CVR Energy Inc.

Greetings and welcome to the CVR Energy, Inc. fourth quarter 2021 conference call. At this time, all participants are in a listen-only mode. A 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. I would now like to turn the conference over to your host, Richard Roberts, Vice President of FP&A and Investor Relations for CVR Energy. Thank you, sir. You may begin.

Thank you, Melissa. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy fourth quarter 2021 earnings call. With me today are Dave Lamp, our chief executive officer, Dane Newman, our chief financial officer, and other members of management. Prior to discussing our 2021 fourth quarter and full year 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. We were cautioned that these statements may be affected by important factors set forth in our filings with the Securities and Exchange Commission and in our latest earnings release. As a result, actual operations or results may differ materially from the results discussed in the forward-looking statements. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events, or otherwise, except to the extent required by law. Let me also remind you that the CVR part is completed at 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 2021 fourth quarter earnings release that we filed with the SEC in Form 10-K for the period and will be discussed during the call. With that said, I'll turn the call over to Dave.

Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. This morning, we reported CVR Energy's Full year and fourth quarter results. For the full year of 21, we reported a net income of $74 million inclusive of non-controlling interest or $25 million attributable to CVI shareholders. Earnings per diluted share were $0.25 for the full year of 2021. For the fourth quarter, we reported net income of $25 million inclusive of non-controlling interest and a net loss attributable to CVI shareholders of $14 million. Loss per diluted share was $0.14 for the fourth quarter. EBITDA for the year was $462 million, and for the quarter it was $116 million. While RIN prices remained stubbornly high and weighted on our refining results, fertilizer markets fundamentals continued to improve and drove another quarter of strong results for CVRs fertilizer business. Despite the challenges in the refining market in 2021, we continue to focus on safe, reliable operations. We continue to achieve significant year-over-year improvements in environmental health and safety metrics, including a 42% year-over-year reduction in environmental events. We are providing more ESG disclosures and we published our first internal ESG report for 2020. Work is progressing on a 2021 report that we plan to release publicly later this year. We also returned capital to our shareholders through a significant special dividend in the second quarter, totaling the equivalent of $492 million, or $4.89 per share. Turning to the fourth quarter results, For our petroleum segment, the combined total throughput for the fourth quarter of 2021 was approximately 222,000 barrels per day, as compared to 219,000 barrels per day for the fourth quarter of 2020. Both facilities ran well during the quarter, and we increased WCS processing at the Coffeyville Refinery due to widening spreads of WCS at Cushing. Benchmark cracks have improved significantly from a year ago. The Group 3 2-1-1 crack averaged $17 per barrel in the fourth quarter of 21. However, RINs consumed over 35% of that at approximately $6.19 per barrel. Group 3 2-1-1 averaged $8.44 per barrel in the fourth quarter of 2020 when RINs were $3.50 a barrel. The Brent TI differential averaged $2.71 per barrel in the fourth quarter compared to $2.49 in the prior year period. The Midland Cushing differential was $0.63 per barrel over WTI in the quarter compared to $0.37 per barrel over WTI in the fourth quarter of 2020. And the WCS to WTI differential was $16.60 per barrel compared to $11.44 per barrel in the same period last year. Light product yield for the quarter was 103% based on crude oil processed. Our distillate yield as a percentage of total crude oil throughputs was 44% in the fourth quarter of 2021, consistent with prior periods. In total, we gathered approximately 113,000 barrels per day of crude during the fourth quarter of 21 compared to 117,000 barrels per day for the same period last year. We continue to see a slight decline in production across our system due to limited drilling activities over the past year. However, we would expect to see additional wells being drilled with current prices firmly above $80 per barrel. In the fertilizer segment, consolidated ammonia utilization was 90% during the quarter, which was impacted by some unplanned downtime at both facilities. In October, we completed the installation of an additional CO2 compressor and an ammonia pump at our Coffeyville facility, which should increase UAN production capacity by approximately 100 tons per day. Fertilizer prices continued to increase through the fourth quarter, and prices currently look firm through the first half of the year. Now let me turn the call over to Dane to discuss our financial highlights.

