the crude rates at our Wynnewood refinery. Other than that, there's nothing else planned going forward for the rest of the year. Our next turnaround there really in 2023, which is a small turnaround at Coffeyville and mainly on the coker. That's the only other impact that's there. As far as what I mentioned where crack spreads are today, we're in an area that I haven't seen in my career in a long time, if ever. I think I saw it a couple of times during a hurricane, and only lasted two weeks or so. Structurally, the market is very constructive. It appears we're short refining capacity worldwide. If you look at the margins in Singapore and in Europe, they're also equally wide. It's pretty much a worldwide event. The world's short diesel big time. Eventually that's gonna have a pull on gasoline as the driving season comes, and it's gonna have to pull out. Either you have to raise crude rates or which I don't think that the world has the capacity to do, or you have to carve into diesel to make more gasoline. It just looks very, very strong. For taking the questions. Our next question comes from the line of Manav Gupta with Credit Suisse. Please proceed with your question. Dave, first of all, congrats for reinstating the dividend. It's good to see that the dividends which had disappeared kind of pre-pandemic or during the pandemic from the refining coverage are all coming back. Thank you for reinstating it. It just helps the overall sector. My question here is for those of us who are more of refining analysts and less of fertilizer analysts, help us understand, every quarter we are seeing fertilizer prices move up. What's driving that? How long can this super cycle environment for the fertilizer remain in place, and how are you guys benefiting from it? Well, you know, I think, if you just take the numbers and look at it, you know, prices are up over the first quarter of 2021, over 250%, but just about on ammonia as well as UAN. We make a fair quantity of ammonia, and we make an even higher quantity of UAN. That margin is even higher than the ammonia margin. It, you know, the structural thing that's happened here is, you know, plants in Europe have shut down because of the high natural gas price. If you look at the price, I think I looked at it yesterday, with natural gas where it is in Europe, it's $1,500 a ton just in natural gas cost on a ton of ammonia. You know, that is what's basically driving it. You also had some hoarding going on with China and Russia. Basically that was before Ukraine. They're hoarding their own production to make sure they can feed their people and have enough fertilizer for themselves. They were both big exporters. When you put those all together, it's just the U.S. is an import market, so net import market. The world's just short fertilizer, frankly. If you look at crop prices, you know, they're very, very strong. The world is also short grain, soybeans, corn and wheat. That's it's kind of a perfect storm, I'd call it. It's, you know, it takes probably 5 years now to build a new fertilizer plant and probably $5 billion or $3 billion-$5 billion, depending on where you build it. You haven't heard too many announcements of too many of those happening. You know as well as I do, the best cure for high prices is high prices. You know, this is a cycle that tends to get solved eventually. Perfect. My quick follow-up here is on. Look, everybody is obviously bullish on the Gulf Coast and the export potential and everything. But when you look at the cracks, mid-con cracks are incredibly good. So, understand the bullishness on the Gulf Coast, but can you talk about the strength in the refining fundamentals as it relates to, like, a pure mid-con refiner that you're seeing right now? I'll leave it there. Thank you. Yeah. As I mentioned on the previous statements, you know, the demand is has not been you know, it's back to pre-COVID levels across the board in our markets. Magellan inventories are on the low side. We came out of winter with gasoline on the high side, and that's been whittled away. I'm very constructive on what the group looks like. You know, it all depends on what the turnaround cycles will be and who runs well and who doesn't, and any other weather impacts that occur. Right now, the market looks wonderful. Thank you so much. You're welcome. Our next question comes from the line of Matt Vittorioso with Jefferies. Please proceed with your question. Yeah, good afternoon. I guess just a couple quick ones. Just on, you know, as we progress through the second quarter and the third quarter, you know, that two on one crack averaging $45 so far, obviously it's gonna be a solid second quarter. Just wondering if you could give us any sort of directional commentary on captures. First quarter capture on that two on one was, you know, 45% or so. Any sort of just high-level guidance on sort of how that should progress in the second quarter? Well, you know, I don't have any reason to see it changing much. You know, if you look at the basis on gasoline, it's still sub NYMEX. Distillate is above NYMEX. Premium moves around like mad. And those are the way we really impact our capture rates is those. Of course, the big headwind is RINs. You know, that carves out 20 to, you know, up to 25% of the capture right there. If you put that back in, we're in our historical range, typical. Now we have done a lot to increase premium make, and we'll continue to capture that as going forward, which is a big change. We're also back in the jet business a bit, which is not only in the military, but in the commercial aviation area. Those margins have been quite remarkable also for the year. That's helpful. I guess just on the, I think you mentioned in the press release the sort of corporate restructuring that's gonna carve out or create, you know, some new subsidiaries around the green stuff. Just from a bondholder's perspective, just wanna confirm that you're not moving assets out of any restricted group or moving assets away