Greetings, and welcome to the CVR Energy First Quarter 2022 Conference Call. 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, 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 1-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 the 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 23 to shareholders of record at close of market on May 13. 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 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 compared to $16.33 in the first quarter of 2021. Based on the high end of the proposed 2022 RVO levels, RIN prices averaged approximately $6.11 per barrel in the first quarter, an increase of 13% over the first quarter of 2021. The Brent-TI differential averaged 2.89 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 Mid-Con. 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 2 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. RINs 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 mark-to-market impact on our estimated accrued RFS obligation, which was marked-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 '22, 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 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. The CVR Energy owns approximately 37% of CVR Partners common units and 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 to $239 million, of which approximately $131 million to $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 to $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 CVR Partners' 2023 senior notes, $36 million for the noncontrolling interest portion of the CVR Partners' fourth-quarter distribution and $12 million for CVR Partners unit repurchases. Turning to the balance sheet. At March 31, 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 to 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% and 97%. Direct operating expenses to be approximately $55 million to $60 million, excluding inventory and turnaround impacts and total capital spending to be between $12 million and $17 million. For renewables, we estimate second quarter 2022 total throughput to be approximately 3,500 to 4,500 barrels per day and direct operating expenses to be between $2 million and $4 million. With that, Dave, I'll 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, refining product demand is essentially in line with 5-year average levels. While inventories for gasoline and distillate jet fuel are nearly 10% below 5-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 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 refining 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 Mid-Con demand for gasoline and diesel in line with pre-COVID levels, inventories have tightened since the beginning of the year which has significantly improved the basis in the Group 3. Distillate inventories in the Magellan system are nearly 25% below the 5-year average levels, pushing Group 3 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 have stated a number of times, the key to the sustained widening of the Brent TI 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 4 quarters, CVR Partners has paid down $95 million of high-interest debt and bought back $12 million of units and announced the distribution of over $12 per unit. Our net 37% interest in CVR Energy's share of the distributions for the past 4 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 the pretreater in the second quarter of '23. We are also continuing to develop our overall renewables strategy beyond these 2 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 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 the Brent TI spread of approximately $14.19 per barrel and a Midland differential of $0.88 per barrel over WTI. The WTI differential has averaged $0.27 under WTI and the WCS differential has averaged $14.24 per barrel under WTI. Fertilizer prices remained strong as well. The 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 TI was $2.41 per barrel and WCS was $15.03 under WTI assuming the high end of the proposed 2022 RVO, RINs were approximately per barrel. Group III diesel cracks are over $83 per barrel. In April, the 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 remains stubbornly high as we continue to wait for the EPA to rule on small refinery exemptions for '19, '20, and '21 as well as finalizing the RVO for 2021 and '22. We continue to be perplexed by how a federal agency can repeatedly obligations under the law to rule on small refinery waiver exemption 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 positions for small refinery exemptions for 2019, 2020, and 2021 and will soon be filing for '22. Until these outstanding issues are resolved by the EPA or the courts, we will likely continue to carry RIN obligations on our balance sheet as we believe we are legally entitled to relief, and we'll continue to prepare to assert our rights wherever and whenever possible. The chaos caused by the 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 the EPA on which participants in the value chain are able to pass through the cost of the program, the 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 whom have publicly admitted to holding RINs until prices rise and only selling to obligated parties opportunistically. Hopefully, consumers will take notice and demand that the EPA and the administration lower gasoline prices immediately by fixing the broken RFS. Meanwhile, our focus is on safe, reliable operation of our assets and environmentally responsible manner to ensure we are ready to capture market opportunities as they develop. With that, operator, we're ready for questions.

Our first question comes from the line of Phil Gresh with JPMorgan.

My first question is regarding the dividend announcement. You mentioned the annualized rate, which is quite substantial. Does this imply that the dividend will represent the new standard moving forward? Additionally, could you share your thoughts on the overall capital return strategy you are aiming to implement?

Well, I think you've heard us say many times that our business model is to return cash to shareholders in as many ways as we possibly can and any available cash. And I think this just demonstrates that strategy. The Board will look at it every month, every quarter and make a decision. But obviously, we wouldn't have reinstated it if we didn't have some confidence in the business. And the shape of the curve going forward looks very positive to us. So I think we went back to our original strategy of returning money to shareholders.