Thank you, Dave, and good afternoon, everyone. Our consolidated fourth quarter net income of $25 million and loss per diluted share of 14 cents includes a negative mark-to-market impact on our estimated outstanding RFS obligation of $9 million and favorable inventory valuation impacts of $17 million. Excluding these impacts, our fourth quarter 2021 adjusted EPS was a loss of 20 cents and adjusted EBITDA was $109 million. The petroleum segments EBITDA for the fourth quarter of 2021 was $27 million compared to a negative $66 million in the same period in 2020. The year-over-year EBITDA increase was driven by the significant increase in crack spreads offset somewhat by elevated rinse prices. Excluding the marked market impact on our estimated outstanding RFS obligation of $9 million and inventory evaluation impacts of $17 million, our petroleum segment adjusted EBITDA was $19 million. In the fourth quarter of 2021, our petroleum segment's reported refining margin was $7.13 per barrel. Excluding inventory evaluation impacts, unrealized derivative losses, and the marked market impact of our estimated outstanding rent obligation, Our refining margin would have been approximately $6.70 per barrel. On this basis, capture rate for the fourth quarter of 2021 was approximately 39% compared to 59% in the fourth quarter of 2020. Our capture rate for the fourth quarter of 2021 was negatively impacted by elevated rinse prices and a less favorable crude differential, mostly due to the steep backwardation in the crude oil market. RIN's expense in the fourth quarter of 2021 was $100 million, or $4.89 per barrel of total throughput, compared to $120 million for the same period last year. As a reminder, our reported RIN's expense does not include the impact of any waivers or exemptions. Our fourth quarter RIN's expense includes a $9 million mark-to-market impact on our estimated accrued RFS obligation, including a $2 million benefit from revising our 2021 obligation to the high end of the recently proposed 2021 renewable volume obligation. Our estimated accrued RFS obligation was mark to market at an average RIN price of $1.34 a year end compared to $1.31 at the end of the third quarter. The full year 2021 RINs expense was $435 million as compared to $190 million in 2020. Our estimated RFS obligation at the end of the year approximates Winnie Wood's obligations for 2019 through 2021 as we continue to believe Winnie Wood's obligations should be exempt under the RFS regulation. For 2022, based on the high end of the EPA's proposed 2022 RVO, we forecast a net obligation from refining operations of approximately 250 to 260 million RINs adjusted for our expected internal blending volumes. We also expect to generate approximately 100 to 110 million D4 RINs from renewable diesel, bringing our net RIN obligation for 2022 to approximately 150 million RINs. Our forecast does not include the impact of any waivers or exemptions. Derivative gains for the fourth quarter of 2021 totaled $2 million, which were primarily realized gains associated with Canadian crude oil derivatives. In the fourth quarter of 2020, we had derivative losses of 15 million, which included unrealized losses of $23 million, primarily associated with the crack spread swaps that were closed at the end of the third quarter of 2021. The petroleum segment's direct operating expenses were $4.84 per barrel of total throughput in the fourth quarter of 2021, as compared to $3.99 per barrel in the fourth quarter of 2020. The increase in direct operating expenses was primarily a result of higher personnel expense and increased natural gas prices. For the fourth quarter of 2021, the fertilizer segment reported operating income