CVR Energy Inc.

Greetings. Welcome to CVR Energy Incorporated 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. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. Please note this conference is being recorded. I will now turn the conference over to Richard Roberts, Director of FP&A, and Investor Relations. Thank you. You may begin.

Thank you, Sherry. 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 Newman, 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 assigned under federal securities laws. For this purpose, any statements made during this call that are not statements of historical facts may be deemed to be forward-looking statements. Your caution of 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 10Q 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 recognize 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 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 pretreater at Winniewood 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 to both segments once again posting increases in EBITDA year over year. For our petroleum segment, The combined total throughput for the third quarter of 21 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 in the quarter, and we continued to process WCS at our Coffeyville refinery due to weak WCS prices and cushion. Benchmark cracks increased through the quarter despite elevated rent prices. The Group 3 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 per barrel in the third quarter compared to $2.72 in the prior period. Light product yield for the quarter was 100% on crude oil processed. We continued to optimize refinery operations to ensure maximum capture via maximizing production of distillate and higher margin products, LPG recovery, and rinse 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 continue 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 Antioch 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 a 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 Dave 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 include a positive mark-to-market impact on our estimated outstanding rent obligation of $115 million, unrealized derivative gains of $22 million, and favorable inventory valuation impact of $8 million. As a reminder, our estimated outstanding rent obligation is based on the 2020 RBO 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 break-even 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 written prices and realized derivative losses. In the third quarter of 2021, our petroleum segment's reported refining margin was $15.03 per barrel. Excluding bearable 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 rent 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. RIN's expense excluding marked market impacts reduced our third quarter capture rate by approximately 26% compared to a 22% reduction in the prior period. In total, RIN's expense in the third quarter of 2021 was a benefit of $16 million or 81 cents 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 RIN's 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 RIN's 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 Winningwood's obligations for 2019 through the first nine months of 2021 as we continue to believe Winningwood'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 total $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 30th, we have closed all of our outstanding crack spread derivative positions. The petroleum segment's 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 due 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, a net loss of 19 million, or $1.70 per common unit, and EBITDA of 15 million. There were no adjustments to EBITDA in either period. The year-over-year increase in EBITDA was primarily driven by higher UEN 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 to $223 million, of which approximately $66 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 Winniewood in 2022 and Coffeeville in 2023. Cash provided by operations for the third quarter of 2021 was home $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 30th, we ended the quarter with approximately $566 million of cash. Our consolidated cash balance includes $101 million in the fertilizer segment. As of September 30th, excluding CBR 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 into the fourth quarter of 2021, for our 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 and $100 million, and total capital spending to be between $26 and $30 million. For the fertilizer segment, we estimate our fourth quarter 2021 ammonia utilization rate to be between 90 and 95%, million, excluding inventory and turnaround impacts, and total capital spending to be between $9 and $12 million. With that, Dave, I'll turn it back over to you.

Thank you, Dan. In summary, refinery market fundamentals have steadily improved since summer, and the cracks have responded accordingly. We also saw some relief of 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 RBOs for 20, 21, and 22, as well as issuing small refinery exemptions. Looking at the current market, we remain cautiously optimistic based on the fundamentals we see. Starting with crude oil, OPEC is clearly in the driver's 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 a tightening of the Brent TI spread as Cushing Inductories declined due to shale oil production declines in the Bakken, DJ Basin, and the Anaharko Basin. We continue to believe the resumption of shale oil production growth will be key to a sustained widening in the Brent TI differential. Moving to refined products, demand has 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. The 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 Yuri, 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 double 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're happy to have our 36% ownership in CBR 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 Winnie Wood hydrocracker to renewable diesel service. Given 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 Winniewood to the spring of next year, during which we'll finish the hydrocracker conversion with completion and startup of the renewable diesel unit expected in mid-April. Second, we are progressing the development of a pretreater unit at Winniewood 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 pretreater unit is on order and is critical path for the project to be completed. The board has approved the project and we're currently estimating completion late in the fourth quarter of 22 at a capital investment of approximately $60 million. Third, on the Coffeeville 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. 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 Coffeeville 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 3 2-1-1 cracks have averaged $19.24, with RINs averaging $6.77 on a 2020 RVO basis. The Brent TI spread is averaged $2.52, with the Midland Cushing differential at $0.31 over WTI, and the WTL 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 $1,000 per ton, while UAN prices are over $500 a ton. As of yesterday, Group 3 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 a 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 D4 RENs and immediately rebuild the REN bank, which has been severely depleted. We believe resetting the RVOs at more realistic levels that de-emphasizes 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 complying with the RFS are entitled to relief through small refinery exemptions. We have submitted applications for Winnewood 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're ready for questions.

