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. 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 at 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 throughout 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 by 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 continuing 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 segment 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 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 the 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 the 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 escalating prices of 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, we remain cautiously optimistic based on the fundamentals we observe. 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 per 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 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 bouncing 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 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. This year's fertilizer market is seeing a combination of supply and demand impacts that have tremendously affected 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 has caused fertilizer facilities to shut-down further reducing available supplies across the globe. As a result, we saw our third-quarter sales price for ammonia and UAN double from a year ago levels, and those prices have continued to increase through the fall. At this point, we think customers are more concerned about securing supply than pricing. The outlook for the nitrogen fertilizer market is very positive through the next year, and we are happy to maintain 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 provides us with unique benefits, and 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. 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 Wynnewood to 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, as it is critical path for the project to be completed. The Board has approved the project, and we estimate 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 opportunities to access a greater pool of investors and financing or potentially position us to take advantage of changes in law that benefit renewable energy. Although we are still in the early stages 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 $1,000 per ton while UAN prices are over $500 per 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 complying 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 the EPA should not grant those exemptions as they have in the past years. With that, operator, we are ready for questions.

Thank you. 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. Congratulations 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 is designed to match the capacity of the renewable diesel unit, which is about 7,300 barrels a day, totaling just under 100 million gallons a year of renewable diesel. It's designed to handle any type of feedstock that we can process, with some limitations, though not many. 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 treated corn oil that is available in the market today that is suitable for processing without pretreating. Once the unit is up, we'll have a steady diet of soybean oil, preferably raw, along with some raw corn oil and some of these treated materials. But then we'll also look in our backyards for waste oils that make sense. We have a long runway to work on that, whether it's yellow grease, white grease, or tallow due to the many ag operations right in our backyard. We don't know exactly what the CI will be, but you can count on us 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 consider the turnaround activity scheduled for next year as well as 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 signal 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 asked frequently 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 this tightness might last. And I think a lot of people wonder if there is a scenario where Brent could go above WTI. I think you'd be pretty well positioned to provide your thoughts on that.

Sure. As I mentioned in the prepared remarks, I think the recovery of shale oil drilling and production is vital to that spread returning to reasonable levels. As I stated, it’s down below $1 right now and Cushing is still losing inventory. If you look at shale oil production right now, the only region showing any growth is Permian. That's directly tied to the Gulf and generally tends to move barrels that way. I think the Permian will have to come to Cushing and to keep it supplied, assuming production doesn't pick up in the other basins. I don't completely understand the overall feeling in the oil space regarding the capital returns shareholders are seeking. But obviously, there's a long runway of very good wells in all locations that aren't being produced right now. Most of what's happening right now is merely ducts being harvested. I don't foresee a trend changing until the world sees higher oil prices, which would force people back to the market to see growth. That said, I don't think there's any danger of Cushing running out; there's plenty of oil there. Exports will have to shut back a bit, resulting in a tighter Brent-TI spread.

Right. So you don't see TI necessarily going above Brent, it's just that we need to disincentivize the exports while the 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 light even with those adjustments versus maybe what others were publishing in their Mid-Con results. So was there anything particular you would highlight in the quarter, or is it just tight spreads and factors like that affecting 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 had in last year, trying to protect against a resurgence of COVID. But that really is the only special item in there. If you factor that $2 back in, we would be around $9 on an adjusted basis, which is pretty close to what most people are achieving.

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, seeking updates there on the conversion. First on the feedstock, we've seen many recent announcements on JVs and private partnerships with publicly traded entities. There seems to be more of those, and given that you're progressing and seem more confident on bringing that unit forward, could you just give us a comment on where you are in terms of discussions with partners about locking down a fixed source of feedstock versus buying on the spot market? 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 the standpoint of soybean oil, we still think soybean oil will be a critical part of the mix due to its abundance. The basis on soybean oil has come down significantly compared to where it was when we were ready to make the conversion. It was trading upwards of $0.30 a pound and is now back in the $0.15 a pound range. Coupled with the HOBO spread improvement, even without pre-treatment, we see renewable diesel margins returning to positive numbers. They aren’t very strong, but still positive and very dependent on what low carbon fuel standard credits do and what RINs do. I believe the margin spread is secure for at least the next year. We will look to backward integrate, and there are numerous cases out there for new crushers that need to be built. We think our location is good for such projects, and we'll seek partnerships to take a position in those projects. Additionally, there are alternatives being looked into from a canola oil standpoint and others, as most parties canola oil or canola seed produces about 40% oil compared to soybeans which produce only 20%. So we have many options to secure 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 some sort of a JV structure or something that would ensure you put a capital investment in order to secure the feedstock there versus just maintaining an offtake contract? It seems like something that's becoming more favored as we see these MoUs in news releases in the headlines. So given all that you have going on, just checking if there is room within the capital framework to consider that?

Yes. I think that's an option on the table. These crushers look like they’re reasonable projects for us, and for backing in the oil space, frankly, one of the problems with the whole waste market for these oils is that it's a thinly traded market with no liquidity. Ensuring the options around that, so we can trade that back and forth between partners and our competitors will be significant, and the more we can do of that, the better. Securing the base supply of oil off a crusher is key to making that happen.