of $72 million, net income of $61 million or $5.76 per common unit, and EBITDA of $93 million. This is compared to a fourth quarter 2020 operating loss of $1 million, a net loss of $17 million or $1.53 per common unit, and EBITDA of $18 million. The year-over-year EBITDA improvement was driven primarily by higher prices for UAN and ammonia, set slightly by higher feedstock costs and operating expenses. The partnership declared a distribution of $5.24 per common unit for the fourth quarter of 2021. As CBR Energy owns approximately 36% of CBR Partners' common units, we will receive a proportionate cash distribution of approximately $20 million. Total consolidated capital spending for the full year 2021 was $226 million, which included $50 million from the petroleum segment, $26 million from the fertilizer segment and $148 million for the renewable diesel project at Winnie Wood. Of this total, environmental and maintenance capital spending comprised $65 million, including $47 million in the petroleum segment and $16 million in the fertilizer segment. We estimate the total consolidated capital spending for 2022 to be $222 to $251 million, of which $136 to $150 million is expected to be environmental and maintenance capital. and $80 to $90 million is related to the completion of the renewable diesel unit at Winniewood and construction of the pretreater. Our consolidated capital spending plan excludes planned turnaround spending, which we estimate will be approximately $70 to $80 million for the planned turnaround at Winniewood this year and preparing for the turnaround at Coffeyville next year. Cash provided by operations for the fourth quarter of 2021 was $14 million, and free cash flow was a use of $24 million. During the quarter, we paid cash taxes of $37 million and interest of $22 million. Other material uses of cash in the quarter included $15 million for the partial redemption of CVR Partners' 2023 notes and $21 million for the non-controlling interest portion of the CVR Partners' third quarter distribution. Turning to the balance sheet, we ended the year with approximately $510 million of cash. Our consolidated cash balance includes $113 million in the fertilizer segments. As of December 31st, excluding CVR partners, we had approximately $584 million of liquidity, which was comprised of approximately $398 million of cash and availability under the AVL of approximately $361 million, less cash included in the borrowing base of $175 million. During the quarter, CVR partners redeemed another $15 million of its 2023 nine and a quarter senior notes outstanding. Subsequent to year end, CVR Partners redeemed the final $65 million of the 2023 notes that were outstanding. With the debt refinancing completed in June of 2021 and the full redemption of the remaining 2023 senior notes earlier today, CVR Partners' total debt on the balance sheet has been reduced by $95 million, and annual debt service costs will be reduced by approximately $26 million per year, a reduction of over 40%. Looking ahead to the first quarter of 2022, For our petroleum segment, we estimate total throughput to be approximately 185 to 200,000 barrels per day, as winning wood will be running at reduced rates in March during the turnaround. We expect total direct operating expenses to range between 90 and 95 million, and total capital spending to be between 35 and 45 million. For the fertilizer segment, we estimate our ammonia utilization rate to be between 92 and 97% for the quarter. We expect direct operating expenses to be approximately 50 to 55 million, excluding inventory impacts, and total capital spending to be between $4 and $7 million. With that, Dave, I'll turn it back over to you.