Thank you. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the queue. You may press star 2 if you would like to remove your question from the queue. And for participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Our first question is from Carly Davenport with Goldman Sachs. Please proceed.

Carly Davenport Hi. Good afternoon. Thanks for taking the questions. The first one is just on the pretreatment 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 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's designed to match the capacity of the renewable diesel unit, which is about 7,300 barrels a day. And that's about a 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 it, 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's 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 this 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 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 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 22.

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 Grace with JP Morgan. Please proceed.

Hey, good afternoon, Dave. Hey, Phil. My first question, I just wanted to get your thoughts on a question we've been 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 the 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 $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, you know, that's directly tied to the Gulf and generally tends to move barrels that way. I do think the Permian is going to have to come to the Cushing to keep it wet. And assuming that production doesn't pick up in these other basins, I don't completely understand, other than it's the current feeling in the oil patches, is that it's 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 ducks are being harvested. And, you know, I don't know that 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, you know, 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 or a little bit light even with those adjustments versus maybe what I would have 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, you know, we're around $9 on an adjusted basis, and 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 Winnie Wood and the updates there on the conversion. First, on the feedstock, I wanted to know, you 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 little bit of comment on where you are in terms of talking to partners or where those discussions are in terms of locking down a fixed source of feedstock versus buying 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 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 abundance. 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 It's now back in that 15-cent-a-pound range. Not that, in combination with the hobo spread improvement, has brought the, even without a pretreater, 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 RENs do, and I think the Bunder's tax credit is fairly assured for at least the next year. So, you know, I think we're going to look at more at backward integrating. There's many cases out there for new crushers that need to be built. And, you know, we think our location is a pretty good one for that. And, you know, we'll look for a call on the oil to take a position in those projects. And, you know, 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 soybeans only producing 20%. So there's a lot of options coming on the table to secure that base supply for not only the Winnie Wood project, but even the Coffeyville project longer term.

David, just a quick thought 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 you know where you put a capital investment in in order to secure the feedstock there versus just a you know an offtake contract that would renew that seems to be something that is getting more favored as we see these MOUs and these releases in the headlines so you know given all that you've got going on just wondering if there's room within the capital framework to think about that

Yeah, I think that's on the table. These crushers look like they're reasonable projects to us. And for a colony oil, I mean, you know, frankly, one of the problems with the whole waste market for these oils is that it's a very thinly traded 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 And, you know, 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 of Crusher is key to making that happen.

Okay. So my last question is just on the margins. It's a bit bigger picture. So a couple things combined here. One, you know, 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, you know, as you expect and I think all of us expect, 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, there's more RD or BBD supply and potentially SAF supply coming on stream. So all else equal, that should be negative or headwind for the hobo spread as we look out maybe past 20, you know, into the back half of 22 or past 22. So when I think about sort of through cycle, for Winnie Wood and potentially for Coffeyville here. Two-part question within that. First, breaking it out in a separate segment, I mean, I know there's optionality that you can flip back to being a petroleum refiner, given the scope and the way you've done the project, but how would that work in terms of breaking it out into a 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 secondly, Just bigger pictures, how do you consider those factors of a compression and 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?