Okay. So last question is just about margins. Several factors are at play here—I know the HOBO spread looks better, but as you noted, part of that is also due to the rally in oil prices and diesel cracks. We expect a supply response which should lead to a normalization on that side. Simultaneously, there's more RD or BPD supply and potential SAS supply coming on stream. So considering all this, how do you assess through-cycle margins for Wynnewood and Coffeyville? Breaking it out into a separate segment, should the margin structure not be favorable for a period of time or if returns are better as a petroleum refiner?

Yes. The major change is that the basis difference remains problematic. The HOBO spread was nearly $3, and now it's trading in the low $2 range. However, the basis is back to positive numbers for renewable diesel. We will take that into consideration and move more in line with economics we initially envisioned for the project. We seek less than a $1 per gallon on a soybean basis, and the more corn we can incorporate, the better the enhancement.

Okay. Thanks. That's super helpful.

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 more on the comment you made regarding the opportunities in carbon capture that you're looking at. Would it be associated with your renewable diesel? Or is that something you're considering on the refining side as well?

Well, I think it's all around the table, Matt is how I would summarize it. The key to our renewable business that we previously discussed is maintaining a broader portfolio beyond just renewable diesel. If we look at our infrastructure in Coffeyville, for instance, we have a recovery system today coming off the fertilizer plant that recovers about three-quarters of a million tons of CO2 per year and is shipped about 60 to 70 miles away to an old oil field for sequestration and crude oil recovery. Since we have that existing infrastructure, we can also recover CO2 from several other refinery streams. One is when renewable diesel starts, while operating a hydrogen plant, we produce a concentrated CO2 stream that we could pump into that recovery system with compression. Additionally, we also have other streams within the refinery that are concentrated CO2 that we could recover for the same purpose and collect 45Q credits that way. Further, we plan to generate renewable propane and renewable naphtha that will help lower CIs and further monetize through renewable diesel at both our refineries. There is a longer runway than just for renewable diesel; we’re looking at any synergy between a refinery and a carbon capture operation that could be installed. I firmly believe these hard-to-decarbonize industries will require some degree of direct air capture of CO2. If there are synergies with low-level heat and other aspects we have at a refinery that would be a logical foundation to develop those systems, we want to be positioned to do that.

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 provided strong Q4 guidance. So, I guess what would you say to investors that might be concerned that refiner discipline is potentially fading 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. It depends on the competitiveness of your assets. If you have marginal assets on the margin, then the discipline applies to those. 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 and West Coast, and I'm assuming they would be highly discounted even versus a couple of years ago. So just trying to understand if you remain interested in raising your refining footprint, considering the stress test evaluations in refining.

Manav, I think I mentioned in the opening remarks that we believe fossil fuels will be necessary for a long time. However, I don't know that all our investment money going forward will go towards the renewable space; the rest 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 operate our renewable diesels. I think that clearly indicates our pivot is more towards renewables and less towards more refining. There are several refineries out there on the market, and they are likely ones that should be on the market or must be shut down. In our opinion, there is probably about 1 million barrels of capacity that lacks the reason to run or produce free cash flow on a five-year turnaround basis. Some additional facilities are being offered for consideration. Our focus remains on renewables.

Perfect. My quick follow-up here is, you are eligible for renewable SREs, but given that the EPA doesn’t always act logically, should they not grant your requests? Would you consider taking legal action as you did last time to obtain the SREs?

We are ready to pursue legal avenues, even to the Supreme Court, if necessary.

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

Hey, Dave. Good afternoon.

Hey, Paul.

When is the EPA supposed to get back to you on your application for the SRE?

They were supposed to respond within 90 days of our submissions. They have yet to do so for any cases. They still have a few days remaining on the 2021 application, but the 2019 and 2020 applications are long overdue. We're debating litigation on those two as well.

So what's the next step? What timeline should we be looking for?

The next step is to follow the lead of other refiners and sue if they don't act shortly. I know of at least two refiners pursuing similar actions. One was slated to receive a ruling on October 22. They had an agreement with the EPA to either grant or deny their waiver, but that got postponed to November 5. That's the next date for those cases. The timeline is that we need to see action, and it's vital the RVOs take the small refinery waivers into account.

What about the pre-treatment unit? Is it still scheduled to come online targeting year-end 2022?

Yes, we expect to complete it in the late fourth quarter of 2022.

How about Coffeyville, assuming you move ahead with FID there, when do you expect it to come online?

Currently, we're just focused on engineering for the Coffeyville conversion and defining scopes and costs. Before we proceed with Coffeyville, we need to secure some assurance of additional market demand for low carbon fuel standards expansion. Approximately 12 states are looking at it, and we need a few to finalize approvals to support the Coffeyville conversion. There are about 7 billion gallons proposed, but only about 1 billion of that service consumes all the credits available in California, Oregon, and Washington. We need more demand to justify that conversion. It’s a possibility that might happen, but the timeline remains uncertain.

Lastly, regarding the turnaround in Wynnewood next year and Coffeyville in 2023, how long will those take, and what sort of impact should we expect during downtime? Also, you mentioned that you no longer have hedging. Did you say that was as of September 30 or the end of the year?

Yes, we put crack positions on for the second and third quarter, and those have all expired. So, we have no hedge on crack going forward, as of September 30. Regarding the turnaround, we originally planned to do Wynnewood in the fall, but we moved it to spring to align with the renewable diesel conversion. This turnaround involves the cat cracker and Alki a number one crude unit for a duration of about 40 days. Coffeyville is scheduled for 2023, focusing mainly on the coker and a crude unit, which should also be in the 30 to 40 day range.

Thanks.

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.

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