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Greetings, and welcome to the CVR Energy Fourth Quarter 2023 Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Richard Roberts, Vice President of Financial Planning and Analysis and Investor Relations. Thank you, sir. You may begin.

Thank you, Christine. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy fourth quarter 2023 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 2023 fourth quarter and full year 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 from 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. This call also includes various non-GAAP financial measures. The disclosures related to such non-GAAP measures, including reconciliation and the most directly comparable GAAP financial measures, are included in our 2023 fourth quarter earnings release that we filed with the SEC and Form 10-K 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. For the full year of 2023, we reported a consolidated net income of $878 million, earnings per share of $7.65 and an EBITDA of $1.4 billion. At the segment level, we generated $1.2 billion of EBITDA in the Petroleum segment and $281 million of EBITDA in the Fertilizer segment. Fourth quarter consolidated income was $97 million and earnings per share were $0.91. EBITDA for the quarter was $204 million. Despite year-over-year declines in cracks, crack spreads and fertilizer prices in the fourth quarter we posted another quarter of solid results driven by lower RIN expenses, higher utilization of our assets and reduced operating costs mainly due to lower natural gas and electricity prices. We are pleased to announce the Board of Directors has authorized a fourth quarter regular dividend of $0.50 per share, which will be paid on March 11 of 2024 to shareholders of record at the close of the market on March 4. For the full year of 2023, the Board authorized regular and special dividends of $4.50 per share for a total payout ratio of approximately 64% of free cash flow generated for the year. In the Petroleum segment, combined total throughput for the fourth quarter of 2023 was approximately 223,000 barrels per day of crude. Crude utilization for the quarter was approximately 97% of nameplate capacity and light product yield was 103% on crude oil process. Benchmark cracks softened during the fourth quarter with Group 2-1-1 averaging $23.66 per barrel. The bulk of the decrease was from the third quarter came from the decline in distillate crack, which was driven in part by increased inventories as the U.S. refining fleet run hard through the winter. RIN prices declined from extremely elevated levels we have seen over the past few years averaging $4.67 per barrel for the fourth quarter, although they are still too high. We were pleased with our favorable ruling from the Fifth Circuit Court of Appeals in November holding that EPA’s denial of the Wynnewood Refinery company’s small refinery exemptions for 2017 through 2021 were permissibly retroactive contrary to the law and arbitrary and capricious. The Fifth Circuit vacated those denials and remanded our small refinery exemptions back to EPA which has yet to act. In addition to our lawsuits against EPA, we recently sent EPA a petition for rulemaking demanding they cure the violation of the renewable fuel standard, which we believe clearly requires that only obligated parties who over comply with their RFS obligations can sell those excess RINs to other obligated parties. Instead, unlike every other credit program in EPA history, EPA allows anyone to buy, generate, and sell RINs, including non-obligated parties who exploit the RIN market for profit. Allowing this activity harms not only small and merchant refiners, but also the American consumer, who by EPA’s own admission paid the ultimate cost of the RFS through higher prices at the pump. EPA has not responded yet to our petition, and if they don’t, we will see them, once again, in court. For the fourth quarter of 2023, we processed approximately 18 million gallons of vegetable oil feedstock in our renewable diesel unit at Wynnewood. The HOBO spread improved from the third quarter, primarily due to declines in soybean oil prices. However, this was more than offset by the decline in D4 RIN prices and a weaker basis for California diesel. In the Fertilizer segment, both facilities ran well during the quarter with a consolidated ammonia utilization of 94%. Relative to our prior year period, fertilizer prices were lower, primarily due to lower natural gas prices and the return of some European nitrogen facility production capacity that had been curtailed. Demand was strong for the fall ammonia application, and despite softening in grain prices, we believe farmer economics remained favorable at these fertilizer prices. Now, let me turn the call over to Dave to discuss our financial highlights.