Thank you, Dane. In summary, over the course of 2021, we saw a material recovery in the refining market fundamentals. Between the reduction in refining capacity due to announced closures, downtime associated with winter storms and hurricanes, and product demand mostly returning to pre-COVID levels. Product inventories have tightened significantly, which led to a sustained rebound in crack spreads. Unfortunately, RINs remain stubbornly high and continue to drag on refining margins and an unnecessary increase in the price of transportation fuels. Fortunately for CVR, Our rent exposure should be reduced significantly in the near term as we complete the renewable diesel unit at Winniewood, which we currently plan to have online by middle of April and at full rates during the second quarter. Initially, we plan to run a mix of pretreated soybean oil and corn oil, and we currently have feedstock inventories on hand. As a reminder, we expect to generate approximately 170 to 180 million rents a year from this renewable diesel production, which should bring our net RIN exposure to under 100 million RINs per year, assuming no waivers or exemptions. On our last earning call, I discussed our increased focus on renewables and decarbonization. We are pleased to report that our Board of Directors has approved a comprehensive plan to reorganize our company to facilitate the segregation of renewables, including the formation of new entities, and ultimately the transfer of assets. We currently expect to execute this plan over the next 12 months, subject to any required authorizations, and look forward to reporting on milestones as we progress. This step significantly advances the focus on renewables we outlined several quarters ago, and once complete, should provide significant optionality for maximizing value. We also continue to advance various projects. We anticipate the startup of the Winniewood RDU in April and expect to begin reporting a new renewable segment when appropriate. We are co-currently progressing other projects, including the expected installation of a pretreater at Winniewood. We also have engineering design work underway to evaluate a renewable project at the Coffeyville Refinery. which could be potentially larger than the Winneywood refinery and could include sustainable aviation fuel production. We are in discussions with a number of vegetable oil producers as we believe there could be a benefit in partnering with the feedstock supplier in order to have more control and potentially better economics. Overall, our strategy around renewables will be focused on anything that decarbonizes our refining and fertilizer value chains. We'll be return focused and look for the most attractive economics for recovering and sequestering CO2 from various sources we have in our business today to determine how we can build a meaningful business around it. We believe we are uniquely positioned to capitalize on our renewables projects given the synergistic relationship with refining and our proximity to the Farm Bill. Turning back to refining, As I mentioned, we see a significant improvement in refining fundamentals over the past year. Gasoline inventories in the U.S. are currently 4% below five-year averages, and diesel inventories are 20% below five-year averages. Meanwhile, demand for gasoline and diesel is back to pre-COVID levels, and demand for jet is within 15% of pre-COVID levels. Vehicle miles traveled in December of 2021 even surpassed levels during the same month in 2019. We continue to monitor the startup of new refinery capacity globally, which we believe should drive additional refinery closures in Europe and North America over the next few years. Moving on to fertilizer. Our last earning call, we highlighted some of the improvements we've seen in the nitrogen fertilizer business. And those strong market conditions have continued into 2022. Last year, we saw a perfect storm of supply disruptions in both US and globally in a period of strong demand for fertilizer that led to significant increases in prices for ammonia and UAN. Natural gas prices in Europe At nearly $25 per million BTUs, a number of fertilizer facilities remained shut in, while China, Egypt, and Russia continued to restrict exports of fertilizers. The price increases we saw in the fourth quarter are looking firm into spring, and we have a good order book on the first half of 2022 that captured the higher market prices that developed in the fourth quarter. Over the past three quarters, CVR Partners has announced distributions of nearly $10 per unit, which generates nearly $40 million of cash distributions net to CVI's 36% interest. With the financing and pay down of high interest debt, CVR Partners has significantly improved its balance sheet and reduced its annual debt service by $26 million. Looking at the first quarter of 2022, quarter-to-date market metrics are as follows. Group 3 2-1-1 cracks have averaged $18.09 per barrel with a Brent TI spread of $2.93 per barrel and a Midland differential of $1.14 over WTI. The WTL differential has averaged $0.72 per barrel over WTI and the WCS differential has averaged $13.17 per barrel under WTI. Fertilizer prices have held firm after increasing significantly in the fourth quarter, with ammonia prices over $1,200 per ton and UAN prices over $550 per ton. As of yesterday, Group 3-211 cracks were $17.47 per barrel Brent TI was $3.33 per barrel, and WCS was $12.50 under WTI. Assuming the high end of the proposed 2022 RVO, RINs were approximately $7.24 per barrel. EPA's persistent failure to comply with its obligations under the RFS has led to current high RIN prices environments. We were hopeful that EPA would capitalize on the opportunity to fix the situation in setting the 20, 21, and 22 RVOs. Unfortunately, they missed the mark again as RIN prices rose after EPA issued the proposed RVOs in December. Comment periods end in early February for both the proposed RVO and EPA's proposed denial of outstanding small refinery exemption requests. Depending on the final rulemaking by EPA, we are prepared to file suit if necessary to hold EPA accountable to the law. In addition to pursuing small refinery exemptions, we believe Winnie Wood is entitled to per the RFS. may pursue lawsuits regarding EPA's unlawful activities, including its failure to rule on small refinery exemption requests within the mandated time period, failure to provide 16-month settlement window from the time the initial RVOs are proposed, and for damages caused by its unlawful actions and associated impacts to the market. Until these issues are resolved, it is likely continue to carry a RIN obligation on our balance sheet related to Winnie Wood's RIN obligation, as we believe they should be exempt under RFS. We also believe RIN prices will likely moderate in the future, possibly due to pressure from high gasoline prices or from a resolution of the issues I just mentioned. With that, operator, we're ready for questions.