from bondholders. This is just creating, like, realigning the existing asset setup. Is that fair? Yeah. That is correct. In terms of the notes, all will be moved within the construct of the CVI notes. Okay. Lastly for me, just thinking about cash flow, you know, given where cracks are today and just the, you know, what could be a, you know, very strong couple quarters here. You're also, you know, getting distributions from UAN, who's also generating very, very strong cash flow. Just maybe if you could talk about your cash flow priorities. You've reinstituted the dividend, and I presume you'll sort of assess what size that dividend should be each quarter. Away from that, any capital allocation thoughts? On the back of that, when you came with your bond deal, you did, you know, $1 billion to refi $500 million, with the thought that maybe you would do some M&A at some point. I know you've kind of moved away from M&A, so I guess I'm thinking as those 25s, you know, they're still a couple years away, but as they get closer, do you think about just a straight refi there, or is $1 billion of debt the right level for you guys? Just how are you thinking about that stuff? Yeah. I think we're comfortable with the $1 billion level of debt for the time being. You know, as we get to the refi point, we'll of course look for opportunities to look for green funds and maybe split some of that up between the various entities at that time. For the time being, you know, we wanna make sure that we're taking advantage of the green funding as we can. In terms of other capital allocations, as you said, we'll assess it each quarter and then take a look at what's in front of us and determine what the best path is. All right. Thanks, guys. Our next question comes from the line of Paul Cheng with Scotiabank. Please proceed with your question. Hey, guys. Good afternoon. Hey. I have to apologize. I came in a little bit late, so maybe I didn't catch it correctly. Did you say that you guys are looking at the potential option of converting a full conversion of Wynnewood into a renewable plant that will also produce SAF? No. We were talking about Coffeyville at that time. As I think we announced some time ago that we were doing an engineering study to define the scope for a Coffeyville conversion of one of its hydrotreaters to renewable diesel. Within that, we have the option of adding a module to make sustainable jet fuel at the same time. Because that has been on the table for some time. Yes. When is that you guys going to make that decision? Well, as I mentioned in the prepared remarks, Paul, we're not gonna make that decision until some kind of expansion on the Low Carbon Fuel Standard regulation to other states. That market is getting oversupplied or will be soon. Or the conversion of RFS to a Low Carbon Fuel Standard credit, which the EPA has been talking about a little bit. I don't know. I don't hold my hopes very high that they'll do it, but if they were smart, they would 'cause that's really what the goal of you know reducing carbon is. The RFS is very inefficient at it compared to what the LCFS is. I mean, realistically, for the LCFS market, even if we have a large number of states going to be adopting that, given the amount of RD under construction, since anyway, we're going to be structurally long and need to export. Under that circumstance, will that be. Will you guys look at that and say, "Okay, I mean, export market is fine because we believe that Europe, Canada, every place - a lot of places that are going to adopt some kind of market like that, so as such that there's a strong export market for RD. Will you make the conversion or that the FID the project that tailored for the export market or that you say, "No. I mean, that this is really just if I can't see the domestic demand and supply is in a good shape, I'm not going to build it. I mean, from a fundamental standpoint, more strategically, how you look at the market? Well, I think, Paul, you know, from our location to export would be difficult at best. I think you would see the coastal plants doing the exporting and the internal plants doing mainly the rail to wherever the LCFS market is. I will point out, if you look at, you know, our cost to rail to California is probably in that $0.30 a gallon range. LCFS credits right now where they're priced, depending on what feed you run, let's just do it on a soybean basis, are about $0.38 credit. You're getting close to where it's a push to whether you rail it or just dump it into your base pool of fuel oil. Uh-huh That's always a variable that's there. You know Right. Dave, I'm sorry, I'm not referring to that you're going to export it yourself, but I mean, just the whole market, if other people are exporting, then you're going to tighten the domestic market. Yeah. That's why I asked that if, in order for the market to balance, we need to export a lot of RD, will that as a condition that still make you comfortable to FID? Well, I don't know. I don't think to make a conversion to Coffeyville. I think it's, you know, we'd have to look at that specific point. It's unclear to me how you really monetize going to Canada at this point. You lose the blender. Okay. -tax credit. There's no RIN that's associated with it. It's there, you know, I don't see a mechanism to make that happen at this point, even for those- I see. Plants that are close to it. Thank you. The second question is for Dane. I probably may have missed some of your prepared remark. Did you talk about what is the RVO currently on your balance sheet? Also whether you have been keeping current for 2022. Finally, let's assume in June third the EPA essentially status quo, haven't done anything to change the current programming in terms of SRE as well as the RVO, then revise it for 2021, 2022s. At that point, will the company start to looking for a pathway to settle your obligation, or I mean, what is the next step for you guys? The current RVO obligation on the balance sheet is $585 