CVR Energy Inc.

Greetings and welcome to the CVR Energy Inc. second 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, Mr. Richard Roberts, Senior Manager of FP&A and Investor Relations for CVR Energy. Thank you. You may begin.

Thank you, Melissa. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy second quarter 2021 earnings call. With me today are Dave Lant, our chief executive officer, Tracy Jackson, our chief financial officer, and other members of management. Prior to discussing our 2021 second 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. Your caution 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 second quarter earnings release that we filed with the SEC in Form 10Q for the period and will be discussed during the call. With that, I'll turn the call over to Dave.

Thank you, Richard. Good afternoon, everyone. Thank you for joining our earnings call. Yesterday, we reported the second quarter consolidated net loss of $2 million and a loss per share of $0.06. Adjusted EBITDA for the quarter was $66 million. Our facilities ran well during the quarter, with both the petroleum and fertilizer segments posting increased adjusted EBITDA year over year. Once again, rising RIN prices were considerable headwinds to our results, including a $58 million non-cash mark-to-market on our estimated outstanding RIN obligation. In May, our Board of Directors approved a special dividend totaling $492 million, comprised of a combination of cash and our interest in Dellick U.S. Holdings. As I have stated over the past few quarters, absent any material acquisitions, We had too much cash on the balance sheet that wasn't earning a return. When we completed the senior notes offering in January of 20, we were evaluating a number of acquisitions at the opportunities at the time and elected to raise additional cash to fund a potential transaction. Since that time, the market has changed significantly. The bid-ask spread for refinery acquisitions remained too wide. The U.S. and Europe are now in a position of excess refining capacity, and we believe more refinery closures are needed. And we are shifting our strategy to focus more on renewables. As a result, in accordance with the provisions of the senior notes, the Board elected to distribute the excess cash proceeds. In addition to providing shareholders with nearly $5 per share of cash and a DELIC stock, this structure also allowed us to recognize a net gain of $87 million that we made on our DELIC investment while providing us with an efficient exit. With the continued uncertainties around RINs and small refinery exemptions, the Board has elected not to reinstate the regular dividends. We'll continue our discussions with the board around the best uses of our cash and the appropriate level of cash to return to our shareholders. For our petroleum segment, the combined total throughput for the second quarter of 2021 was approximately 217,000 barrels per day as compared to 156,000 barrels per day in the second quarter of 2020, which was impacted by a planned turnaround at Coffeyville. Both refineries ran well during the quarter, and we resumed processing WCS at Coffeyville due to the weak WCS prices in Cushing. Benchmark cracks have increased since the beginning of the year. However, elevated RIN prices continue to consume much of that increase in cracks. The Group 3 2-1-1 crack averaged $19.15 per barrel in the second quarter as compared to $8.75 in the second quarter of 2020. On a 2020 RVO basis, RIN prices averaged approximately $8.15 per barrel in the second quarter, a 267% increase from the second quarter of 2020. The Brent TI differential averaged $2.91 per barrel in the second quarter as compared to $5.39 in the prior year period. The Midland Cushing differential was $0.24 over WTI in the quarter as compared to $0.40 per barrel over WTI in the second quarter of 2020. And the WCS to WTI differential was $12.84 compared to $9.45 in the same period last year. Light product yield for the quarter was 99% on crude processed. We optimized crude runs to ensure maximum capture via maximizing premium gasoline production, light product yield, LPG recovery, and rinse generation. In total, we gathered approximately 118,000 barrels a day of crude oil during the second quarter of 2021, compared to 82,000 barrels per day in the same period last year, when production levels were disrupted by low crude oil prices at the onset of the COVID pandemic. We have seen some declines in production of production across our system due to limited drilling activity, although additional rigs were added in both Oklahoma and Kansas during the second quarter. In the fertilizer segment, both plants ran well during the quarter, with consolidated ammonia utilization of 98%. The rally in crop prices has driven a significant increase in prices for nitrogen fertilizers this year, and prices have remained firm through the spring planting season and into summer. Domestic fertilizer inventories are low following the shutdown from winter storm Uri earlier this year, and deferred turnaround activity from 2020 is now taking place. USDA estimates for corn planting and yields continues to imply one of the lowest inventory carryouts in the last 10 years. With low fertilizer inventories and continued strong demand for crop inputs, the setup remains positive. for fertilizer demand as well as pricing. Now let me turn the call over to Tracy to discuss some additional financial highlights.

