CVR Energy, Inc. (CVI) Q3 2021 Earnings Report, Transcript and Summary

Greetings. Welcome to CVR Energy, Inc. Third 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] Please note this conference is being recorded. I would now turn the conference over to Richard Roberts, Director of FP&A and Investor Relations. Thank you. You may begin.

Thank you, Kerry. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy third quarter 2021 earnings call. With me today are Dave Lamp, our Chief Executive Officer; Dane Neumann, our Chief Financial Officer; and other members of management. Prior to discussing our 2021 third 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 financial measures, including reconciliation to the most directly comparable GAAP financial measures, are included in our 2021 third 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 said, I'll turn the call over to Dave.

Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. Before I get into our results, I wanted to make a few comments about some exciting developments. While we believe fossil fuels will certainly be necessary for many years to come, we recognized that renewable fuels are an important part of the future. For this reason, we began exploring utilizing excess hydrogen capacity at our refineries for renewable diesel production nearly two years ago, and have invested nearly $150 million since on those initiatives. We believe we are uniquely positioned given our transportation and logistical connection to the Farm Belt, and we intend to be in the forefront of this green revolution. We have made progress on several fronts since our last call and are accelerating our efforts with the Board’s recent approval of the feed pre-treater at Wynnewood at an estimated cost of $60 million. I'll provide more details later in the call. Yesterday, we reported third quarter consolidated net income of $106 million and earnings per share of $0.83. EBITDA for the quarter was $243 million. Our facilities ran well during the quarter and continued strength in prices for refined products and nitrogen fertilizer led both segments once again, posting increases in EBITDA year-over-year. For our Petroleum segment, the combined total throughput for the third quarter of 2021 was approximately 211,000 barrels per day as compared to 201,000 barrels per day in the third quarter of 2020, which was impacted by some weather-related power outages. Both refineries ran well during the quarter and we continued to process WCS at our Coffeyville refinery due to weak WCS prices in Cushing. Benchmark cracks increased through the quarter despite elevated RIN prices. The Group three 2-1-1 crack averaged $20.50 per barrel in the third quarter as compared to $8.34 in the third quarter of 2020. Based on the 2020 RVO levels, RIN prices averaged approximately $7.31 per barrel in the third quarter, an increase of 177% from the third quarter of 2020. The Brent-TI differential averaged $2.71 per barrel in the third quarter compared to $2.42 in the prior period. Light product yield for the quarter was 100% on crude oil processed. We continue to optimize refinery operations to ensure maximum capture via maximizing production of distillate and higher margin products, LPG recovery and RINs generation. In total, we gathered approximately 112,000 barrels per day of crude oil during the third quarter of 2021 compared to 124,000 barrels per day in the same period last year. We continued to see some declines in production across our system due to limited drilling activity although, our gathering rates have stayed ahead of overall decline rates across the Anadarko Basin. Some rigs were added in both Oklahoma and Kansas over the past few months, but drilling activity has been slower to increase than we would have expected. In the Fertilizer segment, both plants ran well during the quarter with the consolidated ammonia utilization of 94%. The rally in fertilizer prices that began earlier this year continued to the third quarter with prices breaking normal seasonal patterns and continued to rise through the summer. With low fertilizer inventories and continued strong demand for crop inputs, the outlook remains positive for our Fertilizer segment. Now let me turn the call over to Dane to discuss some of our financial highlights.