Thank you, Dave, and good afternoon, everyone. For the fourth quarter of 2023, our net income attributable to CVI shareholders was $91 million, earnings per share was $0.91, and EBITDA was $204 million. Our fourth quarter results include an unfavorable inventory valuation impact of $90 million, unrealized derivative gains of $67 million, and a reduction to quarterly RINs expense due to a mark-to-market impact on our estimated outstanding RFS obligation of $57 million. Excluding the above mentioned items, adjusted EBITDA for the quarter was $170 million, and adjusted earnings per share was $0.65. Adjusted EBITDA on the Petroleum segment was $153 million for the fourth quarter with lower RINs costs, high utilization rates, and reduced operating expenses, somewhat offsetting the year-over-year decline in crack spreads. Our fourth quarter realized margin, adjusted for inventory valuation, unrealized derivative losses, and RIN mark-to-market impacts was $12.91 per barrel, representing a 55% capture rate on the Group 3 2-1-1 benchmark. RINs expense for the quarter, excluding the mark-to-market impact, was $65 million, or $3.19 per barrel, which negatively impacted our capture rate for the quarter by approximately 14%. The estimated accrued RFS obligation on the balance sheet was $329 million at December 31, representing 362 million RINs mark-to-market at an average price of $0.91. This was down significantly from the RFS obligation on the balance sheet at the end of 2022, of 692 million, comprised of 397 million RINs marked at an average price of $1.74. In addition to the decline in the price of RINs, we also reduced the outstanding balance through RIN purchases, blending activities, and additional RIN generation from the renewable diesel unit. As a reminder, our estimated outstanding RIN obligation excludes the impact of any small refinery exemptions. Direct operating expenses in the Petroleum segment were $4.69 per barrel for the fourth quarter compared to $5.52 per barrel in the fourth quarter of 2022. The decrease in direct operating expenses was primarily due to lower natural gas and electricity costs. Adjusted EBITDA on the Fertilizer segment was $38 million for the fourth quarter with increased sales volumes and lower natural gas and electricity costs somewhat upsetting the decline in prices relative to the prior year period. The Board of Directors of CVR Partners’ general partner declared a distribution of $1.68 per common unit for the fourth quarter of 2023. As CVR Energy owns approximately 37% of CVR Partners common units, we will receive a proportionate cash distribution of approximately $7 million. Cash used in operations for the fourth quarter of 2023 was $36 million and free cash flow was a use of $94 million. Significant uses of cash in the quarter included $201 million for the CPI third quarter regular and special dividends, $70 million of RIN purchases, $58 million of capital and turnaround spending, and $22 million of cash taxes and interest. Total consolidated capital spending for the full year of 2023 was $197 million, which included $108 million in the Petroleum segment, $29 million in the Fertilizer segment, and $56 million on the pretreatment unit for the RDU. Turnaround spending was approximately $60 million in 2023. For the full year 2024, we estimate total consolidated capital spending to be approximately $225 million to $250 million and turnaround spending be approximately $60 million to $70 million. Turning to the balance sheet, we ended the quarter with a consolidated cash balance of $581 million, which includes $45 million of cash in the Fertilizer segment and excludes the funds reserved for redemption of our 2025 notes. During the quarter, we completed a $600 million senior unsecured notes offering with a 5-year term and an 8.5% coupon. The proceeds of which were recently used to redeem the $600 million of senior unsecured notes due in 2025 at par. Total liquidity as of December 31, excluding CVR Partners was approximately $784 million, which was comprised primarily of $535 million of cash and availability under the ABL facility of $249 million. Looking ahead to the first quarter of 2024, for our Petroleum segment, we estimate total throughput to be approximately 190,000 to 205,000 barrels per day, which will be impacted by the planned turnaround at Wynnewood in the quarter. We estimate direct operating expenses to range between $100 million and $110 million, total capital spending to be between $40 million and $45 million, and turnaround spending to be between $35 million and $40 million. For the Fertilizer segment, we estimate our first quarter 2024 ammonia utilization rate to be between 86% and 91%, which will be impacted by some planned downtime at Coffeyville in the quarter. We estimate direct operating expenses to be approximately $52 million to $57 million, excluding inventory impacts, and total capital spending to be between $9 million and $13 million. For the renewable diesel unit, we estimate first quarter 2024 total throughput to be approximately 6 to 10 million gallons, which will be impacted by a catalyst change in the quarter. We estimate direct operating expenses to be between $8 million and $12 million, and total capital spending to be between $10 million and $14 million. With that, I will turn it back over to Dave.

