Cvr Energy Inc Q4 FY2021 Earnings Call

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. 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 Neumann, 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. You are cautioned that these statements may be affected by important factors set forth in our filings with the Securities and Exchange Commission and in our latest earnings release. As a result, actual operations or results may differ materially from the results discussed in the forward-looking statements. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise, except to the extent required by law. 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 2021 fourth quarter earnings release that we filed with the SEC and 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 attributed to CVI shareholders. Earnings per diluted share were $0.25 for the full year of 2021. For the fourth quarter, we reported a 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 weighed on our refining results, fertilizer market fundamentals continued to improve and drove another quarter of strong results for CVR’s fertilizer business. Despite the challenges in the refining market in 2021, we continued to focus on safe, reliable operations. We achieved 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 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 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. 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 the prior period. 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 continued 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, 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 Dave 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 $0.14 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 $0.20, and adjusted EBITDA was $109 million. The Petroleum segment's 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 RIN prices. Excluding the mark-to-market impact on our estimated outstanding RFS obligation of $9 million and inventory valuation 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 valuation impacts, unrealized derivative losses, and the mark-to-market impact of our estimated outstanding RIN obligation, our refining margin would have been approximately $6.70 per barrel. On this basis, the 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 RIN prices and a less favorable crude differential, mostly due to the steep increase in the crude oil market. RINs 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 RINs expense does not include the impact of any waivers or exemptions. Our fourth quarter RINs 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 at year-end compared to $1.31 at the end of the third quarter. The full-year 2021 RINs expense was $435 million compared to $190 million in 2020. Our estimated RFS obligation at the end of the year approximates Wynnewood’s obligations for 2019 through 2021 as we continue to believe Wynnewood’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 million to 260 million RINs, adjusted for our expected internal blending volumes. We also expect to generate approximately 100 million 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 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 the fourth quarter of 2020, with an 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, offset 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 CVR Energy owns approximately 36% of CVR 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 Wynnewood. 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 million to $251 million, of which $136 million to $150 million is expected to be environmental and maintenance capital, and $80 million to $90 million is related to the completion of the renewable diesel unit at Wynnewood and the construction of the pretreatment facility. Our consolidated capital spending plan excludes planned turnaround spending, which we estimate will be approximately $70 million to $80 million for the planned turnaround at Wynnewood this year and preparing for the turnaround of 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 segment. As of December 31, excluding CVR Partners, we had approximately $584 million of liquidity, which was comprised of approximately $398 million of cash and availability under the ABL 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, 9.25% 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 185,000 to 200,000 barrels per day as Wynnewood will be running at reduced rates in March during the turnaround. We expect total direct operating expenses to range between $90 million and $95 million, and total capital spending to be between $35 million to $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 million to $55 million excluding inventory impacts, and total capital spending to be between $4 million 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 and downtime associated with winter storms and hurricanes, product demand mostly returned to pre-COVID levels, and product inventories tightened significantly, leading to a sustained rebound in crack spreads. Unfortunately, RINs remain stubbornly high and could continue to drag on refining margins and increase the price of transportation fuels unnecessarily. Fortunately for CVR, our RIN exposure should be reduced significantly in the near term as we complete the renewable diesel unit at Wynnewood, which we currently plan to have online by the middle of April and at full rates during the second quarter. Initially, we plan to run a mix of pre-treated soybean oil and corn oil, and we currently have feedstock inventories on hand. As a reminder, we expect to generate approximately 170 million to 180 million RINs 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 earnings 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, which 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 start-up of the Wynnewood RDU in April and expect to begin reporting a new renewable segment when appropriate. We are concurrently progressing other projects, including the expected installation of the pretreatment facility at Wynnewood. We also have engineering design work underway to evaluate the renewable project at the Coffeyville refinery, which could be potentially larger than the Wynnewood 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 a feedstock supplier in order to have more control and potentially better economics. Overall, our strategy around renewables will focus 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 agricultural belt. 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 fuel is within 15% of pre-COVID levels. Vehicle miles traveled in December of 2021 even surpassed levels during the same period in 2019. We continue to monitor the start-up 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, in our last earnings 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 the U.S. and globally during a period of strong demand for fertilizer that led to significant increases in prices for ammonia and UAN. Natural gas prices in Europe are nearly $25 per million BTUs, and many fertilizer facilities remain shut down due to economics. Meanwhile, China, Egypt, and Russia continue 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 for 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 the Midland differential at $1.14 over WTI. The WTI 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 2-1-1 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. The EPA's persistent failure to comply with its obligations under the RFS has led to the current high RIN prices environment. We're hopeful that EPA will capitalize on the opportunity to fix the situation in setting the 2021 and '22 RVOs. Unfortunately, they missed the mark again as RIN prices rose after the EPA issued the proposed RVOs in December. Comment periods end in early February for both the proposed RVO and the EPA's proposed denial of outstanding small refinery exemption requests. Depending on the final rule making by the EPA, we are prepared to file suit if necessary to hold the EPA accountable to the law. In addition to pursuing small refinery exemptions, we believe Wynnewood is entitled to exemptions under the RFS, and we also may pursue lawsuits regarding EPA's unlawful activities, including its failure to rule on small refinery exemption requests within the mandated time period and failure to provide a 16-month settlement window from the time the initial RVOs are proposed, as well as damages caused by its unlawful actions and their associated impacts on the market. Until these issues are resolved, it is likely we will continue to carry a RIN obligation on our balance sheet related to Wynnewood’s RIN obligation, as we believe they should be exempt under the RFS. We also believe RIN prices will likely moderate in the future, possibly due to pressure from high gasoline prices or from the 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. Our first question comes from the line of Phil Gresh with JP Morgan. Please proceed with your question.