million. Keep in mind, that represents we have outstanding waivers for 2019, 2020 and 2021 for Wynnewood. As I mentioned or as Dave mentioned, we'll be soon filing 2022. We legally believe that we're entitled to those waivers. As such, we're comfortable carrying that balance sheet or that liability on our balance sheet. Your second question, Paul? Dave. I didn't quite catch it. No, I was asking that whether for 2022, you guys have been current on your RVO or that has been added to your balance sheet. We're still short a little of 2022 and 2021s. Our plan is to settle Coffeyville and remain short on Wynnewood, in essence, because we believe we're entitled to the small refinery waiver at Wynnewood. We'll be litigating over that. And- as EPA acts. Right. Dave, that's my final part of the question is that, on June third, if the EPA didn't change, so if the next step is that you guys going to sue them again? Well, it depends on what they do on June third, of course. I anticipate that they're going to, just based on what they did with 18 small refinery waivers, rescinding those, what appears to me to be illegally, and then try to apply a change in the way they have interpreted the regulation at something that's so far past when it was created. It's kind of ridiculous, the approach they've taken. That said, you know, I think we're still, you know, fairly certain and quite certain that we'll be successful in litigating the Wynnewood exemption. There's no reason for us to do anything more but to litigate at this point. I see. All right. Thank you. You're welcome. Our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt & Co. Please proceed with your question. Hey, Dave. Good morning. Just trying to circle back to your comments that you expect RD to make, I think it was $10 million-$30 million this year. I was wondering if we can extrapolate that 4,000 barrel per day renewable volume guidance for Q2, if we can extrapolate that for Q3 and Q4. When I do so, it looks like you'd make around, I guess 46 million gallons for the year. That 10-30 million range would be anywhere from like $0.22 EBITDA per gallon to $0.65 EBITDA per gallon. Just wanted to run those numbers by you and see if there's anything else we need to take into consideration or if that's the range that you're trying to guide to. Well, as I'm sure you know, Matthew, you know, the way you buy feedstock here is usually a quarter ahead or even two quarters. The volatility in the HOBO spread has been incredible. It's somewhat of an equation for hedging strategies and other things that we're still working out or how exactly we're gonna do it. But I don't think your numbers are far off. You just look at the margin today on an RBD soybean, and we do run a mix of soybean oil and corn oil in varying percentages that you know that you would come up with those kind of margins that you mentioned. You'd be very close. Great. Sounds good. Thanks for providing the OpEx. Oh, yeah, go ahead. The other point. Yeah, just one second. One other point I'd make to you is that we haven't decided what exactly rate we'll run. Whether it'll be, you know, we'll ramp it up or not will depend on what those margins are. Right. It is a pretty volatile environment. I just had a question on SG&A. That $39 million in Q1, was that impacted by the stock comp expense or that one-time accrual? Really what I'm trying to get at is that $39 million, is that a good run rate for Q2, or do you expect to be, you know, closer to like the low 30 or even high 20 million range like you used to be? There was a stock-based comp impact in the SG&A figures as well. And then in addition, you know, as we go about this restructuring, we're picking up some ancillary costs there as well, helping inflate that. Nothing that we see that would dramatically change what our typical run rates are absent that project and any volatility in the stock price. Okay. That means coming down to the low 30 range for Q2? Should be. Yeah. Pretty good number. I mean, the $12 million for sure was a one-time charge. That was the other income. Yeah. That was another income or other expense. You know, that's not gonna repeat itself, hopefully. The rest of it is stock-based. You know, tell us what our stock's gonna do, we can tell you where that's gonna impact, where or how it's gonna impact. It should be one time unless it continues up. Hopefully, it does. Other than that, there's, you know, the restructuring does cost us a little bit of money, but that's the only other thing in there. I'd expect it- Great. I'd expect it to go back to where it was after a couple quarters. Okay. Very helpful. Last question. You know, a lot of focus on the current diesel cracks. But I mean, the 2023 curve has really moved up as well. Just wondering if you're looking at any sort of product crack hedging and how appealing that might be and whether you start to layer any product crack hedges on. No, we look at that all the time, and we have, we do occasionally do a certain percentage of our volume. You know, some of the crack, you know, of course, if you would've locked them in last week, they were low compared to where they are today, but it's heavily backwardated. You know, the first two months out, you're back down into that, like you said, 2023. And I think 2023 was, what? About $43 you could do in the Group 3 actually, not even NYMEX. And even looking at 2024, it was $38, and those are very strong numbers. I don't know that we'll do anything yet. You know, I think I always say the best cure for high prices is high prices. Those numbers are very attractive, if you look at history. Whether we'll do that or not, I don't know. Great. Thank you very much. You're welcome. We have no further questions at this time. I would now 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, commitment toward safe, reliable, and environmentally responsible operations. We look forward to reviewing our second quarter of 2022 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.