Thank you, Dave, and good afternoon, everyone. For the third quarter of 2021, our consolidated net income was $106 million, earnings per share was $0.83 and EBITDA was $243 million. Our third quarter results included a positive mark-to-market impact on our estimated outstanding RIN obligation of $115 million, unrealized derivative gains of $22 million and favorable inventory valuation impacts of $8 million. As a reminder, our estimated outstanding RIN obligation is based on the 2020 RVO levels and excludes the impact of any waivers or exemptions. Excluding the above mentioned items, adjusted EBITDA for the quarter was $99 million. The Petroleum segment’s adjusted EBITDA for the third quarter of 2021 was $43 million compared to breakeven adjusted EBITDA for the third quarter of 2020. The year-over-year increase in adjusted EBITDA was driven by higher throughput volumes and increased product cracks offset by elevated RIN prices and realized derivative losses. In the third quarter of 2021, our Petroleum segments reported refining margin was $15.03 per barrel. Excluding favorable inventory impacts of $0.41 per barrel, unrealized derivative gains of $1.17 per barrel and the mark-to-market impact of our estimated outstanding RIN obligation of $5.94 per barrel, our refining margin would have been approximately $7.51 per barrel. On this basis, capture rate for the third quarter of 2021 was 37% compared to 55% in the third quarter of 2020. RINs expense excluding mark-to-market impacts reduced our third quarter capture rate by approximately 26% compared to a 22% reduction in the prior period. In total, RINs expense in the third quarter of 2021 was a benefit of $16 million or $0.81 per barrel of total throughput compared to $36 million or $1.96 per barrel of expense for the same period last year. Our third quarter RINs expense was reduced by $115 million from the mark-to-market impact on our estimated RFS obligation, which was mark-to-market at an average RIN price of $1.31 at quarter end compared to $1.67 at the end of the second quarter. Third quarter RINs expense, excluding mark-to-market impacts was $99 million compared to $35 million in the prior year period. Our estimated RFS obligation at the end of the third quarter approximates Wynnewood’s obligations for 2019 through the first nine months of 2021, as we continue to believe Wynnewood’s obligation should be exempt under the RFS regulation. For the full-year of 2021, we forecast an obligation based on 2020 RVO levels of approximately 270 million RINs, which does not include the impact of any waivers or exemptions. Derivative losses for the third quarter of 2021 totaled $12 million, which includes unrealized gains of $22 million primarily associated with crack spread derivatives. In the third quarter of 2020, we had total derivative gains of $5 million, which included unrealized gains of $1 million. As of September 30, we have closed all of our outstanding crack spread derivative positions. The Petroleum segments direct operating expenses were $4.52 per barrel in the third quarter of 2021 as compared to $4.17 per barrel in the prior year period. The increase in direct operating expenses was driven primarily by a combination of higher natural gas costs and higher stock-based compensation to the increase in share price. For the third quarter of 2021, the Fertilizer segment reported operating income of $46 million, net income of $35 million or $3.28 per common unit and EBITDA of $64 million. This is compared to third quarter 2020 operating losses of $3 million and net loss of $19 million or $1.70 per common unit and EBITDA of $15 million. There were no adjustments to EBITDA on either period. The year-over-year increase in EBITDA was primarily driven by higher UAN and ammonia sales prices. The partnership declared a distribution of $2.93 per common unit for the third quarter of 2021. As CVR Energy owns approximately 36% of CVR Partners common units, we will receive a proportionate cash distribution of approximately $11 million. Total capital spending for the third quarter of 2021 was $38 million, which included $12 million from the Petroleum segment, 7 million from the Fertilizer segment and $19 million on the renewable diesel unit. Environmental and maintenance capital spending comprised $15 million, including $12 million in the Petroleum segment and $3 million in the Fertilizer segment. We estimate total consolidated capital spending for 2021 to be approximately $208 million to $223 million, of which, approximately $66 million to $73 million is expected to be environmental and maintenance capital. Our consolidated capital spending plan excludes planned turnaround spending, which we estimate will be approximately $4 million for the year in preparation for the planned turnarounds at Wynnewood in 2022 and Coffeyville in 2023. Cash provided by operations for the third quarter of 2021 was $139 million and free cash flow was $76 million. During the quarter, we paid cash taxes of $67 million, which was partially offset by the receipt of a $32 million income tax refund related to the NOL carryback provisions of the CARES Act. Other material cash uses in the quarter included $31 million for interest, $15 million for the partial redemption of CVR Partners 2023 senior notes and $11 million for the non-controlling interest portion of the CVR Partners second quarter distribution. Turning to the balance sheet. At September 30, we ended the quarter with approximately $566 million of cash. Our consolidated cash balance includes $101 million in the Fertilizer segment. As of September 30, excluding CVR Partners, we had approximately $680 million of liquidity, which was primarily comprised of approximately $469 million of cash and availability under the ABL of approximately $370 million less cash included in the borrowing base of $160 million. Looking ahead to the fourth quarter of 2021 for Petroleum segment, we estimate total throughput to be approximately 210,000 to 230,000 barrels per day. We expect total direct operating expenses to range between $90 million and $100 million and total capital spending to be between $26 million and $30 million. For the Fertilizer segment, we estimate our fourth quarter 2021 ammonia utilization rate to be between 90% and 95%, direct operating expenses to be approximately $45 million to $50 million, excluding inventory and turnaround impacts and total capital spending to be between $9 million and $12 million. With that, Dave, I'll turn it back over you.