Thank you, Dave, and good afternoon, everyone. Before I get into our results, I would like to highlight that during the second quarter of 2021, we revised our reporting to include adjusted EBITDA, which excludes significant non-cash items not attributable to ongoing operations that we believe may obscure our underlying results and trends. For the second quarter of 2021, our consolidated net loss was $2 million, loss per diluted share was $0.06, and EBITDA was $102 million. Our second quarter results include a negative mark-to-market impact on our estimated outstanding rent obligation of $58 million, unrealized derivative gains of $37 million, favorable inventory valuation impacts of $36 million, and a mark-to-market gain of $21 million related to our investment in DELIC. Excluding these items, adjusted EBITDA for the quarter was $66 million. The petroleum segments adjusted EBITDA for the second quarter of 2021 was $18 million, compared to negative $1 million in the second quarter of 2020. The year-over-year increase in adjusted EBITDA was driven by higher throughput volumes and increased product cracks, offset by elevated rent prices and realized derivative losses. In the second quarter of 2021, our petroleum segment's reported refining margin was $6.72 per barrel. Excluding favorable inventory impacts of $1.81 per barrel, unrealized derivative gains of $1.87 per barrel, and the mark-to-market impact of our estimated outstanding rent obligation of $2.92 per barrel, our refining margin would have been approximately $5.99 per barrel. On this basis, capture rate for the second quarter of 2021 was 31%, compared to 75% in the second quarter of 2020. REN's expense, excluding mark-to-market impacts, reduced our second quarter capture rate by approximately 30%. Derivative losses for the second quarter of 2021 totaled $2 million, which includes unrealized gains of $37 million, primarily associated with crack spread derivatives. In the second quarter of 2020, we had total derivative gains of $20 million, which included unrealized gains of less than half a million. In total, REN's expense in the second quarter of 2021 was $173 million, or $8.77 per barrel of total throughput, compared to $16 million, or $1.12 per barrel for the same period last year, an increase of over 680%. Our second quarter rent expense was inflated by $58 million from the mark-to-market impact on our estimated RFS obligation, which was mark-to-market at an average rent price of $1.67 at quarter end. Our estimated RFS obligation at the end of the second quarter approximates Winningwood's obligations for 2019 through the first half of 2021, as we continue to believe Winningwood's obligations should be exempt under the RFS regulation. We have applications for small refinery exemptions for Winnie Wood Outstanding with the EPA for 2019 and 2020 and will soon submit for 2021. For the full year 2021, we forecast an obligation based on the 2020 RVO levels of approximately 255 million RINs. This includes RINs generated from internal blending and approximately 19 million RINs we could generate from renewable diesel production later this year, but does not include the impact of expected waivers. the petroleum segment's direct operating expenses were $4.23 per barrel in the second quarter of 2021, as compared to $5.52 per barrel in the prior year period. This decline in direct operating expenses was primarily driven by higher throughput volumes and our continued focus on controlling costs. For the second quarter of 2021, the fertilizer segment reported operating income of $30 million, net income of $7 million, or $0.66 per common unit, and adjusted EBITDA of $51 million. This is compared to second quarter 2020 operating losses of $26 million, a net loss of $42 million or $3.68 per common unit, and adjusted EBITDA of $39 million. The year-over-year increase in adjusted EBITDA was primarily driven by higher UAN and ammonia sales prices. The partnership declared a distribution of $1.72 per common unit for the second quarter of 2021, As CVR Energy owns approximately 36% of CVR Partners common units, we will receive a proportionate cash distribution of approximately $7 million. Total consolidated capital spending for the second quarter of 2021 was $83 million, which included $9 million from the petroleum segment, $4 million from the fertilizer segment, and $69 million on the renewable diesel unit. Environmental and maintenance capital spending comprised $12 million including $8 million in the petroleum segment and $3 million in the fertilizer segment. We estimate total consolidated capital spending for 2021 to be approximately $226 to $242 million, of which approximately $83 to $91 million is expected to be environmental and maintenance capital. Our consolidated capital spending plan excludes planned turnaround spending, which we estimate will be approximately $7 million for the year in preparation for the planned turnaround at Winnie Wood in 2022 and Coffeyville in 2023. Cash provided by operations for the second quarter of 2021 was $147 million, and free cash flow was $54 million. Working capital was a source of approximately $100 million in the quarter, due primarily to an increase in our estimated rents obligation, partially offset by a decrease in derivative liabilities and increased crude oil and refined products inventory valuations. Subsequent to quarter end, we received an income tax refund of $32 million related to the NOL carryback provisions of the CARES Act. Turning to the balance sheet, at June 30th, we ended the quarter with approximately $519 million of cash. As a reminder, the cash portion of the second quarter special dividend paid on June 10 was $242 million. Our consolidated cash balance includes $43 million in the fertilizer segment. As of June 30th, excluding CPR partners, we had approximately $652 million of liquidity, which was comprised of approximately $483 million of cash. and availability under the ABL of approximately 364 million, less cash included in the barring base of 195 million. Looking ahead to the third quarter of 2021 for our petroleum segment, we estimate total throughput to be approximately 190 to 210,000 barrels per day. We expect total direct operating expenses to range between 75 and 85 million and total capital spending to be between 18 and 24 million. For the fertilizer segment, we estimate our third quarter 2021 ammonia utilization rate to be greater than 95%, direct operating expenses to be approximately $38 to $43 million, excluding inventory impact, and total capital spending to be between $9 and $12 million. With that, Dave, I'll turn the call back to you.