Thank you. At this time, we'll be conducting a question and answer session. If you'd like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star 2 if you'd 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. Our first question comes from the line of Phil Gresh with JPMorgan. Please proceed with your question.

Hey, good afternoon, Dave. Thanks for taking my question. So just stepping back and kind of looking at the fourth quarter results, it seems that Gulf Coast refiners have put up much better margins quarter to quarter than the mid-come. You talked about some of the factors that could be influencing that, but just curious if you think, you know, are those transitory factors in your view or structural factors like rent TI, backwardation, et cetera? So just any thoughts you have there. Thanks.

Sure, Phil. Well, you know, it's not uncommon for the MidCon to go long product during the winter season. It's not only the effect of high RVP, which is allowed under the law, but also just the fact that, you know, with the Brent TI at the numbers it's at, it still has an incentive to, everybody has an incentive to run wide open. And demand typically falls a little bit, although not much, but the production of gasoline goes up dramatically. That and a little bit of the volatility in crude price, you mentioned backwardation, and the fact that there were no real significant refinery interruptions in our market, the basis just kind of blew out and reduced our probability appropriately, therefore. So if you look at the Magellan inventories on gas, they're fairly high right now, and that's seasonally typical. That's the reason we're doing our Winnie Wood turnaround in the first quarter, which is usually the weakest season. I do expect it to recover once demand picks up in the area and the RVP starts to go back down. You know, as far as the Brent TI goes, you know, it's really related directly to the production of shale oil, which is increasing, but not nearly as much as we would have expected at these kind of crude prices.

That's very thorough. Thank you. My follow-up is just around capital allocation. I'm just trying to get my arms around, you know, where CVI is headed here. Because you have, you know, the renewable objectives that could require more capital spending. If you look at Coffeeville or other opportunities, we also are talking about maybe segregating that business. And then, you know, you think about kind of the cash flow generation of the parent company, you know, the RINs liability that's outstanding. So, you know, could you just kind of walk through how you're thinking about cap allocation? Is there a scenario where you'd consider reinstating dividends or buybacks, or do you feel like with these other things that you have on your plate that now is not the right time to look at that.

Well, I think, you know, from a capital allocation, you know, CVI has always been a cash machine. And it's, you know, it's all about cash flow is what we're all about. I think you heard us mention that we spent $435 million complying with, or at least booked it on our balance sheet of rent expense. And when you put that in the equation, it's... it kind of just takes our cash flow to a level we don't really like. So some rectification to RINs has got to happen. And we kind of outlined a lot of the things that we think we're going to take steps on. But that 435 just kind of wipes out anything we can do. Our balance sheet is still strong, however. We're not far from a position of thinking about dividends again, and I know the board talks about it every quarter, and those conversations will continue. As far as breaking out the renewables business, I think the thought here is, and I think we're all starting to see it in this business, if anybody's in a fossil fuel business, is that raising money going forward is going to be difficult. Not to mention that renewables probably commands a little higher multiple. Those two factors, I think, are a lot behind our strategy here of changing our corporate structure and breaking it out where we can raise money under the decarbonization flag and have access to the capital markets where a lot of them are being shut by ESG concerns and other things.

Okay, great. Thanks for your thoughts.

You're welcome.

Thank you. Our next question comes from the line of Manav Gupta with Credit Suisse. Please proceed with your question.

Hey, Dave. Thanks for all the update on the renewable side. I have a question here, you know. Some of your peers and others, what they're doing is as they're building the renewable diesel business, they're bringing in sometimes financial partners who are offering the capex and taking some preferred equity. Other times they're bringing in a feedstock provider who probably is not offering a capex but offering you You know guaranteed supply of feedstock and then taking some part of the profits and I'm just trying to understand as you build this business out visit will it be more like you know it will be your you know do it yourself or are you open to bringing in financial partners or feedstock partners like how do you plan to build this business alone or with partners.