Thank you, Dane. In summary, refinery market fundamentals have steadily improved since summer, and the cracks have responded accordingly. We also saw some relief for the out-of-control prices for RINs, although prices have risen as the market continues to wait for EPA to act on settling and/or revising RVOs for 2021 and 2022, as well as issuing small refinery exemptions. Looking at the current market remained cautiously optimistic based on the fundamentals we see. Starting with crude oil, OPEC is clearly in the driver seat from a crude price standpoint, inventories have dropped in the U.S. and across the world and backwardation is firmly in place around $12 a barrel over the next year. While we expect to see shale oil production improving at $80 crude, additional Canadian production has been slow to develop despite additional takeaway capacity. Recently, we've seen the tightening of the Brent-TI spread as Cushing inventories declined due to shale oil production declines in the Bakken, DJ. Basin and the Anadarko Basin. We continue to believe the redemption of shale oil production growth will be key to a sustained widening in the Brent-TI differential. Moving to refined products. Demand is largely returned to pre-COVID levels, including demand for jet fuel, which has improved significantly over the past month. Refined product inventories are generally below five-year averages, partially due to some of the downtime on the Gulf Coast from Hurricane Ida. Imports of gasoline and diesel remain high and gasoline exports are back above pre-COVID levels although distillate exports remain low. Looking at crack spreads, distillate cracks are finally coming back and the forward curve is in Contango despite backwardation of crude oil. The question now is whether the benefits of IMO 2020 will come back into play. And that ultimately depends on the shipping, which has been depressed. One area of our business that generally does not get much attention, but is experiencing a significant improvement is our fertilizer business. Fertilizer market this year is seeing a combination of supply and demand impacts that have had a tremendous effect on pricing. On the demand side of the equation, low inventories for corn and soybeans have pushed grain prices higher this year and increased demand for crop inputs. Meanwhile, domestic production of fertilizer has been lower than normal due to plant shutdowns during Winter Storm Uri, heightening turnaround activity in the summer and additional facility shutdowns during Hurricane Ida. Meanwhile, the energy crunch in Asia and Europe have caused fertilizer facilities to shut-in further reducing available supplies across the globe. As a result, we saw our third quarter sales price for ammonia and UAN more than doubled from a year ago levels, and the prices have continued to increase through the fall. At this point, we think customers are not so concerned – not so much worried about pricing as they are about actually being able to get supply. The outlook for the nitrogen fertilizer market is very positive through the next year and we are happy to have our 36% ownership in CVR Partners common units. Turning back to renewables. As I mentioned earlier, we believe the location of our refineries and fertilizer facilities provide us with unique benefits and that we've made progress on several fronts since our last call. First, we are ready to complete the final steps of the conversion of the Wynnewood hydrocracker to renewable diesel service. Give the weakness in soybean oil-based renewable diesel margins over the summer, we elected to keep the unit in traditional petroleum service as refinery margins have been considerably higher. With the recent increase in crude oil and diesel prices, the HOBO spread has improved and the basis for refined bleached and deodorized soybean oil and corn oil has subsided. Our current plan is to move the planned