Thank you, Tracy. While benchmark cracks increased nearly $3 per barrel during the second quarter, RIN prices increased by nearly the same amount. leaving the underlying margin available to refineries mostly unchanged. Demand trends have been positive for gasoline, diesel, and jet fuel. However, increasing refinery utilization has driven an increase in product inventories as well. We continue to believe further rationalization of refining capacity both in the U.S. and Europe will be required to drive further inventory tightening and sustained rebound of crack spreads. Looking at current market fundamentals adjusted for RINs, cracks have been generally flat since the spring. RIN prices peaked in the second quarter and have declined since the favorable Supreme Court ruling. However, RIN prices remain way too high. Gasoline and diesel demand are within a few percentage points of pre-pandemic levels, although jet remains well below. which continues to weigh on the distillate crack. The return of international travel is key to increasing jet fuel demand, and this should come along with continued growth in vaccinations and loosening travel restrictions, although the recent uptick in COVID cases from the Delta variant may present a near-term risk. However, we remain cautiously optimistic on market fundamentals that we see. Starting with crude oil, Crude oil inventory draws, weak domestic production, and strong exports of light crude have all caused the bread TI spread to narrow. Sour and heavy crude spreads have improved but are still weak, especially for WCS and Canada. We believe European refiners have come to appreciate the quality advantage of the U.S. shale oil and are pulling more imports from the U.S. further to pressuring them. Brent TI spread. Looking at refined products, markets are all oversupplied due to high runs in the face of weak jet demand. Despite refinery closures in the U.S., global refining capacity has actually increased in 2020, and more capacity is preparing to start up in 2021 and 22. More closures are necessary in U.S. and Europe as these new chemical integrated refineries come online. RIN prices remain too high and continue to distort the crack spread for all refiners. With the cost of RINs, cracks are weak at best considering the season. Taking into account RIN costs, interest on debt, SG&A, sustaining capital, and turnaround costs over the cycle, most refineries in the U.S. and Europe are not generating free cash flow at these levels. Construction on the Winnie Wood renewable diesel unit has been progressing as planned. We have reached a point where we are ready to bring the hydrocracker down to complete the final steps of the conversion process. However, renewable diesel feedstock prices have increased considerably, particularly for refined, bleached, and deodorized soybean oil, to a level where the economics do not make sense for us to complete the conversion at this time. We should be ready to take the unit down to complete the conversion in the September timeframe. However, the economics must be favorable based on available feedstocks before we proceed. As we have continually stated, one of the key benefits of our project versus our peers is our ability to run the hydrocracker in either renewable diesel service or traditional petroleum service. Our current plan is to keep the unit in traditional petroleum service for now. As we near the completion of phase one of our renewable diesel strategy, we can continue to develop phase two, which involves adding a pretreatment capabilities for low cost and lower CI feedstocks. We have started the process design engineering on the PTU, which will take approximately three months to complete. We are also completing the process design of potential phase three, of developing a similar renewable diesel conversion project at Coffeyville. The recent spike in renewable diesel feedstock prices, particularly for soybean oil, can likely be attributed to the recent startup of two new renewable diesel plants in the US. As more RD plants are constructed in the US, we expect the feedstock market to react to increasing demand and begin pricing according to low carbon fuel standard credit values and freight economics. We believe RD producers with feedstock contracts expirations coming up will be forced to give up some of the margin they currently enjoy. With the installation of a pre-treating unit, we should have the flexibility to run any type of feedstock that we can access. And we are talking to the variety of feedstock suppliers that are in our backyard. Looking at the third quarter of 2021, quarter-to-date metrics are as follows. The Group 3 211 cracks have averaged $18.75 per barrel, with RINs averaging $7.77 on a 2020 RBO basis. The Brent TI spread has averaged $1.72, with the Midland Cushing differential at $0.14 under WTI and the WTL differential at $0.68 under Cushing WTI. and a WCS differential at $13.04 per barrel under WTI. Ammonia prices have increased to around $600 a ton, while UAN prices are over $300 a ton. As of yesterday, Group 3 2-1-1 cracks were $20.84 per barrel. Brent TI was $1.63, and the WCS differential was $14.45 under WTI. On the 2020 RVO basis, RINs were approximately 840 per barrel. In June, the Supreme Court ruled to overturn the Tenth Circuit Court ruling on small refinery exemptions related to continuity. As we have previously stated, the intent of Congress was that no small refinery should go bankrupt from the impact of RFS compliance and that small refineries like ours with high diesel output, remote location, and lack of meaningful retail and wholesale infrastructure are entitled to relief at any time. The Winnie Wood Refinery was originally granted small refinery exemptions for 2017 and 18, and we do not see any legal reason why its 2017 exemption should not be reinstated and why it should not be granted exemptions for 2019, 20, and 21. Excuse me. In addition to failing to have timely rule on the pending small refinery exemptions, EPA has yet to issue the renewable volume obligation for 2021, despite being more than nine months past their deadline. The recent E15 ruling by the D.C. Circuit makes EPA's decisions around the RVO that much more important given the industry's inability to meet ethanol blending mandates and the pressure that puts on D6 RIN prices. Of course, the best short-term outcome for CVI is for EPA to issue small refinery waivers for qualifying refineries now without reallocation. Other alternatives are to issue a nationwide waiver, substantially reduce the RVO, or cap D6 RIN prices and place emphasis on D4 RINs. I think the best long-term solution for all stakeholders is to decouple D6's RENs from D4's. EPA should act now to reduce the ethanol mandate and increase the renewable diesel and biodiesel mandate. Should also implement a 95 octane standard for all new ICE engines, internal combustion engines, and should harden all ICE internal combustion engines vehicles for E30 or higher. These actions would not only advance the reduction of carbon emissions now, but would also ensure the viability of liquid fuels in the future. With that, we're ready for questions.