Yes. Understood. Okay. And then the second question, I just wanted to ask you, you gave the update on the PTU and the delay there. But I was hoping you could just talk a little bit more broadly about your view of fundamentals now as you start up the facility without the PTU. Do you feel comfortable with the margin environment here, there are so many moving pieces right now between what's happening at diesel prices, prices, LCFS. Just curious what your latest thinking is on the fundamental picture.

I find the current market quite intriguing. When we decided to proceed with the conversion, the circumstances were quite different from today. However, we believe we can generate profits with the existing setup. We are sacrificing some opportunity in refining as we are reducing our crude rate to accommodate this; overall, the RDU seems to be profitable for us. It's important to note that we acquired much of the feedstock we are using now several quarters ago because we postponed the conversion by about six months. Consequently, a substantial portion of what we're processing was purchased quite some time ago; the impact on our profit and loss statement remains to be determined. The positive aspect is that the unit is operational and stable, and we are nearing the certification of the material as carbon dated, with the necessary paperwork nearly finalized. It's still uncertain whether we will increase the rate and how quickly we will do so. At this moment, we are committed to operating through this catalyst life cycle and will reassess once we need to order and replace another batch of catalysts.

Yes, that makes sense. To clarify, considering the current LCFS prices, which have decreased significantly, do you believe that the economics of running RD have effectively factored in this lower LCFS price? Do you feel optimistic about the run rate potential of the business, apart from the inventory you are acquiring at the reduced price?

It's much improved with the pretreater operational, but we're anticipating that our numbers will fall between $10 million and $30 million this year. I'm not certain of the exact figure since the situation is quite volatile—it's even more unpredictable than the oil industry. The market fluctuations are astonishing, largely influenced by diesel differentials and the current dynamics in that area. I must say, this business has become commoditized much faster than I expected. Feedstock prices are aligning closely with bean oil, and it seems that some of the carbon intensity credits are also being impacted by those prices. As the low carbon fuel standard credits decrease, the D4 values have risen, somewhat balancing that out. The question remains about the future of the blender tax credit and whether it will be extended. Nonetheless, we maintain a positive outlook on the business. We’ve invested significantly in it and intend to pursue it further. We’re confident about sourcing other advantageous feedstocks due to our location and are far from giving up on this venture.

I appreciate the volatility and the complexity, and thank you for your thoughts, Dave.

Our next question comes from the line of Carly Davenport with Goldman Sachs.

I wanted to just touch briefly on kind of the cost environment. OpEx came in a touch higher this quarter than we had expected. So 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 of comments, and maybe Dane can elaborate some more. We did have a one-time charge in our operating expenses this time that is not reoccurring, which was about $12 million. Other than that, natural gas is a challenge. I'll remind you that every dollar affects us by about $11 million in EBITDA on a run rate basis. So, we're nearly double in the first quarter compared to the previous quarter. We also likely had some stock-based adjustments due to our stock's increases, especially our UAN stock unit prices. That impacts the P&L. Dane, do you have anything to add?

Yes. 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 in OpEx and SG&A.

Understood. And then 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 the lack of the maintenance at Wynnewood coming through 2Q. So can you just talk about 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. In terms of operations, we plan to run our plants at full capacity as much as possible, considering factors like weather and other unforeseen events. During the Wynnewood turnaround, we built some inventory that we need to work through before we can fully increase the crude rates at our Wynnewood refinery. Other than that, there are no further plans for the remainder of the year. Our next turnaround will be in 2023, which will be a minor one at Coffeyville, primarily focusing on the coker. That's the only other impact we foresee. Regarding margins, we're experiencing levels that I haven't seen in my career for a long time, if ever. There were brief moments during the hurricane, but those lasted only a couple of weeks. Currently, the market conditions are very favorable, and there seems to be a global shortage of refining capacity. Looking at margins in places like Singapore and Europe, they're also quite high. This is a worldwide issue, and it has significant implications. As the driving season approaches, gasoline demand will inevitably increase, which will require raising crude rates—though I don't believe the world has the capacity to do so—or drawing from diesel supplies to produce more gasoline. Overall, the situation appears very robust.

Our next question comes from the line of Manav Gupta with Credit Suisse.

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. So thank you for reinstating it. It just helps the overall sector. My question here is for those of us who are more of refining analyst and less of fertilizer analyst. 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?