Hey. Good afternoon, Dave. Thanks for taking my question.

Hi, Phil.

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-over-quarter than the Mid-Con. You talked about some of the factors that could be influencing that. Just curious if you think are those transitory factors in your view or structural factors like Brent-TI, backwardation, etc. So just any thoughts you have there? Thanks.

Sure, Phil. It's not unusual for the Mid-Con to experience extended product runs during the winter months. The combination of higher RVP, as permitted by regulations, along with the current Brent-TI incentives means that there is motivation for everyone to operate at maximum capacity. Generally, demand decreases somewhat, although not significantly, while gasoline production increases substantially. Additionally, the volatility in crude prices you've pointed out, such as backwardation, coupled with the lack of major refinery disruptions in our market, resulted in a significant increase in our base, which appropriately affected our profitability. Therefore, if you examine the Magellan gasoline inventories, they are relatively high right now, which is typical for this season. This is why we are planning our Wynnewood turnaround in the first quarter, typically the weakest time of the year. I anticipate a recovery once demand rises in the area and RVP decreases. Regarding Brent-TI, it is primarily linked to the production of shale oil, which is rising, but not as markedly as we would have predicted given the current crude prices.

Got it. That's very thorough. Thank you. My follow-up is just around capital allocation. I'm just trying to get my arms around where CVI is headed here because you have the renewable objectives that could require more capital spending. If you look at Coffeyville or other opportunities, we also are talking about maybe segregating that business? And then you think about cash flow generation of the parent company, and the RINs liability that's outstanding, so could you just kind of walk through how you're thinking about capital allocation? Is there a scenario where you 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?

From a capital allocation standpoint, CVI has always generated substantial cash flow, which remains a priority for us. We previously mentioned that we allocated $435 million towards RIN expenses, impacting our cash flow negatively. This situation underscores the need for adjustments to the RINs. We've identified various steps to address this issue, but that $435 million significantly limits our financial flexibility. Nevertheless, our balance sheet remains robust, and I believe we are approaching a point where we can consider dividends again. The board discusses this each quarter, and those discussions will persist. As far as breaking out the renewables business, the thought here is, and I think we're all starting to see it in this business; anybody in fossil fuel businesses that raising money going forward is going to be difficult, and 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 a 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.