Thank you. 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 Manav Gupta with Credit Suisse. Please proceed with your question.

Hey guys, appreciate the comments on the renewable diesel side. I understand that our RDB costs have been moving up pretty significantly. I'm just trying to understand like what would be a good break even. And so the hypothetical question is, let's say you did have a pre-treat and you could use the CDS or soybean oil. Would that be enough for you to turn on the machine or you still need a feedstock prices to be 15, 20 cents discount to where CDSO is trading today to be more on the economical side. If you could help us understand what kind of magnitude would bring you in that green versus break-even or red.

Sure. The biggest problem right now is the basis of bean oil and frankly all other oils. To be able to get the refined bleached and, uh, deodorized, uh, bean oil, you know, you're paying another 28 cents a pound roughly, um, to get it delivered. And that, that right there is, uh, is really the problem. Of course, if you had a pretreater, you could buy untreated beans. The problem with that is, is that all the bean producers are recognized that 28 cent advantage there and that, and they're really not offering a lot of that, uh, that untreated bean oil to the marketplace because they can make more money by refining it. You know, I think what's really happening is that you're seeing all these feedstocks go up in value. They're all approaching basically the raw bean oil price. And the only thing that differentiates them is the CI. And that's when I say that, you know, I believe these things are going to all trade on their CI ultimately, and the producers of the feedstock are going to want to share in that low carbon fuel standard somehow through the CI.