turnaround at Wynnewood to the spring of next year, during which we will finish the hydrocracker conversion with completion and startup of this renewable diesel unit expected in mid-April. Second, we are progressing the development of our pre-treater unit at Wynnewood that should allow us to run a wider variety of lower carbon-intensity feedstocks that should generate additional low carbon fuel standard credits. Long lead equipment for this pre-treater unit is on order and it is critical path for the project to be completed. The Board has approved the project and we are currently estimating completion late in the fourth quarter of 2022 at a capital investment of approximately $60 million. Third, on the Coffeyville project, Schedule A engineering is in process for the renewable diesel conversion with an expected annual capacity of approximately 150 million gallons of renewable fuel per year with an option of up to 25 million gallons of that amount to be sustainable aviation fuels should regulations support it. And fourth, our fertilizer business is progressing its efforts towards monetizing 45Q tax credits for carbon capture and sequestration through enhanced oil recovery activities that are already taking place at its Coffeyville facility. It also continues to explore the production of ammonia certified blue at both of its facilities. In conjunction with all of this, we are currently evaluating breaking out the renewable business as a separate entity. This could potentially provide us with more opportunity to access a greater pool of investors and financing or potentially position us to take advantage of changes in law that benefits renewable. Although, we are still in the early innings of developing our renewable diesel business, we are taking a long-term view and want to prepare for the future as we look to scale up the business. With the potential production of renewable diesel at both refineries, sustainable aviation production at Coffeyville, carbon capture opportunities and other potentials for blue hydrogen production, we believe we have a fairly long runway for developing an impactful business in the green energy space. Our goal is to decarbonize our refining business by growing our renewables business while supplying our customers with competitive fuels they need. Looking at the fourth quarter of 2021, quarter-to-date metrics are as follows: Group three 2-1-1 cracks have averaged $19.24 with RINs averaging $6.77 on a 2020 RVO basis. The Brent-TI spread has averaged $2.52 with the Midland Cushing differential at $0.31 over WTI and the WTI differential at $0.19 per barrel over Cushing WTI, and the WCS differential at $13.56 per barrel under WTI, forward ammonia prices have increased to over a $1,000 per ton while UAN prices are over $500 a ton. As of yesterday, Group three 2-1-1 cracks were $15.65 per barrel, the Brent-TI was $0.66 per barrel and the WCS was $15.10 under WTI. On the 2020 RVO basis, RINs were approximately $6.26 per barrel. As I mentioned earlier, we saw some brief relief in RIN prices in September when rumors circulated about a potential reduction in the 2020 RVO and 2021 RVO that would be set below the original 2020 level. The net effect of these actions if taken would decouple D6s and D4s RINs and immediately rebuild the RIN bank, which has been severely depleted. We believe resetting the RVO at more realistic levels that deemphasizes D6 in favor of D4s, which actually goes much further to reducing carbon emissions is an appropriate step to make. We also continue to believe that small refineries that face disproportionate economic harm in compliant with RFS are entitled to relief through small refinery exemptions. We have submitted applications for Wynnewood for 2019, 2020 and 2021, and see no reason EPA should not grant those exemptions as they have in the past years. With that, operator, we are ready for questions.

