CVR Energy, Inc. (CVI) Q2 2021 Earnings Report, Transcript and Summary

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. [Operator Instructions] 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 Lamp, 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. 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 second quarter earnings release that we filed with the SEC and Form 10-Q 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 in adjusted EBITDA year-over-year. However, 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 Delek US 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 2020, we evaluated a number of acquisitions -- we were evaluating a number of acquisition opportunities at the time and elected to raise additional cash to fund the potential transaction. Since that time, the market has changed significantly. The bid-ask spread for refinery acquisitions remained too wide. The US 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 on -- 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 Delek stock, this structure also allowed us to recognize a net gain of $87 million that we made on our Delek 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 dividend. 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 continued to consume much of that increase in cracks. The Group three 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 RINs 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 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 Delek. Excluding these items, adjusted EBITDA for the quarter was $66 million. The Petroleum segment's 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 RINs 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 RIN 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. RINs expense excluding mark-to-market impact 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 $0.5 million. In total RINs 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 RINs 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 RIN price of $1.67 at quarter end. Our estimated RFS obligation at the end of the second quarter approximates Wynnewood's obligations for 2019 through the first half of 2021 as we continue to believe Wynnewood's obligation should be exempt under the RFS regulation. We have applications for small refinery exemptions for Wynnewood outstanding with the EPA for 2019 and 2020 and we'll 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 million to $242 million, of which approximately $83 million 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 Wynnewood 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 RINs obligation, partially offset by a decrease in derivative liabilities and increased crude oil and refined products inventory valuation. 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 CVR 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 borrowing base of $195 million. Looking ahead to the third quarter of 2021 for our petroleum segment, we estimate total throughput to be approximately 190,000 to 210,000 barrels per day. We expect total direct operating expenses to range between $75 million and $85 million and total capital spending to be between $18 million 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 million to $43 million, excluding inventory impacts and total capital spending to be between $9 million 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 the refinery utilization has driven an increase in product inventories as well. We continue to believe further rationalization of refining capacity both in the US and Europe will be required to drive further inventory tidy 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 remained 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 on 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 Brent-TI spread to narrow. Sour and heavy crude spreads have improved, but are still weak especially for WCS in Canada. We believe European refiners have come to appreciate the quality of -- quality advantage of the US shale oil and are playing more imports from the US further pressuring the 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 US, global refining capacity has actually increased in 2020 and more capacity is preparing to start up in 2021 and 2022. More closures are necessary in US 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 US and Europe are not generating free cash flow at these levels. Construction on the Wynnewood 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 time frame. 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 either renewable diesel service or traditional petroleum service. Our current plan is to keep the unit additional petroleum service for now. As we near the completion of Phase 1 of our renewable diesel strategy, we continue to develop Phase 2, which involves adding 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 3 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 start-up 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 a 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 2-1-1 cracks have averaged $18.75 per barrel with RINs averaging $7.77 on a 2020 RVO 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 the 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 $8.40 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 Antenna 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 Wynnewood refinery was originally granted small refinery exemptions for 2017 and 2018, and we do not see any legal reason why its 2017 exemption should not be reinstated and why it should not be granted should – why it should not be granted exemptions for 2019, 2020 and 2021. In addition to failing – to have timely rule on the pending small refinery exemption, 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 to 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 D6s RINs from D4s. EPA should act now to reduce the ethanol mandate and increase the renewable diesel and biodiesel mandate. It 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. [Operator Instructions] Our first question comes from the line of Manav Gupta with Credit Suisse. Please proceed with your question.

Hey, guys. I appreciate the comments on the renewable diesel side. I understand that RBD costs have been moving up pretty significantly. I'm just trying to understand like what would be a good breakeven. And so the hypothetical question is, let's say you did have a pre-treat and you could use the CDSO soya bean oil would that be enough for you to turn on the machine, or you still need feedstock prices to be $0.15, $0.20 discount to where CDSO is trading today to be more on economical side? If you could help us understand, what kind of magnitude would bring you in that green versus breakeven or red?

Sure. The biggest problem right now is the basis of bean oil and frankly all other oils. The -- to be able to get the refined bleached and deodorized bean oil, you're paying another $0.28 a pound roughly to get it delivered. And that right there is really the problem. Of course, if you had a pretreater, you could buy untreated beans. The problem with that is -- that all the bean producers recognize that $0.28 vantage there and they're really not offering a lot of that untreated bean oil to the marketplace because they can make more money by refining that. 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 thing that differentiates them is the CI. And that's when I say that 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 Wynnewood waiver? Clearly, the Supreme Court ruling is in your favor. You should get it. So like where you're sitting, I understand the best case outlook would be get rid of RVO 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 and as evident by how the last three administrations have administered it. So we're -- 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. Here we are in July -- or really August now. And we don't have an RVO for 2021. 2021 is almost half over or more than half over. And the due date is still officially March 31, 2022. The normal process for EPA is to have 16 months between they declare the RVO and your actual cashing in or having to render the RINs. So we're way off track here. I think they've got -- the Supreme Court ruling 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 spend a year here not generating near enough RINs as an industry to even supply the RVO that was a carryover from 2020. 2020 frankly RVO was way too high. So they have to do something to rebuild the bank somehow someway. And I think the staffers know that. It's just one of the politics around it. And as I've outlined there's really four ways to deal with it. One to issue small refiners, do it 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. The mandate of over 10% on ethanol, it just does not work. You have to dig in D4s to meet the D6 requirement and that drives D6s up. So I think the ultimate best solution is then for -- 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 what -- 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 Cheng with Scotiabank. Please proceed with your question.