Wow, that's very informative. I had no idea they're holding CDSO and forcing people to buy RBD. I was always wondering why there's such a big discount between the two. So if obviously CDSO is not available, then the screen prices don't matter. My quick follow-up here is, Dave, You highlighted a number of possible fixes, solutions to the RFS. And in your mind where you are, what's the most likely outcome with highest probability right now? Is it SREs? Is it SREs without reallocation? Like, how confident are you that you will get that veiny wood waiver? Clearly, the Supreme Court ruling is in your favor. You should get it. So like where you are sitting, I understand the best case outlook would be get rid of our view and stuff. But like, what's the most realistic probability weighted thing you're looking at, which would help you out?

Well, I think there's some easy streets that EPA could take here. And frankly, I don't know that it's EPA. I think it's really politics at this point. And this is the problem with this regulation. It's easily manipulated by the politicians, as evident by how the last three administrations have administered it. So I think what we hear is that EPA and staffers are waiting for the politics to be decided before they're going to take a course of action. And it's been delayed again. You know, here we are in July, or early August now, and we don't have an RVO for 21. You know, 21 is almost half over, or more than half over. And the due date is still officially March 31st of 2022. You know, the normal process for EPA is to have 16 months between when they declare the the RBO and your actual cashing in or having to render the ribs. So we're way off track here. I think they've got, you know, the Supreme Court really gave them some cover with the other side, I'll call it, the corn lobbies and the RFA groups, to use the small refinery as a way to rebuild the bank. The fact of the matter is, We spent a year here not generating near enough RENs as an industry to even supply the RVO that was a carryover from 2020. In 2020, frankly, RVO was way too high. They had to do something to rebuild the bank somehow, some way, and I think the staffers know that. It's just one of the politics around it. As I've outlined, there's really four ways to deal with it. One, to issue small refiners without reallocation. Two is to do a general waiver, which they can do to all states, which is in the law. And three is to decouple D6s from D4s somehow. You know, the mandate of over 10% on ethanol just does not work. You have to dig into D4s to meet the D6 requirements. And that drives D6s up. So I think the ultimate best solution is for them to really decouple D6s from D4s, make D4s very low, and reduce the mandate on it. We'll do that, or to just cap them somehow. And all those will solve this problem. And frankly, the emphasis of EPA should be on D4s and D3s, which really gives you the big bang for the buck on reducing carbon and fuels. So I don't know how it's so hard, and that last one really helps everybody, including the corn lobby and the renewable fuels associations.

That's fair. Thank you for so much information, Dave. Thank you so much.

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

Hey guys, good afternoon. Dave, you're talking about the green market. Obviously that one possibility is looking to expand into maybe the brand wholesale market. One of your peers just announced a deal that part of the advantage is that they will allow them to get into that business. And the price then seems to be that expensive. Have you guys looked into that option or that you don't think that that fits into you?

Paul, we've been trying to do that for three years, and to get any scale in it is difficult. We really were looking at it from an acquisition standpoint as a key part of our acquisition strategies, but the bid-ask was too wide. We could never, ever get a deal done. So, you know, we've kind of backed off that. We're maximizing our internal generation as all we can. There are talk of Magellan actually revamping their system to allow for 5% biodiesel blending in base diesel, which would help us tremendously. Other than that, we just maximize rack sales all we can, and that's about it. about all we can do at this point.