Yeah, well, I think the big change is this basis difference. Bean oil, the hobo spread, it got as almost as wide as $3.00. come back into two, even below two a little bit. But right now, it's still trading in the low twos. 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. It took two quarters, really, to make it happen. But it has subsided. And, you know, will that return? I don't know. Diamond Green is starting up now and supposedly is online. The market saw very little impact from that, maybe a little bit in some of the other oils prices and margins, but it seems to absorb it okay. I think ours will 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, you know, Largely and move into more in line with the economics we originally envisioned with the project. So that's something less than a dollar per gallon on a soybean basis. And throw a little corn oil in 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 the way I'd look at it. I mean, the key to a renewables business that we previously just discussed 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 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, we'll be 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 45 cube credits that way. And we also can monetize it through renewable diesel because we lower the CI when we recover CO2 off the hydrogen system, for instance. And then likewise, there's 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 a longer runway than just plain. The other angle that we'd love to look at is, and we are to some degree, is the any synergies between a refinery and a carbon capture operation that could be installed. There's no doubt in my mind these hard decarbonized industries are going to require some kind of direct air capture of CO2. And if there's synergies with low-level heat, other things that we have at a refinery, that would 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 should it happen.

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 pretty strong guidance for Q4. So I guess, you know, 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 a couple of years ago. So just trying to understand, are you still somewhere interested in raising your refining footprint and given the distressed asset valuations in refining particularly out there?

Manav, I think I mentioned in the opening remarks that we believe fossil fuels will be necessary for a long period of time. On the other hand, I don't know that all our investment money going forward is really around the renewable space. and the rest of it is just sustaining capital to maintain what we have and refining. 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're probably ones that should be on the block or should shut down. In our opinion, there still is probably a million barrels of capacity that doesn't have any reason to run and doesn't really feed cash flow on a five-year turnaround cycle basis. And some more of those are coming up that you're hearing about today.

Perfect.

We're focused on renewables.

Perfect. My quick follow-up here is you are right. You do deserve, you should be eligible for Viniwood 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 Chang with Scotiabank. Please proceed.

Hey, Dave. Good afternoon. Hey, Paul. I don't know if there's an answer. Is there a when that the EPA is 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. They haven't done that in any cases. I think they still have a few days left on the 21 application, but 19 and 20 are long, long gone. And in fact, we're debating litigation on them right now on those two issues also.

So I guess my question is that what's the next step? Because I mean, 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's already two refiners that I know of that have done that. One was supposed to rule on October 22nd. They had an agreement with EPA that they would either grant their waiver or deny it. And that got pushed to November 5th. So that's the next date, and the other ones are just in the beginning throes of litigation. But 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.

We're talking about government, though.

Yeah, I know. It's hard to say. All right.

All right. And that 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 22.

So basically year end 2022. Right. And how about for cost of view?

that assume if you do go ahead and FID when that is supposed to come on stream?

Can you say it again, Paul?

For cost of view, that you're also looking at to convert one of the hydrotreater to a RD. So when that, if you do FID on that, when that's supposed to come on stream?

Well, the 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 and various stages of getting it on the ballot for approval. We need a couple of those to happen to really have the coffee bill conversion. If you just look at the number of gallons that are on the table now, it's close to 7 billion. And, you know, there's only about a 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 will probably happen. It's a good possibility it will happen, but when, who knows.

Sure. And do you have an estimate if you do want to add SAF into Winningwood? Let's say call you 50-50 in the capacity. How much is the capital involved?

Well, for sustainable aviation fuel, all you really have to do is, there's two avenues to it. One is to put a fractionator on the back end and fractionate it 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. Kind of our position on sustainable jet right now 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've got to have substantial subsidies to make that occur. And the airlines, you know, 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 Winnipeg next year and Kosovo in 2023. Can you give us, say, how long the duration of the turnaround and what impact to the output during the downtime. And also you mentioned that you no longer have hedging. I apologize. Did you say that as of September 30 or as of the end of the year that you no longer have those positions?

We put correct 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?

That's right, September 30. As far as the turnarounds go, Paul, we originally were going to do Winnie Wood 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 costs by combining those two together. And that turnaround at Winniewood involves the catcracker and alky and number one crude unit. So it's a good 40-day turnaround to turn those particular units around. And Coffeyville is in 23, but it's just a coker, basically, and a crude unit.

Is that going to be the fall or the spring for cost of things?

For Coffeyville, it'll probably be the fall.

And how many days?

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.

Again, I'd like to thank you all for your interest in CVR Energy. Additionally, I'd like to thank our employees for their hard work and commitment towards safe, reliable, and environmentally responsible operations, especially during this COVID period. We look forward to reviewing our fourth quarter 2021 results in our next earnings call with you all. Have a happy holidays if I don't see you since then.

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