If you look at the numbers, prices have increased by over 250% from the first quarter of 2021, particularly for ammonia and UAN. We produce a significant amount of ammonia and an even greater quantity of UAN, with margins for UAN exceeding those of ammonia. The main reason for this situation is that plants in Europe have closed due to high natural gas prices, which I observed yesterday at $1,500 per ton for ammonia just in natural gas costs. This is a major contributing factor. Additionally, countries like China and Russia have been hoarding their own production to ensure they have enough fertilizer for their populations, especially before the situation in Ukraine escalated. Both countries were previously significant exporters. This has left the U.S. as a market that relies on imports, and globally, there is a fertilizer shortage. In conjunction with strong crop prices, we also face a shortage of grains, soybeans, corn, and wheat, creating what I would call a perfect storm. Building a new fertilizer plant now takes about five years and costs between $3 billion and $5 billion, depending on the location. There have not been many announcements for new plants, but as we know, the best remedy for high prices is high prices. This cycle typically resolves itself 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 contracts are incredibly good. So I 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? And I'll leave it there.

Yes. As I mentioned before, demand has returned to pre-COVID levels across our markets. Magellan inventories are low. We came out of winter with high gasoline levels, which have decreased. I'm optimistic about the group's outlook. It will depend on the turnaround cycles and which operators perform well, as well as any weather impacts. But at this moment, our market appears very strong.

Our next question comes from the line of Matt Vittorioso with Jefferies.

I have a couple of quick questions. As we move through the second and third quarters, the 2-1-1 crack has averaged $45 so far. Clearly, this indicates a strong second quarter. Could you provide some directional insights on captures? The capture rate in the first quarter for that 2-1-1 was around 45%. Any high-level guidance on how you expect that to progress in the second quarter?

Well, I don't have any reason to see it changing much. If you look at the basis on gasoline, it's still sub NYMEX. Distillate is above NYMEX, premium moves around and those are the way we really impact our capture rates. Of course, the big headwind is RINs and that carves out up to 25% of the capture right there. If you put that back in, we're in our historical range, typical. We have done a lot to increase premium make, and we'll continue to capture that 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. And those margins have been quite remarkable also for the year.

That's helpful. I wanted to clarify regarding the corporate restructuring mentioned in the press release, which will create some new subsidiaries focused on green initiatives. From a bondholder's viewpoint, I want to ensure that you are not transferring assets out of any restricted group or moving them away from bondholders. This seems to be just a realignment of the existing asset structure. Is that accurate?

That is correct. In terms of the notes, all will be moved within the construct of the CVI notes.

Okay. And then lastly for me, just thinking about cash flow, given where cracks are today and just what could be a very strong couple of quarters here. You're also getting distributions from UAN who's also generating 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 of that dividend should be each quarter. But away from that, any capital allocation thoughts? And on the back of that, when you came with your bond deal, you did $1 billion to refi 500 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, there's still a couple of 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?

Yes. I think we're comfortable with the $1 billion level of debt at this time. 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. But for the time being, we want to make sure that we're taking it as advantage of the green funding as we can. In terms of other capital allocation, 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.

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

Maybe that I have to apologize, I came in maybe late or maybe I didn't catch it correctly. Did you say that you guys are looking at the potential option of converting like a full conversion of Wynnewood into a renewable plant that will also produce?

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 find the scope for Coffeyville conversion of one of its hydrotreaters to renewable diesel. And within that, we have the option of adding a module to make sustainable jet fuel at the same time.

Okay. So that has been on the table for some time. When are you going to make that decision?

Well, as I mentioned in the prepared remarks, Paul, we're not going to 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 and/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 because that's really what the goal of reducing carbon is and the RFS is very inefficient at it compared to what the LCFS is.

For the LCFS market, even with many states likely to adopt it, we will still face structural challenges and the need to export due to the RD projects currently in construction. Given that scenario, will you consider the export market viable, especially since Europe, Canada, and various other regions are likely to establish similar markets, potentially leading to a strong export opportunity for RD? Will you focus on projects tailored for the export market, or will you refrain from building if you don't see a healthy domestic demand? From a fundamental and strategic perspective, how do you assess the market?

Well, I think, Paul, from our location, the 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 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. So you're getting close to where it's the push to whether you rail it or just dump it into your base pool. And that's always a variable that's there.