Thank you, Dane. In summary, CVR Energy had another strong year with strong contributions from our petroleum and fertilizer businesses. While the refining market was very strong for most of the year, we saw conditions soften towards the end of the year, and we remain cautiously optimistic about the near-term outlook. Starting with refining, overall refining product demand in the U.S. is down to start 2024 compared to pre-COVID levels and 5-year averages. Year-to-date gasoline demand is down approximately 7%, and distillate demand down almost 12% compared to the same period of 2019. Meanwhile, inventories of refined products have increased, with gasoline inventories up 2% and distillate inventories up 5% compared to a year-ago levels. In Group 3, the demand trends are a little better, with year-to-date gasoline demand down about 5% compared to 2019, and distillate demand up almost 8%. However, gasoline and diesel inventories in Group 3 have increased over 30% from a year-ago levels. Despite the weakness in gas cracks in the fourth quarter, the incentive to blend butane over the winter drove the refining fleet to run hard and led to a swell in inventory levels. As we approach the change in RBP season in the spring, elevated turnaround activity across the fleet and low inventories of summer grade gasoline could drive a normalization of inventory levels and offer some upside for summertime gas cracks. Although vehicle miles traveled in 2023 increased year-over-year, this is somewhat offset by increases in fuel efficiency as the new vehicle fleet miles per gallon has also increased. The EPA estimates new vehicle fuel efficiency increased by approximately 1.5 miles per gallon in 2023 with additional increases expected in 2024 and 2025. Real world gains will probably be lower, but as the fleet turns over, we expect the increases in miles per gallon may further increase offsets in vehicle miles traveled. On the diesel side of the equation, the reduction in supply that was expected from Russian export ban never materialized as trade flows adjusted and Russian volumes found homes in other countries. The mild winter in Europe also led to a decline in natural gas prices, which contributed to an overall decline in gas cracks as well. We continue to monitor the planned start-up of several large-scale refineries around the world expected this year, although historically these types of projects tend to commence lower and later than expected. Further delays in start-ups and a pick-up in economic and industrial activity, especially improvement of the Cass Freight Index, could provide upsides for diesel cracks this year. Looking at crude oil, commercial crude inventories are near the bottom of the 5-year range. Although if you include the Strategic Petroleum Reserve, inventories continue to set new 5-year lows. Crude oil production in the U.S. continues to increase with the average production volumes for 2023 increasing over 600,000 barrels per day compared to 2022. Crude oil exports remain steady around 4 million barrels per day, and we continue to believe the incremental barrel produced in the United States will need to clear the market via exports. We think this dynamic, along with elevated freight rates amid the ongoing conflicts in the Middle East, is supportive of a wider breadth TI differential, which has averaged over $4.50 per barrel for 2023. Volumes in our gathering systems averaged over 140,000 barrels per day in 2023, an increase of 18,000 barrels per day compared to 2022. We continue to see meaningful benefits on cost and capture rates in our system by buying crude at the wellhead and we continue to work to increase the volumes of our gathering systems and reduce our purchases of Cushing WTI. All that said, the U.S. refining fleet has the highest average complexity, lowest natural gas cost, and for inland refineries, the lowest crude cost relative to other refiners around the world. As demand moderates for refined products in the U.S., we believe product exports will grow and crude exports will continue to increase from the harvesting of shale oil formations. Of course, all of this requires the government to allow free markets to work. In our Fertilizer segment, production was strong at both facilities in 2023 as a result of the turnarounds completed in 2022, and we set multiple new production and shipping records at both facilities. Full demand for ammonia application was the strongest we have seen in recent years. Although grain prices have pulled back with the recent decline in fertilizer pricing, we believe farmer economics remain attractive. And we currently expect another period of strong demand in the upcoming spring planting season. At our Coffeyville Fertilizer Facility, we have been conducting engineering studies on the potential to utilize natural gas as an alternative feedstock, which would reduce our purchases of third-party coke. We believe by making certain modifications to the plant, we could utilize either feedstock to produce nitrogen fertilizer. If the project is approved by the Board and successfully implemented, it gives the ability to choose the optimum feedstock mix and will be the only nitrogen fertilizer plant in the United States with that flexibility. Our new pretreatment unit at our renewable diesel unit was mechanically completed at the end of the first quarter, and we should begin processing feed through the unit in the coming days. We plan to complete the next catalyst change at the renewable diesel unit over the next few weeks, while we undertake planned turnaround work at the Wynnewood Refinery. Our current plan for the balance of the year is to run at a slightly reduced throughput rate of the RDU in an effort to optimize catalyst life and increase product yields. As we have talked in previous call, we are continuing to evaluate opportunities for renewables expansions, particularly into the SAF production at both Wynnewood and Coffeyville. On the potential Wynnewood project, we plan to begin soliciting bids over the next few months for offtake agreements that would support the potential conversion of the existing RDU to 100% SAF. On a potential larger project, we are evaluating at Coffeyville, we currently expect to have preliminary engineering and cost estimating work complete by the end of the first quarter. Our current plan is to approach the market in the second half of 2024 to solicit bids for partners to invest in the construction of a renewable diesel and sustainable aviation fuel facility near Coffeyville with a capacity of up to 500 million gallons per year. We believe there is interest in the market for this projects like this, and ultimately our Board approval of the project will depend on our ability to find partners willing to fund the cost of construction. We are also making progress on several margin enhancing projects at the refineries. During the upcoming turnaround at Wynnewood, we planned to complete tie-in work for the diesel yield improvement project with final completion and start-up expected in the first half of 2025. For the diesel improvement project at Coffeyville, we currently plan to complete tie-in work on one-half of the project in 2025 with completion and start-up currently expected in 2026. We are also working with a partner to utilize a transload facility at the Coffeyville location that they are constructing to increase our capacity to send gasoline, diesel, and jet via rail due to higher prices in regions to the west. And finally, the alkylation project at Wynnewood remains on track for completion in 2026. Once completed, this project is intended to increase gasoline production by 2,500 barrels per day, reducing the sale of propylene in addition to eliminating the use of HF acid at the Wynnewood Refinery. If successfully completed, we believe these projects combined would increase our overall margin capture by 4%. Looking at the first quarter of 2024 quarter-to-date metrics are as follows: Group 2-1-1 cracks have averaged $16.35, with the Brent TI spread at $5.25 per barrel, and the WCS differential of $18.63 per barrel under WTI. Prompt fertilizer prices are $500 to $550 per ton for ammonia and $270 to $280 per ton for UAM. As of yesterday, Group 2-1-1 cracks were $19.55 per barrel, Brent TI was $4.16 per barrel, and WCS was $17.35 under WTI. RINs were approximately $2.93 per barrel. With that, operator, we’re ready for questions.

Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Thank you. Our first question comes from the line of Neil Mehta with Goldman Sachs. Please proceed with your question.

Hey, Dave. Hey, team. Thanks for taking the time.

Sure, Neil.

The first question I had is just around the return of capital. Last year you guys had a great year in terms of $4.50 in terms of cash dividends. How do you think about the role of a special dividend in 2024 in the context of the refining outlook that you outlined on the call?

Well, it’s hard to predict at this point, Neil. I think our regular is probably safe without much doubt. Specials, as we’ve said before, it’s really – it takes extraordinary cracks for us to generate specials, and maybe they’ll come back, maybe they won’t. It’s hard to say at this point.

Yeah, understood. And then, just a little bit of your perspective on the crude markets. We’ve talked a lot about the cracks here, especially in the mid-continent over the last couple of weeks, but just as you look at the underlying differentials, whether it’s TI Brent, whether it’s WCS, what are you spending time thinking about as it relates to crude spreads, and how do you see those evolving over the year?

Well, I think, I’ve said this many times, the U.S. fleet is probably saturated with light crude. And I don’t see many investments to really change that trajectory. There were a couple of condensate splitters built that could help a heavy oil refiner process more shale oil, but no new projects have been announced that I know of. And I think that bodes well for exports, which bodes well for the Brent TI, especially when you look at the freight rates have gone up substantially with the Red Sea issues that are occurring in the Middle East. As far as WCS goes, of course, we have, no doubt, there’s a new pipeline coming on going west that’s substantially increased. I don’t see that making a whole lot of impact on at least our business. It will allow more, less rail to leave Canada. But, the tariff out there is really large, and there’s a lot of constraints on shipping and transloading going off the West Coast. So I still see it really not impacting us a whole lot.

Thanks, Dave. I appreciate the time.

You’re welcome.

Our next question comes from the line of Matthew Blair with Tudor, Pickering. Please proceed with your question.

Hey, good morning. Circling back to the return of capital question, it looks like you will start 2024 with some excess cash in the balance sheet. Do you think that that would help augment the special dividend outlook for 2024? Or do you need to save that cash for other uses, whether it’s M&A or this potential Coffeyville RD and SAF project?

Well, Matt, I think our point of view is that we have a little bit more cash on the balance sheet just because we have a RIN short that’s out there in the past. And our main strategy has been as to keep our rating where it is with the rating agencies. And that requires probably a little more cash just to compensate for it. But as RIN prices drop that liability is dropping rapidly. So, the Board will look at dividends every quarter. And, we’ve always set a minimum cash of just to basically stay out of our revolver on crude days and other events that occur in the business like turnarounds around $450 million, $500 million, and we plan to stay in that range.