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 updates on the renewables side. I have a question here. Some of your peers are building the renewable diesel business; they are bringing in financial partners who are offering the CapEx and giving some preferred equity. Other times, they are bringing in a feedstock provider who probably is not offering CapEx but guaranteeing you supply of feedstock, thus taking some part of the profits. I'm just trying to understand as you build this business out, will it be more like you do it yourself, or are you open to bringing in financial partners or feedstock partners? How do you plan to build this business, alone or with partners?

Well, 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 moving forward, particularly in the area of bean oil supply. I think having people with a little more dollars in the game is not a bad way to go, and we're evaluating several deals, including several crushers that look very promising. Not only that, it's to help us break kind of the monopoly of bean oil where it's controlled by three major ag players, and it will give us much more optionality than you have with the 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 Europe is struggling to make fertilizer 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?

Well, 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, and corn is over $6; farmers are flush with incentives to farm, and the RFS is broken and continues to put a big demand on corn. If you look worldwide, there is a drought in South America. All factors are leading toward more demand for these two grains, which mainly drive fertilizer demand. Even though the cost of fertilizer has gone up, most of our customers are more worried about getting allocated supply than the price. The other reasons the price has gone up significantly are what I mentioned in the prepared remarks: natural gas in Europe has made it unprofitable to make fertilizer. About 40% of the plants over there are shut down due to economics. Additionally, you have China, Russia, and Egypt hoarding their usual exports for their own use. All these factors combined, not to mention the impacts from Winter Storm Uri and hurricanes that shut down a lot of U.S. production, create a perfect storm.

Perfect. And last, very quick one, I've asked you this before. It looks like the EPA is tilting towards declining all SREs. You have fought them before; you even took them to the Supreme Court and won. So are you guys getting ready for 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. I think the responses were dramatic. If I know the EPA, they'll ignore them all and just go like they want. The next day, as soon as they deny in the Federal Register all these small refinery waivers, we will be filing our lawsuit immediately.

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. You’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?

It's still early, but we believe we are in a good position for this. In our Fertilizer business, we currently sequester CO2 for enhanced oil recovery and have a pipeline connected to a third party. We see no reason we can't extend this to both of our refineries and utilize available CO2. For instance, the RD unit at Wynnewood that we're constructing requires the hydrogen plant, which produces a 35% to 40% concentrated CO2 stream that we can further purify and send through either that pipeline or a new one to sequester the CO2 for 45Q credits. Additionally, it generates value through low-carbon fuel standard credits via R&D, which is just one example. We also have a concentrated CO2 stream in our FCC stacks that we can recover. There are numerous exciting options we plan to explore over the next couple of years.

Great. Thanks for that color and the context. The follow-up is just around backwardation, and you flagged some of the impacts on capture rates 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 sensitivity 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 right now, we're about $1.20 to $1.50 in backwardation. I would just make the assumption that that will come right off the crack.

Great. I 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 realization for the first quarter here. It looks like in Q4 it was only about 60% or so of the benchmarks, and normally you're closer to 80%. Just wondering 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. 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 the early first half of the year are all at these higher prices. So you'll see it factor in largely in the first quarter and second quarter. Then it's kind of a question of where does the market go from there? It's not atypical for fertilizer to see a drop in price post-summer time-side dress and other activities that farmers do until the harvest occurs and then they start applying ammonia again. 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 that is pretty much complete on a vast majority of the ammonia and UAN we're going to make in the first half.

Great. Okay. Sounds good. And then on the R&D front, Dave, how would you assess the availability of RBD's soybean oil for your upcoming startup? 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 supplier, or are you kind of watching that carefully on what your start might do to that RBD market?

Well, you remember, Matt, that we postponed—we could have started this up last year and we postponed because the basis for bean oil was too high; it was over $0.30 a pound. It's down to around $0.14 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 $0.14 to $0.20 somewhere in that range. At that point, we're profitable where we're at now, and that's why we're doing the conversion now. So 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. With our pretreater, it gives us that option, but we've also got a pretty good source of corn oil that is suitable to run without a pretreater, and it has a little higher basis than what bean oil has, but it has also a lower CI. So with that mix, we feel we can make money in the short haul and offset a lot of revenue.