I'm sorry, I'm not referring to you're going to export it yourself. But I mean the whole market, other people are exporting then you're going to tighten the domestic market. So that's why I asked that if in order for the market to balance, we need to export RD. Will that be 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 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 tax credit. There's no RIN associated with it. I don't see a mechanism to make that happen at this point even for those close to it.

The current RVO obligation on the balance sheet is $585 million. It is important to note that we have outstanding waivers for 2019, 2020, and 2021 for Wynnewood. As Dave mentioned, we will soon be filing for 2022. We believe we are legally entitled to those waivers, and therefore, we are comfortable carrying that liability on our balance sheet.

And your second question, Paul, I didn't quite catch it.

No, I was asking that whether for 2022, you guys have been current on your RVO or that, that has been added to your balance sheet?

Yes. We're still short of a little '22 and '21. 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 and we'll be litigating all that as EPA acts.

Right. So Dave, that's my final part of the question is that on June 3, if the EPA didn't change so the next step is that you guys are going to sue them again?

It really depends on what the EPA decides on June 3. I expect that they will take actions similar to what they did with 18 small refinery waivers, which I believe were issued unlawfully. They seem to be trying to change their interpretation of the regulations at a much later date, which is quite unreasonable. However, I am confident that we will be successful in our litigation regarding the Wynnewood exemption. At this stage, there is no reason for us to pursue anything other than litigation.

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

Dave, just trying to circle back to your comments that you expect RD to make. I think it was $10 million to $30 million this year. And I was wondering if you can extrapolate that 4,000 barrel per day renewable volume guidance for Q2, if you 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. And so that $10 million to $30 million range should be anywhere from like $0.22 EBITDA per gallon to $0.65 EBITDA per gallon. And 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, the way you buy feedstock here is usually a quarter ahead or even two quarters ahead. The volatility in the HOBO spread has been incredible. It seems like a framework for hedging strategies and other considerations that we're still figuring out. However, I don't think your numbers are too far off. If you look at the current margin on an RBD soybean, and considering we operate with a mix of soybean oil and corn oil in various percentages, you would arrive at the margins you mentioned; you'd be very close. Yes, just a moment. I would like to point out that we have not yet determined the specific rate we will implement. Whether we increase it or not will depend on the margins we observe.

Great. Great. Sounds good. And thanks for providing the OpEx. Yes, go ahead.

Yes, just a moment. One other point I want to mention is that we haven't determined the exact rate we will implement. Whether we will increase it or not will depend on what those margins are.

Yes. So that $39 million in Q1, was that impacted by the stock comp expense or that onetime accrual? And really, what I'm trying to get at is, is that $39 million, is that a good run rate for Q2? Or do you expect to be closer to like the low $30 million or even high $20 million range like you used to be? Yes. So there was a stock-based comp impact in the SG&A figures as well. And then in addition, as we go about this restructuring, we're picking up some ancillary costs there as well, helping inflate that. But nothing that we see that would dramatically change what our typical run rates are that project and any volatility in the stock price.

Okay. So that means coming down to low $30 million range for Q2?

It should be a pretty good number. The $12 million was definitely a one-time charge. That was another income or other expense, but that shouldn't happen again. The rest of it is related to stock-based compensation. We need to understand how our stock will perform and how that will affect us. However, it should be a one-time issue unless the stock continues to rise, which we hope it does. Aside from that, the restructuring has cost us a bit of money, but that's the only other factor here. I expect it to return to previous levels after a couple of quarters.

Okay. Very helpful. And then last question. So a lot of focus on the current diesel cracks. But I mean the 2023 curve has really moved up as well. And so 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 examine that regularly, and we do occasionally engage in a certain percentage of our volume. Some of the crack prices were low if you had locked them in last week compared to where they are now. However, it's heavily backward dated. For the first two months out, you're back down to something akin to 2023, which I believe was around $43 that you could achieve in the group, not even including NYMEX. Even for 2024, it was $38, which are very strong figures. So I don't think we'll take any action just yet, but I always say the best remedy for high prices is indeed high prices. Those figures are quite attractive when you consider historical data. Whether we'll move forward with that remains to be seen.

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 towards safe, reliable and environmentally responsible operations. We look forward to reviewing our second quarter 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.