Well, you know, I think we're not real good at sharing, but we probably could in some of these cases. And we're not shutting out that optionality going forward, particularly in the area of bean oil supply or other feedstocks. I think it's, you know, having people with something, you know, a little more dollars in the skin in the game, if you want to say it that way. is not a bad way to go. And we're evaluating several deals, several crushers now that look very promising. And not only that, it's to help us break kind of the monopoly of bean oil, where it's controlled by the three big ag players, and it'll give us a lot more optionality, more like you have with a refining business than you do with the vegetable business itself. So we're not opposed to it, but we haven't found those deals yet.

Okay. And the second question is you talked about a little bit, help us understand some of the factors which are driving these fertilizer prices so high. Is it the fact that, you know, Europe is struggling to make fertilizers with natural gas prices? What are some of the reasons why this high nitrogen or fertilizer price environment could last in 2022 or maybe even 2023?

I think you've got to start with the price of corn and soybeans, Manav. If you look at soybeans, they're approaching $16 a bushel. Corn's over $6. Farmers are pretty flush with incentives to farm. The RFS is broken and continues to put a big demand on corn. If you look worldwide, there's a drought in South America. all factors are leading towards more demand for these two grains, which mainly drives fertilizer. And even though the cost of fertilizer has gone up, most of our customers are more worried about getting allocated supply than they are the price. And the other reasons the price has gone up so much is what I mentioned in the prepared remarks, is the natural gas in Europe is making fertilizer there unprofitable. So about 40% of the of the plants over there are shut down due to economics. And you have China and Russia and Egypt basically hoarding what they're usually exporters, and they're hoarding their production for their own use. So all those factors together, not to mention the winter storm Yuri and hurricanes that shut down a lot of the U.S. production. And the other factor is there was a trade case against Russia and Trinidad that the US won, and there's going to be tariffs on those products, which are probably going to limit imports for the next year or maybe even five years, just because those tariffs are fairly steep. So that's kind of the perfect storm I was referring to.

Perfect. And last, very quick one. I've asked you this before. Looks like EPA is tilting towards declining all SREs. You have fought them before. You've even taken them to Supreme Court and won. So are you guys getting ready for a round two for what you believe is rightfully yours?

Yeah. I mean, the comment period is up on their proposed denial of all small refinery waivers. And I think the responses were pretty dramatic. If I know you, EPA, they'll basically ignore them all and just go like they want to. And the next day, as soon as they deny in the Federal Register all these small refinery waivers, we'll be filing our lawsuit that minute.

Thank you so much.

You're welcome.

Thank you. Our next question comes from the line of Carly Davenport with Goldman Sachs. Please proceed with your question.

Hi, good afternoon. Thanks for taking the questions. Just wanted to start on the decarbonization strategy you mentioned in the prepared remarks. We've talked a lot about the renewable fuels piece, but wanted to get your thoughts on some of the other decarbonization efforts you're considering. Is there anything to share on the CCS side or SAF that you think would be a good fit for your business?

Well, it's early yet, Carly, but what we're looking at is, and I think we're uniquely positioned once again for this, because today we do have, in our fertilizer business, we do sequester CO2 for enhanced oil recovery. We have a pipeline system, and we're connected to a pipeline system that's owned by a third party. But there isn't any reason we can't extend that to both of our refineries and use, recover available CO2 That is out there today. So, for example, I'll give you a couple examples. Like the RD unit at Winniewood that we're building requires the hydrogen plant to run, which makes a 35-40% concentrated CO2 stream, which we can purify further and stick in either that pipeline or a new pipeline getting to it. and sequester that, recover 45 Q credits. Not only that, monetize it in the low carbon fuel standard credit through RD. And that's just one example. We also have a concentrated stream in our FCC stacks of CO2. We could recover those. So there's a slew of stuff there. And there's also a real case to be considered on using hydrogen as fuel instead of natural gas itself. within a refinery that really hits scope one and scope two. We'd like to look at that in some detail and look at building a utility business around that to decarbonize the fuel refineries use. So there's a lot of options here that we think are exciting and we'll be pursuing over the next couple of years.