Thank you. [Operator Instructions] Our first question is from Carly Davenport with Goldman Sachs. Please proceed.

Hi, good afternoon. Thanks for taking the questions. The first one is just on the pre-treatment unit. Congrats on the progress there. Can you talk about the scope of what was approved with the $60 million of capital? Does that cover a 100% of the expected production at the unit? And are there any early thoughts you can provide around feedstocks or a CI range that you're targeting for the unit?

Sure, Carly. The unit is designed to match the capacity of the renewable diesel unit, which is about 7,300 barrels a day, and that's about little under 100 million gallons a year of renewable diesel. And it's designed to handle any type of feedstock that we can throw at with some limitations, not many, but some. What we're targeting right now is when we start the unit up in April, we'll be running refined, deodorized and bleached soybean oil plus a treated corn oil that’s out in the market today that is suitable for processing without pre-treating. Once the unit is up, we'll have a steady diet of soybean oil. I'm sure, preferably raw and some raw corn oil with it, as well as some of these treated material. But then we'll also look in our backyards for those waste oils that make sense. And we have a long runway to work on that, whether it's a yellow grease, white grease or tallow because there's many of those type of ag operations right in our backyard. We don't know exactly what the CI will be, but you can count on we'll be looking to reduce it as we move forward.

Great. Thank you. And then the second one is just around 2022 CapEx. If you have any early thoughts there as we think about the turnaround activity that's scheduled for next year as well as kind of pacing the pre-treater spend as we move through 2022?

We usually don't release that until the fourth quarter earnings call and we'll defer to that timing to single that to the market.

Great. Thanks for taking the questions.

Our next question is from Phil Gresh with JPMorgan. Please proceed.

Hey. Good afternoon, Dave.

Hey, Phil.

My first question, I just want to get your thoughts on a question you’d be getting a lot about the Brent-WTI spread. How it's been tighter recently? You made some comments about needing to see U.S. crude production pick back up. I'm wondering how long you think that duration of this kind of tightness might last. And I think a lot of people are wondering, is there a scenario where Brent could go above WTI? And I think you'd be pretty well positioned to provide your thoughts on that.

Sure. As I mentioned in the prepared remarks, I think, recovery of shale oil drilling and production is vital to that spread returning to reasonable levels. As I mentioned in the prompt number, it's down below a $1 right now and Cushing is still losing inventory. If you look at the production of shale oil right now, the only region that's really showing any kind of growth at all is Permian. And that's directly tied to the Gulf and then generally tends to move barrels that way. I do think the Permian is going to have to come to the Cushing and just to keep it wet and assuming that production doesn't pick up in these other basins. I don't completely understand the – other than it's – the current feeling in the oil patch is, is that these capital returns that shareholders are looking for. But obviously, there's a long runway of very good wells in all these locations that aren't being produced right now. In fact, most of what's happening right now is just ducts are being harvested. And I don't know whether I see that trend changing until the world sees higher oil prices just to force people back to the market to see this growing. That said, I don't think that there's any danger of Cushing running out. There's plenty of oil there and exports will have to shut back a bit, and that just means a tighter Brent-TI spread.

Right. So you don't see TI necessarily going above Brent, it's just – we need to disincentivize the exports with the tight spread where it is?

Exactly.

Right. Okay. Second question, I guess, just on the results themselves. I know there are a lot of moving pieces to the realized margin in refining, various adjustments and things, one timers, but it did seem like the results on the gross margin were a little bit light even with those adjustments versus maybe what I would've expected or some peers were putting up in their Mid-Con results. So was there anything in particular that you would highlight in the quarter or is it just tight spreads and things like that that you think affected the result?

Well, we did have some derivative losses that I think contributed to what you're seeing. It's probably a little under $2 margin that came off from some crack spreads we did in last year, trying to protect against a reemergence of COVID. But that really is the only special item in there. If you put that $2 back in there over around $9 on an adjusted basis and that's – I think that's pretty close to what most people are going to achieve.

Right. Okay. Thanks a lot.

You're welcome.

Our next question is from Prashant Rao with Citigroup. Please proceed.

Good afternoon. Thanks for taking the question. I wanted to follow-up on Wynnewood, the updates there on the conversion. First on the feedstock, I wanted to know – we've seen a lot of announcements coming out on JVs private partnerships with publicly traded entities. There seems to be more of those and given that you're progressing and seem to be more confident on bringing that unit forward, could you just give us a bit of comment on where you are in terms of talking to partners where those discussions are in terms of locking down a fixed source of feedstock versus buy on the spot market? And I have a follow-up on margin, but I'll leave it there for the first question.