Right. And I'm just curious. I mean, Dave, I understand you're trying to get into retail marketing or retail station that's extremely expensive. Wholesale marketing, the brand or the drop-in network, at least based on the deal announced this morning, doesn't seem to be that expensive. I mean, of course, they are buying a bunch of things, but collectively, it doesn't seem to be that expensive. Because I think that at one point you guys are actively looking for refining and then you say, okay, you're no longer looking at refining. But will you consider a deal that is a combination of refining but also with the Joppa network or that that's not really something that you want to do, you just want to get, if you're going into an M&A, you're just going into a Joppa network.

not uh with an associated refining well paul we've looked at uh in our current market zone uh you know they're you know we we if we if we tried to go into retail we're competing against our very customers we sell to number one a large volume of but two you know what we've looked at is just the wholesale model and uh you know the margins on that are are one to three cents typical, and you've got to have a pretty good size ability to term up some of these stations, which means you have to have a brand of some sort, generally. And again, we're competing with our very customers we sell to, to a large extent, which does present some interesting issues. But we just haven't been able to make a deal happen. We've looked at several small wholesale people that are that we've gotten close on, but in the final analysis, we were unable to close the deals. We'll keep looking, but I can't, it's not as easy as it sounds if you don't have a brand.

Mm-hmm, I understand. You're saying that you start processing some WCSS cost of view. How much do you plan to process in the third quarter?

We don't typically guide on that. We'll tell you it's in our slate, but we're not going to say how much we run.

Okay. And I mean, you're saying that today the economic doesn't invite you to turn on the renewable diesel plan, even though you're ready. So that's for arguments that I'm just trying to understand that once that that plan come on stream how your profitability compared to your peers, such as Polaris, since they actually report and bring it into a separate segment. So if your plan is actually up and running and you have a pretreatment unit and one through the entire second quarter, what would be your unique EBITDA look like of that operation? Is that any number? that any insight you can share so that we can have a little bit better understand what is the economic of your facility at all?

Well, I think right now I'm telling you that the margins are negative. That's why we're not doing the conversion right now. And part of that is an overheated bean market. I think it just has to rebalance. It takes a couple of quarters for that to occur. But I'll also tell you that all these feedstocks, even the unused cooking oil and all the way through tallow, through yellow grease, white grease, are all up substantially, almost double. And they're following beans just like they are. The other issue is that just look at the availability of the advantage CI feedstocks. If you add them all up in total availability in the United States, it's half what the bean oil volume is. There just aren't very many of them. That includes corn oil. That's tallow. That's yellow grease, white grease. There are just not that many of them. And what I'm saying is that ultimately this low-carbon fuel standard is going to price into those. And the sellers of them are going to understand the value of them, and they're going to extract some of the value. So the Valeros, they have a long runway of feedstock. I'm telling you, we're going after them. And we're going to look at those that are in our backyard, and we're going to look at how we can get away from them.

And based on what you just described, you're still going to go ahead with the treatment unit and also the phase three expansion or that the building, another one in philosophy. So you're still the plan or that you're going to take a pause?

Well, I think we're going to take a, you know, we're going to do the, at least the initial engineering on the Coffeyville conversion, but we're not going to sanction the project yet until we see how these feedstocks sort out and get ourselves in a position to, to tackle the, the, the one we've built already. How about the treatment unit? We'll do a pre-treater, however, for the Winningwood unit.

So anyway, that you will go ahead. But you're not going to size it so that it will be sized for both Winningwood and the coastal field. You're just going to size it for Winningwood.

That's right.

And how much is that going to be if it's just sized to Winningwood?

We're predicting somewhere between $50 and $60 million.

And you're not going to pause on that. You're going to move ahead as planned on that one.

Yeah, we have board approval to basically do the engineering and also buy long lead equipment. I see.

And then when... I'm sorry?

And that's moving ahead.

Okay. And when do you think that the pretreatment unit currently, when you expect that to come on stream?

Well, the best dates we've heard, although we don't have the full scope done yet, is 12 months, but we've advertised 16 to 18 months is what it will take to complete it. They aren't particularly complicated, so it should be, you know, it's somewhere between 12 months and 16 months, I would say.

So we're talking about sometime in the second half of 2022. Right. Probably third quarter.

This is a safe bet.

Okay. Perfect. Thank you.

Thank you. Our next question comes from the line of Phil Gresh with JPMorgan. Please proceed with your question.

Hey, good afternoon, Dave. Always appreciate you being a straight shooter. Thank you.

Well, I guess my question then on all of this is, if everybody is doing a pretreatment unit, How does that not end up being the same where when it gets to be startup time, the economics are negative? Is there something special about putting in a pretreatment unit that will inherently make it more profitable?