Sounds good. And then on the potential Wynnewood conversion to SAF, do you have a cost estimate for that project? I think one of your peers was in like the $1.30 to $1.40 per gallon range. Do you think you’d be in a similar ballpark on that? And then do you have – I guess, would you expect to be able to tap non-U.S. SAF markets? If you did go through with that project, looks like European SAF premiums are a lot stronger than what we might see in the U.S. And so, would that be an opportunity for you?

Yeah, we’re looking at all the above. I mean, we’ve had a lot of interest in this, a lot of people approach us on this. And, it’s a conversion that can be done rather rapidly, although it does require another reactor to be added to the system. I would say we’re in that ballpark, what you suggested in terms of capital, the dollar. I think, ours would be probably $1 to $1.40 range somewhere in there. And, yeah, there’s a lot of interest coming from Europe, Canada, and West Coast on SAF in general. What our approach on this is maybe a little different than others. We are kind of insisting we want offtake agreements that negate the uncertainty of government subsidies. So anything we structure will be such that we pretty much guarantee a margin that will justify the capital we would put in should we execute the project. As far as you mentioned a little bit of capital reserve for the Coffeyville project. We do not plan on putting any capital in that project. If we can’t find partners that are willing to fund the construction with us donating or basically to not donating, but as part of the transaction would put our renewable diesel business at Wynnewood into a joint venture.

Sounds good. Thanks for the color.

You’re welcome.

Our next question comes from the line of John Royall with JPMorgan. Please proceed with your question.

Hi, good afternoon. Thanks for taking my question. So my first question is on the hedge program for 2024. I think you had previously said, you were about 15% hedged throughout the year. Any more details you can provide on that that’s still the right number and is it more front-half loaded, more loaded towards one product or another just any color you can give them the 2024 hedges would be helpful?

Yes, you got, John, this is Dane. Yeah, in terms of volume, we’re still around that 15% level as you indicated how much has changed on that front since last quarter. It is a little more front loaded and more weighted towards distillate.

We are adding some in 2025, too, John. So, I think we’re below 3%, 4%.

Yeah, very small number.

But we still have the view that as these large merchant refiners come on around the world that the diesel cracks are going to be pressured, and so most of what we’re doing is around diesel.

Understood. Thank you. And then, maybe just a housekeeping question for Dane, given we don’t have the 10-K at this point. We see your CFO is negative, but looking at the working capital number, I think it’s down from 3Q. So what should we think of as a driver of that cash flow flipping negative and what was pretty solid from an earnings perspective in the quarter, not sure if it’s deferred tax or for some other items we may be missing, but any color there would be helpful?

Yeah, I’ll give you a couple items there. There are a lot of movers in the quarter. We were kind of expecting this type of free cash flow draw. In our fourth quarter, we do typically, we always settle our sock-based compensation payments in cash. We prepay insurance expenses in cash, so we’ll build those back up over the course of the next year. One of the other bigger moving items, as you recall, we had some record crude gathering at the wellhead in the third quarter as well at higher crude prices. As the winter months came on that slowed a little bit, and as the prices fell, liability dropped pretty dramatically quarter-over-quarter. And then also buried in that number, of course, is the crack spread swap unrealized gain, pull that liability down, which is, if the market stays where it is, is a future cash savings or gain, depending on the settlement of those hedges. Lastly, on the Fertilizer business, we had a pretty good deferred revenue in cash sitting on the books at the end of the third quarter. Subsequent to that, the customer buying pattern really started to change, and we’re attributing that to the higher cost of carrying inventory. Our prepay value dropped pretty dramatically down to like $3 million, so more headwinds, but all relatively expected from our perspective.

Thank you.

Our next question comes from the line of Manav Gupta with UBS. Please proceed with your question.

Hi, guys, quick question. Looks like you are doing projects at both locations which will give you a higher diesel yield. So help us understand how much more diesel will you be producing on a combined basis from these value-enhancing projects? And I’m assuming these are high-return projects, but if you have a rate of return for these 2 projects that you are pursuing, which give you higher diesel yield?

Yeah, Manav, between the 2 plants, we’re targeting about 6,000 barrels a day for additional production, which would come from cat feed, in essence, which, as you know, typically a cat cracker does 70%-30%, 70% gasoline, 30% diesel. So the ultimate target there is really improving capture, and that’s all in that 4% number I kind of talked about earlier.