Sure. We are looking at backward integrating and from a standpoint of soybean oil, we still think that soybean oil will be a very important part of the mix just because of its abundant. The basis on soybean oil has come in a lot compared to where it was when we were originally ready to make the conversion. It was trading upwards of $0.30 a pound and it's now back in that $0.15 a pound range, not that in combination with the HOBO spread improvement has brought the – even without a pre-treater back to positive numbers on renewable diesel. They're not very strong, but they're still positive and really dependent on what low carbon fuel standard credits do and RINs do and I think the [indiscernible] crack spread is fairly assured for at least the next year. So I think we are going to look at more at backward integrating, there's many cases out there for new crushers that need to be built. And we think our location is a pretty good one for that. And we'll look for a call on the oil to take a position in those projects. And there are some other alternatives out there that are also being looked at from a canola oil standpoint and others that most people – canola oil or canola seed really produces about 40% oil compared to the soybeans only producing 20%. So there is a lot of options coming on the table to secure that base supply for not only the Wynnewood project, but even the Coffeyville project longer term.

Dave, just a quick follow-up before I ask about the margin. Would you be willing to put capital into this – into some sort of a JV structure or something that where you put a capital investment in an order to secure the feedstock there versus just an offtake contract that would renew that seems to be something that is getting more favored as we see these MoUs in news releases in the headlines. So given all that you've got going on just wondering if there is room within the capital framework to think about that?

Yes. I think that's on the table. These crushers look like they're reasonable projects to us and for a call on the oil, I mean, frankly, one of the problems with the whole waste market for these oils is that it's a very thinly trade market and it just has no liquidity to it. And as more and more refiners get into this business, I think creating the options around that and be able to trade that back and forth between partners and our competitors is going to be important to have. And the more we can do of that the better and getting the base supply of oil off a crusher is key to making that happen.

Okay. So last question is just on the margins, is a bit bigger picture. So a couple things combined here, one, HOBO spread looks better, but as you pointed out, part of that's also because we're getting this rally in oil price and diesel cracks, there will – as you expect, and I think all of us expect this, there will be a supply response, and we should see curves telling us oil is going to come back down. There should be some normalization on that side. At the same time, again, there's more RD or BPD supply and the potential SAS supply coming on stream. So all else equal that should be negative or headwind for the HOBO spread as we look out maybe past 2020 – into the back half of 2022 or past 2022. So when I think about sort of through cycle for Wynnewood and potentially for Coffeyville there, two-parted question within that. First, breaking it out in a separate segment, I mean, I know there is optionality that you can flip back to being a petroleum refiner, given the scope and the way you size that you've done the project, are you doing the project. But how would that work in terms of breaking it out into renewable segment? Should the margin structure not be good for a period of time or revert where it's better to be a petroleum refiner? And then secondly, just bigger picture is that, how do you consider those factors of a compression in HOBO and the HOBO spread as we go out in terms of getting your capital return on the project now what's changed versus when you saw the high prices in the summer and took a pause longer term?

Yes. Well, I think the big change is this basis difference is bean oil is – the HOBO spread was – it got as almost as wide as $3, come back into $2, even below $2 a little bit. But right now it's still trading in the low 2s. But the basis was the big problem before, and that was just, I think, that the trade flows had to rebalance to really bring in the effect of two large RD plants starting up at once. That has subsided and took two quarters really to make it happen, but it has subsided. And will that return? I don't know, Diamond Green is starting up now. And supposedly as online, the market saw very little impact from that, maybe a little bit in some of the other oils prices, but end margins, but it seems to absorb it, okay. I think ours would be the next one to start up. So I think we have that runway. And then once we get the pre-treater, we kind of move into the – take the basis out of the equation largely and move into more in line with the economics we originally envisioned with the project. So that's something less than a $1 per gallon on a soybean basis and throw a little corn on there, you get even a little bit more enhancement.

Okay. Thanks. That's super helpful. Thanks, Dave.

You're welcome.

Our next question is from Matthew Blair with Tudor, Pickering, Holt. Please proceed.

Hey. Good morning, Dave. I was hoping you could expand a little bit more on the comment you made regarding the opportunities in carbon capture that you're looking at. Would that be associated with your renewable diesel? Or is that something you're looking at for the refining side as well?

