Earnings Call Transcript - CVI Q2 2021

Operator, Operator

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. 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.

Richard Roberts, Senior Manager of FP&A and Investor Relations

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.

Dave Lamp, CEO

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 increases 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 were evaluating a number of acquisition 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 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 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 RIN 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 continue 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.

Tracy Jackson, CFO

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, the 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.

Dave Lamp, CEO

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 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 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 advantage of the US shale oil and are increasing 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 the 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 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 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 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 expiring 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. 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 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, nor why it should not be granted exemptions for 2019, 2020, and 2021. In addition, the 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. The best short-term outcome for CVI is for the 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 D6 RINs from D4s. The 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 internal combustion engines. And should harden all internal combustion engine 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.

Operator, Operator

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

Manav Gupta, Analyst

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 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 soybean oil; would that be enough for you to turn on the machine, or do 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?

Dave Lamp, CEO

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 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 carbon intensity (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.

Manav Gupta, Analyst

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 small refinery exemptions? Is it small refinery exemptions 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 where you're sitting, I understand the best case outlook would be to 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?

David Lamp, CEO

I believe there are straightforward paths the EPA could pursue, but at this point, it seems more about politics than the EPA itself. This regulation can easily be influenced by political maneuvering, as we've seen with the last three administrations. What I observe is that the EPA and its staff are postponing action until political decisions are made, which has caused further delays. It’s now August, and we still do not have an RVO for 2021, which is already more than half over, with the official due date set for March 31, 2022. Typically, the EPA allows 16 months between announcing the RVO and when it needs to be implemented, meaning we are off track. The Supreme Court's ruling seems to have provided some leeway for groups that typically oppose us, using the small refinery issue as a means to rebuild the bank. The fact is we have spent a year not producing enough RINs to cover the RVO carryover from 2020, which was set too high. Therefore, something must be done to rebuild the bank. The staff understands this, but politics complicate the situation. As I see it, there are four main approaches to address this: one is to issue small refiners without reallocation, two is to apply a general waiver to all states as permitted by law, three is to separate D6s from D4s. The current ethanol mandate of over 10% for D6s is ineffective, leading to artificially high D6 prices. The best resolution would be to separate D6s from D4s, lowering the D4 mandate or finding a way to cap it, which could resolve the issue. Ultimately, the EPA should focus on D4s and D3s, which effectively reduce carbon in fuels, benefiting everyone, including the corn lobby and renewable fuels associations.

Manav Gupta, Analyst

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

Operator, Operator

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

Paul Cheng, Analyst

Hey, 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 peers 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 seem to be that expensive. Have you guys looked into that option or do you think that that fit into you?

Dave Lamp, CEO

We've been trying to pursue that for three years, but achieving any scale has been challenging. We initially considered it a key element of our acquisition strategies, but the difference in pricing made it impossible to finalize a deal. As a result, we have shifted our focus to maximizing our internal generation. There is some discussion about Magellan potentially updating their system to facilitate a 5% biodiesel blending in their base diesel, which would be very beneficial for us. Aside from that, we're just concentrating on maximizing our rack sales as much as possible, and that's all we can currently do.

Paul Cheng, Analyst

I understand that you're exploring retail marketing, which can be quite costly. However, it appears that wholesale marketing for the brand or the job network, based on the recent deal, doesn't have such high expenses. While they are purchasing a variety of items, the overall cost still seems reasonable. I'm curious if, at one point, you were considering refining but then decided against it. Would you be open to a deal that combines refining with the job network, or are you focused solely on pursuing the job network without involving refining?

Dave Lamp, CEO

Well, Paul, we've evaluated our current market situation. If we attempt to enter retail, we end up competing with many of the customers we're already selling large volumes to. We've also considered the wholesale model, where the margins typically range from $0.01 to $0.03. To be successful in this area, you really need to have a solid presence at some of these stations, which generally requires having a recognizable brand. Moreover, we face significant competition from our existing customers, which creates some complex challenges. So far, we haven't managed to finalize any deals. We've come close with a few small wholesale partners, but ultimately, we couldn't close those transactions. We'll continue our search, but it's not as straightforward as it may seem without an established brand.

Paul Cheng, Analyst

Understand. You're saying that you started processing some WCS as cost of fuel. How much do you plan to process in the third quarter?

Dave Lamp, CEO

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.

Paul Cheng, Analyst

Okay. You mentioned that the current economics do not encourage you to start the renewable diesel plant, even though you are prepared. For the sake of discussion, I want to understand how your profitability would compare to competitors like Valero, who actually report this under a separate segment. If your plant were fully operational and you had a pretreatment unit active throughout the second quarter, what would the unit EBITDA look like for that operation? Is there any information you can provide to give us a clearer picture of the economics of your facility?