Great. Thanks for that color and the context. The follow-up was just around backwardation, and you flagged some of the impacts on capture rates there during the quarter. Is that something you're able to quantify, what the impact was on capture in the quarter? Are there any kind of sensitivities you can provide as we think about go-forward captures given the current curve structure?

Well, it's pretty much a one-for-one proposition that comes right off of your crack. So, you know, what right now we're about $1.20, between the $1.20 and $1.50 of backwardation. I would just make the assumption that comes right off the crack.

Great. Appreciate that.

You're welcome.

Thank you. Our next question comes from the line of Matthew Blair with Tudor Pickering Holt. Please proceed with your question.

Hey, good morning. I was hoping you could help us think about fertilizer pricing realizations for the first quarter here. You know, it looks like in Q4 it's only about 60% or so, the benchmarks, and normally you're closer to 80%. I just wonder if we can pencil in 80% for Q1 or if there are some other moving parts we need to take into consideration.

Well, we do have an industrial business that's part of one of our plants that's fairly large. So those are formula prices that take a while to ramp up. As far as the open book goes, most of the stuff that we've booked in the spring and in the early first half of the year, I should say, are all at these higher prices. So you'll see it factor in largely in the first quarter and second quarter. And then it's kind of a question, where does the market go from there? It's not atypical for fertilizer to see a drop in price post the summertime side dress and other activities that farmers do until the harvest occurs and then they start to apply ammonia again. So we think it's still pretty strong, but it's hard to say exactly what will happen in that second half. just because we have the order book is pretty much complete on a vast majority of the ammonia we're going to make and UAN we're going to make in the first half.

Right, right. Okay, sounds good. And then on the RD front, Dave, how would you assess the availability of RBD soybean oil for your upcoming startup? You know, we saw last year where the pricing really blew out relative to the crude soybean oil. So has there been a material improvement in overall supply, or are you kind of watching that, kind of careful on what your startup might do to that RBD market?

Well, you remember, Matt, that we postponed. We could have started this up last year, and we postponed it because the basis for bean oil was so high. It was over 30 cents a pound. It's down in the 40, 14 cents now, and it's kind of maintained there. It took a while for all the trade flows to rebalance, but they have done that now. And it's pretty steady at that, you know, I'll call it 14 to 20 cents, somewhere in that range. And at that point, you know, we're profitable where we're at now, and that's why we're doing the conversion now. I don't see a real big problem with the availability of it. We'll have to look for other feedstocks, as we've always said. And with our pre-treater, it gives us that option. But we've also got a pretty good source of corn oil that is suitable to run without a pre-treater. And it has a little higher basis than what bean oil has, but it's also a lower CI. So with that mix, we feel we can make money in the short haul and offset a lot of ribs.

So if that basis blows out again after you start up your plant, what do you do? Do you shut your plant in response to economics or do you just keep producing until your pre-treater comes on?

Well, we'd probably keep running. But I don't anticipate that happening. Our move is not huge. And some of the others coming on are claiming they're using used oil and tallow and other things. And the fact of the matter is we have about two months of feedstock and inventory. So we're not going to shock the market like it was seen last time.

Great. Thank you.

A lot of these are getting delayed, too, Matt. Some of them are coming on later and later, so that just helps rebalance trade flows.

Right, right. Good point. Thank you for all the color.

Thank you. Our next question comes from the line of Paul Cheng with Scotiabank. Please proceed with your question.