Well, I think all around the table, Matt is way I'd look at it. I mean that the key to renewables business that we previously just discussed was, is having a portfolio that's more broad than just renewable diesel. And if you look at our infrastructure we have at Coffeyville just for instance, we have a recovery system today coming off the fertilizer plant that recovers about a three quarters of a million tons a year of CO2 that is then shipped, I don't know, 60, 70 miles away to an old oil field that is used to sequester it and recover crude oil. And since we have that infrastructure existing, we have several other streams that exist in the refinery. One is, when renewable diesel starts up while we running a hydrogen plant, which makes a pretty concentrated CO2 stream that we could pump into that same system with compression. Then we also have other streams within the refinery that are concentrated CO2 that we could recover off of it and use it for the same purposes and collect 45Q credits that way. And then we also can monetize it through renewable diesel because we lower the CI when we recover CO2 off the hydrogen for system for instance. And then likewise, there is other avenues that you can do. We're going to make a significant amount of renewable propane and renewable naphtha that can be used to reduce the CIs and again, monetize through the renewable diesel at both refineries. So there's longer runway than just playing. The other angle that we'd love to look at is and we are to some degree is any synergies between a refinery and a carbon capture operation that could be installed. There's no doubt in my mind, these hard decarbonize industries are going to require some kind of direct air capture of CO2. And if there is synergies with low level heat, other things that we have at a refinery that it'd be a logical place to build them. And the regulatory structure doesn't exist today, but it's coming, I think. And we want to be in position to do that. It should have happened.

Great. Thanks for the details. And then looking at your refiner throughput guidance for Q4, I believe the midpoint is up about 4% quarter-over-quarter. Some other refiners have also had pretty strong guidance for Q4. So I guess what would you say to investors that might be concerned that refiner discipline is potentially fading a little bit here?

Well, I think I'd tell them that if you look at our operating history, we never really cut back that much during COVID, we did for maybe a quarter, but then we were right back up into full production. So I think it depends on the competitiveness of your assets. And if you have marginal assets on the margin that the discipline applies to, then you should be cutting back. In our case, we tend to run our refineries wide open all the time, and we have the margin to prove it.

Great. Thank you.

Our next question is from Manav Gupta with Credit Suisse. Please proceed.

Hey, Dave. Last year, you were looking to increase your refining footprint. Obviously things didn't work out. But now if you look around, there are refineries available on the Gulf Coast, West Coast, and I'm assuming they would be highly discounted even versus couple of years ago. So just trying to understand are you still somewhere interested in raising your refining footprint and given the stress test evaluations in refining particularly out there.

Manav, I think, I mentioned in the opening remarks is that, we believe fossil fuels would be necessary for a long period of time. On the other hand, I don't know that we'd – all our investment money going forward is really around the renewable space and rest of it is just sustaining capital to maintain what we have in refining. Even we're probably taking a unique position in the industry because we are cutting refining capacity to be able to make these renewable diesels. And I think that tells you that our pivot is away from more refining and more towards renewables going forward. There are several refineries out there on the block and they are probably ones that should be on the block or should shutdown. In our opinion, there still is probably 1 million barrels of capacity that doesn't have any reason to run and doesn't really free cash flow on a five-year turnaround cycle basis. And some more of those are coming up that you're hearing about today. We're focused on renewables.

Perfect. My quick follow-up here is, you are right, you do deserve, you should be eligible for renewable to SREs and everything, but we kind of know EPA doesn't always act logically and in the unfortunate event, they don't give it to you. Would you take a legal recourse as you did last time to get the SREs? Is that something you would consider again?

We are ready right now to pursue the legal avenues to the Supreme Court if we have to.

Okay. Thank you. Thank you so much, Dave. Thank you.

You're welcome.

Our next question is from Paul Cheng with Scotiabank. Please proceed.

Hey, Dave. Good afternoon.

Hey, Paul.

I don't know your stand answer. Is that – when that the EPA supposed to get back to you on your application for the SRE?

They were supposed to get back to us in 90 days when we submitted them because they haven't done that in any cases. I think they still have a few days left on the 2021 application, but 2019 and 2020 are long, long gone. And in fact, we're debating litigation on them right now on those two issues also, so…

Right. So I guess my question is that what’s the next step? Because I mean that if the government don't come back to you and they just drag on, so what's the next step and what timeline that we should be looking for?