Dave Lamp, CEO

Currently, our margins are negative, which is why we are not proceeding with the conversion at this time. This is partly due to an overheated bean market that needs to rebalance, which typically takes a couple of quarters. Additionally, the prices of various feedstocks, including used cooking oil, tallow, yellow grease, and white grease, have nearly doubled. The availability of advantageous CI feedstocks is limited; when you consider all of them in the U.S., their total availability is only half of the bean oil volume. There simply aren't many available options, including corn oil, tallow, yellow grease, and white grease. I believe that the low carbon fuel standard will add value to these feedstocks, which sellers will recognize and capitalize on. Companies like Valero have a strong supply of feedstock, and we are actively pursuing ways to secure supplies that are closer to us while strategizing to compete for them.

Paul Cheng, Analyst

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 are you going to take a pause?

Dave Lamp, CEO

We will proceed with the initial engineering for the Coffeyville conversion, but we will not approve the project until we assess how the feedstocks are performing. We want to ensure we are ready to address the project we have already built.

Paul Cheng, Analyst

How about the pretreatment unit?

Dave Lamp, CEO

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

Paul Cheng, Analyst

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?

Dave Lamp, CEO

That's right.

Paul Cheng, Analyst

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

Dave Lamp, CEO

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

Paul Cheng, Analyst

All right, and you're not going to pause on that. You're going to move ahead as planned on that one.

Dave Lamp, CEO

Yeah. We have Board approval to basically do the engineering. And also buy long lead equipment. So Paul…

Paul Cheng, Analyst

Got you, and then, when I'm sorry?

Dave Lamp, CEO

And that's moving ahead.

Paul Cheng, Analyst

Okay. When do you expect the pretreatment unit to come online?

Dave Lamp, CEO

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's somewhere between 12 months and 16 months I would say.

Paul Cheng, Analyst

So we're talking about sometime in the second half of 2022?

Dave Lamp, CEO

Right. Probably in the third quarter is a safe bet.

Paul Cheng, Analyst

Okay. Perfect. Thank you.

Operator, Operator

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

Phil Gresh, Analyst

Hey, Good afternoon, Dave. Always appreciate you've been straightforward.

Dave Lamp, CEO

Thank you.

Phil Gresh, Analyst

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?

Dave Lamp, CEO

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 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.

Phil Gresh, Analyst

Right. Outside of bean oil and the feedstock, is the CI adjusted parity something you would expect, even if it's the parity that leads to positive EBITDA on the feedstock side like we're currently experiencing with bean oil?

Dave Lamp, CEO

Well, it's kind of hard to say. I think we're designing to run anything. The more advantageous feedstocks with lower carbon intensity you have, the greater profitability you can achieve under the current low carbon fuel standard prices in California. However, I do believe those prices are somewhat at risk as more supply comes into the market, since we need the market to expand. All of these factors will influence our decisions regarding future renewable diesel production. Currently, there’s a lot of announced capacity expected to come online, but much of it likely lacks secure feedstock. We will all face similar challenges regarding carbon intensity and the overall price of beans.

Carly Davenport, Analyst

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?

Dave Lamp, CEO

Sure. I believe it largely depends on the price of crude oil and the new investment discipline that exploration and production companies seem to have implemented in their business strategies. I keep thinking that at $70 oil, they will decide to start drilling, but that hasn't occurred yet. I think the relationship between Brent and TI will really depend on the increase of crude production from shale oils to widen the spread for exports. Therefore, I expect it will remain within a $2 to $3 range, possibly $1.50 to $3 for a while. It has experienced some volatility, but I firmly believe that Europeans have learned how to effectively manage shale oil production without generating fuel oil, and they are exporting the crude or products back to the United States.

Carly Davenport, Analyst

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 the path for any incremental capital returns or balance sheet uses?

Dave Lamp, CEO

I believe our focus is on returning free cash flow to shareholders. We're working hard to generate this cash flow, excluding the investments in renewable diesel, which we consider the new strategic direction for the company. It seems that refining may have reached its peak, though I'm not certain. If we need to reduce the number of refineries here and in Europe, especially with the large, fully integrated facilities being constructed in Asia, then the noncompetitive refineries should ultimately be phased out. This is the solution we envision. Additionally, uncertainty surrounding RINs creates further momentum in the opposite direction. Therefore, I don't believe our approach to capital allocation has altered. Our strategy remains focused on returning as much as possible to shareholders, as demonstrated by the 22% yield based on yesterday's stock price following the special dividend. While the business is not currently generating significant free cash flow due to RIN prices, it has the potential to return to that state soon if the EPA makes favorable decisions.

Carly Davenport, Analyst

Great. Thanks for the time.

Dave Lamp, CEO

You are welcome.

Operator, Operator

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

Dave Lamp, CEO

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.

Operator, Operator

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