So if that basis blows out again after you start your plant, do you shut the plant in response to economics, or do you just keep producing until your pretreater comes on?

Well, we probably keep running, but I don't anticipate that happening. Our move is not huge. Some of the others coming on are claiming they're easing used oil and tallow and other things. 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, Matt. Some of them are coming on later and later. So that would just help rebalance trade flows.

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.

I think you are saying that you are going to reorganize and that it's partly done by early next year. Does that mean that from a financial reporting perspective, you're going to wait until then before you start reporting the RBD profit in your quarterly results? Or will you go ahead and start doing that before then? Also, you mentioned that it's going to become a different business. Will you be looking at merging the plant outside of your refinery location, and also when you're looking at the future, what comp payback period and IRR requirement do you have for those investments?

Sure, Paul. The probably the latter. First, as I think we would look at probably the same return we look at in our refining businesses. I don't view the renewable business as different. I think it'll be just as competitive as refining, and it'll ultimately trade that way. So there's really no difference in that from our approach standpoint. Your other question on what we were 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 could keep it under where we are, or we have the option to do that if the market dictates that should be done. Again, the reason we're doing this is we think renewables command a higher multiple, and we're worried, as much as anything, about our financing going forward as more ESG takes hold, and we're already starting to see banks not want to participate in fossil fuel-type businesses. So that's what we're planning for the future.

And Dave, when you're looking at even anticipation of your RD plan, I mean, the next one, obviously, you're looking at the cost of you. Are you looking at how to integrate inside your refinery location as a good potential, or are you going to look at for RD and then also look at other opportunities like CCS and other things?

Well, I think a lot of this decarbonization is going to turn into an opportunity for people that want to participate in that value chain, potentially installing us for other plants and taking an ownership; it’s no different than the hydrogen plants today, which are typically owned by third-parties. I can see decarbonization owned by third-parties just as easily, and that would help us refiner decarbonize as well as monetizing that through a separate corporation. We have a wide-open space.

Okay. And then I just wanted to go back: you said you could report them as a separate segment when it is appropriate. That means that this year, you're going to start up in the second quarter. Should we assume by the second quarter, you will start doing it, or is it going to take a number of quarters before you do that?

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

Okay. Since you're planning on at least for Wynnewood, once you have the plan, you’ll have the flexibility for them to switch depending on the market conditions to go back into conventional refining versus RD? What’s the lag effect? How long will it take for you to make that switch?

About 30 days to make the switch once you decide, but practically speaking, you're going to do it in some kind of cycle. The fact is, once you put the hydrocracker service back in, you probably want to have a good runway to run it. So you're not going to do that without a lot of thought and careful consideration of what the market forward is on refining.

So in practical terms, it's probably not more than once a year. If you make the switch, you must be convinced for the subsequent 12 months that you will run in that particular form?

Yeah, that's right.

And could you tell us, once you start up the RD, how will the Wynnewood refinery be impacted? I think you will reduce the capacity by 19,000 barrels per day. How will the throughput and product yield change?

Yeah. Well, that 18,000 barrels is an old number. We've really come back to around 70 at Wynnewood with RD, and we'll go to a like feedstock to accomplish that. What we're after there is naphtha to make hydrogen to make RD with, and we are uniquely positioned there, because we can gather those kinds of crudes in the field and bring them in through our proprietary pipelines.

Do you have an estimate of what your gasoline and business view will look like after you make the switch?

Yeah. The distillate yield won't go down, and that's the main opportunity cost here, because we will lose the hydrocracker, which is a big distillate maker. You’ll likely see a loss of about 15% of the diesel yield as a result.

Thank you.

You're welcome, Paul.

Thank you. Ladies and gentlemen, that concludes our question-and-answer session. I will 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, and 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.