Well, the next step is to do what several other refiners have done is to – if they don't act on them here soon is to sue them over not meeting their deadline per the law. And there is already two refiners that I know haven’t done that. One was supposed to rule on November – or on October 22. They had an agreement with EPA that they would either grant their waiver or deny it and that got pushed to November 5. So that's the next date. And the other ones are just in the beginning throws of litigation. So it's getting to the point where they have to do something and not only from a litigation standpoint, but I don't know how they sent the RVOs without addressing the small refinery waivers at the same time. They have to take some position on it.

Yes. Were you talking about [indiscernible]?

Yes. I know. It's hard to say.

All right. And for the pre-treatment unit, is it still coming up on stream that targeting now is what 2023 or that is late 2022?

We're thinking we'll have it done in late fourth quarter of 2022.

So basically year end 2022.

Right.

And how about for Coffeyville that assume you do go ahead in FID when that is supposed to come on-stream?

Just can you say it again, Paul?

For Coffeyville that you are also looking at to convert one of the hydrotreater to RD. So when that – if you do FID on that, when that's supposed to come on-stream?

Well, only thing we're doing right now on the Coffeyville conversion is just some engineering and defining the cost and getting a scope together. I really think that before we proceed with Coffeyville, we'd need some more assurance of additional market for low carbon fuel standard expansion. There's about 12 states that are looking at it right now to – and in various stages of getting it on the pallet for approval. We need a couple of those to happen to really have the Coffeyville conversion. If you just look at the number of gallons that are on the table now, it's close to 7 billion. And it's only about – 1 billion of that's in service that would consume all the credits that I think California, Oregon and Washington have, and we need just some more demand to go in that program to really make that conversion. We think that'll probably happen. It's a good possibility it'll happen, but when who knows.

Sure. And do you have an estimate if you do want to add SAF into Wynnewood, unless they call you 50/50 in the capacity, how much is the capital in [indiscernible]?

Well, for sustainable aviation fuel, all you really have to do is there is two avenues to it. One is to put a fractionator on the back end and fractionated out of the renewable diesel production. There's about 20% of that available in that with the right catalyst selections. And then the second alternative, if you want to make more is to add another reactor, which is a much more expensive option, but could increase the yield to 80%, 90%, sustainable jet. Our kind of our position on sustainable jet right now is, is that the regulatory environment is not suitable to produce it again. You're taking a $6 oil and shoving it into a $2 market. And you got to have substantial subsidies to make that occur. In the airlines, with the ones we've talked to are not interested in paying more for it. So it has to come with the government subsidies of some sort.

Okay. And my final question is that, you talk about the turnaround in Wynnewood next year and Coffeyville in 2023. Can you give us a – say, how long is the duration of the turnaround and what unit – and what kind of impact to the output during the downtime. And also you mentioned that you no longer have hedging. You said – I apologize, did you say that as of September 30 or as of the end of the year that you no longer at those benefited position?

Yes. We put crack positions on for second quarter and third quarter, and those have all expired. So we have no hedge on crack going forward.

Okay. So as of September 30, right? And that means…

That’s right. September 30.

Okay.

As far as the turnarounds go, Paul, we do have – we originally were going to do Wynnewood in the fall, but we moved it up to spring to match the renewable diesel conversion because there's some synergy between the two we can save on indirect cost by combining those two together. And that turnaround at Wynnewood involves the cat cracker and Alki a number one crude unit. So it's a good 40-day turnaround to turn those particular units around. And Coffeyville is in 2023, but it's just a coker basically in a crude unit. So…

Is that going to be the fall or the spring for Coffeyville?

For Coffeyville, it'll probably be the fall.

And how many days?

It's still about that 30 to 40 days somewhere in that neighborhood.

Thank you.

You're welcome.

We have reached the end of our question-and-answer session. I would like to turn the call back to management for closing remarks.

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Thank you. This does conclude today's conference. You may disconnect your lines at this time and thank you for your participation.