H, guys. Good afternoon. Dave, you're talking about the Wynne market, and obviously, that one possibility is looking to expand into maybe the brand wholesale market. One of your peer just announced a deal that part of the advantage is that they will allow them to get into that business. And the price doesn't seems to be that expensive. Have you guys looked into that option or that you don't think that that fit into you?

Paul, we've been trying to do that for three years. And it's -- to get any scale in it is difficult. We really -- we were looking at it from an acquisition standpoint as a key part of our acquisition strategies. But we -- bid-ask was too wide we can never ever get a deal done. So we've kind of backed off that. We're maximizing our internal generation is all we can. There are talk of Magellan actually revamping their system to allow for a 5% biodiesel blending in their -- in the base diesel which would help us tremendously. Other than that we just maximize rack sales all we can. And that's 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 job network at least based on the deal and now this morning doesn't seems to be that expensive. I mean that the of course that they are buying a bunch of things. But collectively it doesn't seems to be that expensive. So are you -- because I think that at one point you guys is 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 job network or 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 job network not with an associated refining?

Well, Paul, we've looked at in our current market zone there -- we if we try to go into retail we're competing against our very customers we sell to number one a large volume of. But two what we've looked at is just the wholesale model. And the margins on that are $0.01 to $0.03 typical. And you've got to have a pretty good sized 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 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 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.

Understand. You're saying that you start processing some WCS as cost of fuel. 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 can -- I mean you're saying that today, the economics doesn't entice you to turn on the renewable diesel plan even though you are ready. So let's -- for argument's sake I'm just trying to understand that once that that plan come on stream how your profitability comparing to your peers such as Valero, seems that they actually report and bring 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 unit 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 the margins are negative. That's why we're not doing the conversion right now. And that -- 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 used cooking oil and all the way through tallow, through yellow grease, white grease are all up substantially almost double. And you're following beans, just like they are. The other issue is that, just look at the availability of the advantaged, 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. They're -- I mean they're just not that many of them. And what I'm saying is that, ultimately this low carbon fuel standard's 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 it away from them.

And based on what you just described, you're still going to go ahead with the pretreatment unit and also the Phase three expansion or the billion another one in Coffeyville? So it's still the plan, or that you're going to take a pause?

Well, I think we're going to take -- we're going to do 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 tackle the one we've built already.

How about the pretreatment unit?

We'll, do a pretreated, however for the Wynnewood unit.

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

That's right.

And how much is that going to be? Do you need to just size to Wynnewood?

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

All right, 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. So Paul…

Got you, 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, while we don't have the full scope done yet is 12 months. But we've advertised 16 months to 18 months, as what it will take to complete it. They aren't particularly complicated. So it should be -- 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 in the third quarter 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've been a straight through.

Thank you.

Well, I guess, my question then on all of this is if everybody is doing a pretreatment unit. How does that 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 it was about a $0.28 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. And if I was them I would make a refined bleach to deodorize all day long because the basis is $0.28. They'd pick up – and it probably cost about $0.02 to treat it. So there – the crush plants are making a fortune on it right now. And I think the bean oil markets 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 Mid-Con and not to the Gulf Coast West Coast or East Coast, 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 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 the parity that – positive EBITDA over [Indiscernible] on the 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 advantaged feedstocks lower CI, you get the more profitability you have with the existing low carbon fuel standard prices in California. 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 then 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.

[Operator Instructions] Our next question comes from the line of Neil Mehta 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&Ps seem to have incorporated into their business model. I keep thinking at $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 there 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 has -- 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 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 path for any incremental capital returns or balance sheet uses?

Sure. I think, 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 is probably -- 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 with -- fully integrated with chemicals, the noncompetitive refineries need to frankly go away. And I think that's our ultimate solution to this situation is their ex RINs. And RINs uncertainty just drives more momentum in the other direction too. So, I don't think our capital allocation has changed. It's -- our model is returned to shareholders, as much as possible whenever possible as evident by our 22% yield on yesterday's stock price that -- 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 RIN price. But it has the potential to be back there very soon if EPA does the right thing.

Great. Thanks for the time.

You are 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.