Okay, perfect. And a second question we ask all other refiners, there is an asset package out there, now it doesn’t make sense for many people, but it kind of makes a little bit of sense for you. You could get to a 1 million barrels of refining capacity, you have more product terminals, pipelines. Would there be any scenario in which you might look at CITGO assets for the right valuation?

Well, Manav, we look at everything, so I think I’ll just leave it at that.

Thank you, sir.

You’re welcome.

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

Hi. Good morning.

Hi, Paul.

I think it’s still morning for you guys, or maybe afternoon already. Dave, when you’re looking at your gathering system, have you sensed that or have you seen the activity level of your customer there? Are they increasing or above flat or decreasing in the recent months? I mean, anything that you can tell us in terms of, say, do you think that you are going to be able to gather more or that there’s going to be something at this level?

Well, Paul, as evident by our numbers, we’ve seen an increase in volume, and that’s mainly due to a couple of big plays in the Anadarko Basin. Will they continue? I mean, as far as we know, what we hear from producers is there’s probably a slight gain going through 2025, 2026. After that, we don’t have much visibility on what might occur. A lot of the Anadarko Basin is fed by not only share oils, but just legacy conventional wells that just kind of sit there and produce. So as we gain market share, we’ll get more and more of those, but the bigger volumes of new stuff is really is the shale oil plays in the frack zones, and there’s several big projects that are in development now.

Great. On the renewable diesel, can you share that, what is the EBITDA loss in the quarter, and what’s the growth margin? And also, I mean, if we’re excluding the market condition, what kind of self-help on initiative that we could expand for that business?

Well, if you look at 2023, Paul, going into the third quarter, we were pretty much what I’d call in the profit side of the equation. The fourth quarter hit, and bean oil dropped like a rock. We were unhedged on feedstock, so that took away most of that positivity we had in the first 3 quarters for the fourth quarter. So, I think we ended a year slightly negative, but not too far from breakeven. We really anticipate that the pretreater is going to make a huge difference, because most of the time on these catalyst beds that we have on untreated feed, or even bleached, refined and deodorized our bean oil. The particulates and the other stuff that’s in there just plucked up the bed. So with the pretreater on, we’re going to fix a lot of that, we believe. That’s going to lead to yield improvements and lower costs all the way across, but we’re still – our unit is still challenged with a lack of catalyst and the high space velocity in the reactor and that’s the reason that we’re going to hold the rates back and try to improve the yields and the run length by adjusting the rate until we can answer the question on SAF. Because if we did SAF that would solve a lot of those problems and we back we’d be all the way to the nameplate at that time.

Dave, can you help us to understand why the SAF will solve that problem for you?

Well, we’re a single reactor system today, this gets kind of technical, but I’m happy to tell you. Today, we’re a single reactor we have the ISON [ph] catalyst with the regular whole water removal facilities. If we add another reactor we separate those two. So, we’ll have additional catalyst in the front end, which is really our constraint. And then the ISON [ph] catalyst life will be vastly improved, because you’re stripping all the impurities away that tend to poison that catalyst. So that’s how you do it.

I see. And final one for me, you’re talking about the – trying to improve the distillate yield and those projects. What is the capital cost may look like and how long it takes for the project if you do send soon yet?

Well, we’re still working on the numbers. But, preliminary it looks like when it was probably drawn $10 million somewhere in that neighborhood to do the entire project. Coffeyville will probably be a little bit more, but not a whole lot. I’m anticipating, because there’s 2 units we have to do there, two on the vacuum towers and two on the hydrotreater side. So that one might cost a little bit more, but it also creates a lot more volume. So…

Yeah, I mean, the yield improvement sounds so great. So what’s the catch? I mean, it is so great. I mean, I would imagine you guys have done it in the past. So the fact that it has not been done, is there any reason that why it has not been done in the past?

Well, I don’t know that I have a solid reason why we didn’t do it. I guess, brainstorming, looking at cracks, I guess, distillate cracks in 2022 and 2023, kind of maybe woke up our creative juices to find more diesel. So we did some analysis and did some sampling of what is recoverable. And then we went to work to figure out how. And we found it.

I see. Okay, great. Thank you.

You’re welcome.

Thank you. We have reached the end of the question-and-answer session. I would now like to turn the floor back over to management for closing comments.

Yes. Well, 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, commitment towards safe, reliable, and environmentally responsible operations. And we look forward to reviewing our first quarter results during the next earnings call. Have a great day.