Hey, guys. Good afternoon. Hey, Paul. based on the how the you saying that you're going to reorganize and that probably done by early next year is that means that from a financial reporting you're going to wait until then before you start reporting the out the profit in in your quarterly result or that anyway you will go ahead and start doing that before then and also when you're talking about that becoming a a different business will you be looking at a merchant ld plan outside your refinery location and if and also that when you're looking at future what kind of payback period and irl requirement for those uh investments sure paul and you know the the uh probably the latter first as you know i think you know we

We would look at probably the same return we look at in refining businesses. I think the renewable business is going to be just as competitive as refining, and it's ultimately going to trade that way. So there's really no difference in that from our approach standpoint of that. Your other question on will we be reporting as a separate segment? Yes, as soon as appropriate. We'll have optionality with this restructuring. We don't have to spin it off as a separate company. We can keep it under where we are or we have the option to do that if the market dictates that that should be done. Again, the reason we're doing this is we think renewables commands a higher multiple as well as we're worried as much as anything about financing going forward as more ESG takes heart And, you know, we're already starting to see banks not want to participate in fossil fuel-type businesses. So, you know, that's what we're planning for the future.

And, Dave, when you're looking at this additional R&D plan, I mean, the next one, obviously, you're looking at fossil fuel. And after that, are you guys looking outside your refinery location as a gaswood mill we've Audi or that that's all you're going to look at for Audi and then you will be looking at for basically other opportunities like what you say CSS and other things?

Well, I think a lot of this decarbonization is going to turn into an opportunity of people that want to participate in that value chain as potentially installing this for other plants. and take it in ownership. It's no different than the hydrogen plants today are owned by third parties typically. I can see decarbonization owned by third parties just as alike, and that helps a refiner decarbonize as well as monetizing that through a separate corporation. It's kind of a wide open space.

Okay, and that I just want to go back. You're saying that you could report them as a separate settlement when it is appropriate. That means that is this year that you're going to start up in the second quarter. Should we assume by the second quarter you will start doing it or that it's going to take a number of quarters before you do that?

Well, I think that would be an appropriate time is what I'd call it is to start reporting that as soon as we can get our ducks in a row and have that happen.

okay and um since that your plan always on uh at least for winning which is that once you have the plan and you will have the flexibility for them to switch uh depends on the market condition go back into the conventional refining versus audi making um how how long is the lag effect uh how long it takes in order for you to make that switch uh in terms of that

About 30 days to make the switch once you decide. But the practicality of it is you're going to do it in some kind of cycle. The fact of the matter is you're replacing catalyst on the RD probably every year or less. And that gives you a chance to look at it each time that that happens. Once you put it back in hydrocracker service, you probably want to have a good runway to run it. You're not going to do that without a lot of thought and a whole lot of thought around what the market forward is on refining.

So in practical matter, it's probably not more than once a year. And if you do make the switch, you end up having to be convinced for the subsequent 12 months that you will run in that particular form. Yeah, that's right. And also, can you tell us that Once that you start up the RD, how do we find the Winnie Wood refinery? I think you will reduce the capacity by 19,000 barrels per day. So how's the full put and also the product yield is going to change too?

Yeah, well, you know, that 18,000 barrels is an old number. We've really come back to about, we'll run about 70 at Winnie Wood with RD and we'll go to a light feedstock. accomplish that so what we're after there is naphtha to make hydrogen to to to make uh to make rd with and uh you know that we we're uniquely positioned there because we can go gather those kind of crudes in the field and bring them in with our proprietary pipelines do you have an estimate what is your gas to mean and definite yield will look like after you make the switch yeah well just what you want to go down And that's the main opportunity cost here, because we'll lose the hydrocracker, which is a big distillate maker. So you're going to rely more on cat cracking post-RD than you do today. And you'll see a switch. You'll probably see a loss of 15% or so of diesel yield as a result. Thank you. You're welcome, Paul.

Thank you. Ladies and gentlemen, that concludes our question and answer session. I'll turn the floor back over to management for any final comments.

Again, I'd like to thank you for your interest in CVR Energy. Additionally, I'd like to thank all our employees for their hard work and their commitment towards safe, reliable, environmentally responsible operations. We look forward to reviewing our first quarter 2022 results during our next earnings call. Thank you.

Thank you. This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.