Well, the pretreater allows you to do your pretreatment yourself. I remember I said there's about a 28-cent-a-pound basis built into soybean oil right now. And frankly, it's in corn oil, maybe to a little less degree, but pretty similar. So that's what you're attacking. You're going to get some of that basis out, assuming the bean oil producers will make available untreated bean oil, which is an assumption that we're not sure of at this point. If I was them, I would make refined bleached and deodorized all day long because the basis is 28 cents. They pick up a And it probably cost about two cents to treat it. So the crush plants are making a fortune on it right now. And I think the bean oil market's got to rebalance. And beans are kind of critical here because they're the most available feedstock, the biggest production. And that may not be true worldwide, but it certainly is in the United States. And with our access to the mainly to the MidCon and not to the Gulf Coast, West Coast, or East Coast. You know, we have a lot of feedlots around us. We have a lot of rendering plants. We have a lot of ethanol plants not far from us. So, you know, we're going to be working on those feeds that are in our backyard. Right.

And I guess outside of the bean oil and just the feedstock, the CI adjusted parity that you're talking about, I guess, is that something that you would envision, even if it's a charity that's positive, if it's Dow or if it's a feedstock side like what we're seeing right now on bean oil?

Well, it's kind of hard to say. I think it's we're designing to run anything. And obviously, the more the advantage feedstocks lower CI you get, the more profitability you have with the existing low-carbon fuel standard prices in California. You know, I do feel those are a little bit at risk also as more and more of these come on, because we need that market to expand. And not all those will enter in our decisions to do any more renewable diesel in the future. But the market is pretty – there's a lot of announced capacity coming on. A lot of it doesn't have secure feedstock, I'm pretty sure. And we're all going to be facing the same issues on the CI and the absolute bean price. Right.

Okay. All right. Thank you. I'll turn it over. Thank you.

Thank you. Ladies and gentlemen, as a reminder, if you'd like to join the question queue, please press star 1 on your telephone keypad. Our next question comes from the line of Neil Meda with Goldman Sachs. Please proceed with your question.

Hi, good afternoon. This is Carly on for Neil. Thanks for taking the questions. In the prepared remarks, you ran through the 3Q Brent TI averages thus far, and things are still looking pretty tight there. Can you just talk about your views on how Brent TI evolves in the back half of the year and then into 2022?

Sure. I think it all depends on the price of crude. And furthermore, the newfound investment discipline that the E&P seem to have incorporated into their business model. I keep thinking that $70 oil, they're going to throw that out and say, let's drill. But it hadn't happened yet. And I think the Brent TI really depends on they're becoming more and more crude coming out of the shale oils. to force the spread to increase exports. So I imagine it's going to stay in this $2 to $3 range, maybe $1.50 to $3 range for some time. And it's had some volatility to it, but I do strongly believe that the Europeans have figured out what shale oil is and how to run it very effectively to not make any fuel oil. And they're doing that, and then they're exporting the crude or the products right back to the United States.

Great. Thanks for the color there. And then I guess just with the special dividend now completed, can you kind of walk us through the framework around capital allocation? We know you're focused on building out the renewable side of the business, but can you talk about paths for any incremental capital returns or balance sheet uses?

Sure. I think our – Our model is really free cash flow returned to shareholders. We're trying hard to generate free cash flow, except for the investments we're making in renewable diesel, which we think is the new strategic direction of the company. And really, refining may have peaked. I don't know. But it sure feels that way. If you need to trim a few more refineries here and a few more in Europe, And these monsters that are being built in Asia fully integrated with chemicals, the non-competitive refineries need to, frankly, go away. And I think that's our ultimate solution to this situation is there are X RINs. And RINs uncertainty just drives more momentum in the other direction, too. I don't think our capital allocation has changed. Our model is return to shareholders as much as possible, whenever possible, as evident by our 22% yield on yesterday's stock price from the special dividend we just did. The business is by no means, as I mentioned, in a large free cash flow generation with the red price. But it has the potential to be back there very soon if EPA does the right thing.

Great. Thanks for the time.

You're welcome.

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

Again, I'd like to thank you for your interest in CVR Energy. Additionally, we'd like to thank our employees for their hard work and commitment to our safe, reliable, and environmentally responsible operations. We look forward to reviewing our third quarter results during the next earnings call. Thank you. Have a great day.

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