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. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Richard Roberts, Vice President, 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 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. This call also includes various non-GAAP financial measures. The disclosures related to such non-GAAP measures, including reconciliation of 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 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 that the board of directors has authorized a fourth quarter regular dividend of $0.50 per share, which will be paid on March 11th, 2024 to shareholders of record at the close of the market on March 4th. 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 oil utilization for the quarter was approximately 97% of nameplate capacity, and net product yield was 103 on crude oil processed. 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 in the U.S. as the refining fleet ran 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 Refining Company's small refinery exemptions for 2017 through 2021 were permissibly retroactive, contrary to law, 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 overcomply 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, pay 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 remain favorable at these fertilizer prices. Now let me turn the call over to Dane to discuss our financial highlights. Thank you, Dave, and good afternoon, everyone. For the fourth quarter of 2023, our net income attributable to CVR 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 in 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 31st, representing 362 million RINs, mark-to-market at an average price of $0.91. This is 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, 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 offsetting 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 CVI 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 of 2024, we estimate total consolidated capital spending to be approximately $225 million-$250 million, and turnaround spending to be approximately $60 million-$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 five-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 31st, 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 190-205 thousand barrels per day, which will be impacted by the planned turnaround of 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 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-$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 6-10 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 five-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 RVP 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 fleet, 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 what's 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 continued to monitor the planned startup of several large-scale refineries around the world expected this year, although historically, these types of projects tend to come in slower and later than expected. Further delays in startups and a pickup in economic and industrial activity, especially improvement of the Cass Freight Index, could provide upside for diesel cracks this year. Looking at crude oil, commercial crude inventories are near the bottom of a five-year range, although if you include the Strategic Petroleum Reserve, inventories continue to set new five-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 East, the Middle East, is supportive of a wider Brent 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. Fall demand for ammonia application was the strongest we have seen in recent years. Although grain prices have pulled back some 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's approved by the board and successfully implemented, it gives it ability to choose the optimum feedstock mix, and we'll be the only nitrogen fertilizer plant in the United States with that flexibility. Our new pretreatment unit at our renewable diesel unit was mechanically complete 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 pre-previous calls, we are continued 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 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 plan to complete tie-in work for the diesel yield improvement project, with final completion and startup 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 startup 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 a Brent TI spread at $5-$5.25 per barrel, and the WCS differential of $18.63 per barrel under WTI. Prompt fertilizer prices are $500-$550 per ton for ammonia and $270-$280 per ton for UAN. 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. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment please while we poll for questions. 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. First question I had is just around the, you know, the return of capital. Last year, you guys had a great year in terms of $4.50 in 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. You know, I think our regular is probably safe without much doubt. Specials, you know, as we've said before, is really it takes extraordinary cracks for us to generate specials, and you know, maybe they'll come back, maybe they won't. You know, it's hard to say at this point. Yeah, understood. And then, you know, just love 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, you know, I think you know, I've said this many times, you know, the U.S. fleet is probably saturated with light crude. And I don't see many investments to really change that trajectory. You know, there were a couple of condensate splitters built that you know, can 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 in the, and 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, you know, 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 less rail to leave Canada. But you know, the tariff out there is really large, and there's a lot of constraints on shipping and transloading out going off the West Coast. So I still see it really not impacting us a whole lot. Thanks, Dave. 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 on the balance sheet. Do you think 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, you know, 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. Our main strategy is to keep our, you know, 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, you know, the board looks at dividends every quarter. You know, we've always set a minimum cash of, or 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. 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 $30-$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, you know, 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 of what you suggested in terms of capital, $1. You know, I think it ours would be probably $1-$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. You know, it's what our approach on this is maybe a little different than others. We are kind of insisting we want offtake agreements that, you know, negate the uncertainty of government subsidies. So, you know, 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. And as far as, you know, 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 the 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 J.P. Morgan. 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, if 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 on the 2024 hedges would be helpful. Yeah. You got it, John, this is Dane. Yeah, in terms of volume, we're, we're still around that 15% level, as you indicated, not much has changed on that front since last quarter. It is a little more front-loaded and, and more weighted towards distillate. We are adding some in 2025 too, John. So, and that's, I think we're below 3%-4%. Yeah, very small, yeah. But we still have the view that, you know, that as these, these large merchant refiners come on around the world, that the diesel cracks are gonna 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, 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, you know, solid from an earnings perspective, in the quarter? Not sure if it's deferred tax or, or some other items we may be missing, but any color there would be helpful. Yeah, I give you a couple items there. There were a lot of movers in the quarter. We were kind of expecting this type of free cash flow draw. You know, in our fourth quarter, we do typically—we always settle our stock-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 correct spread swap unrealized gain, pulled that liability down, which is, you know, 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 and 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 prepaid 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 two projects that you're pursuing, which give you higher diesel yield? Yeah, Manav, between the two plants, we're targeting about 6,000 barrels a day of additional production, which would come from cat feed, in essence, which, as you know, typically, a cat cracker does 70, 30, 70 gasoline or 70 gasoline, 30% diesel. So, you know, the ultimate target there is really, you know, is improving capture. And that's all in that 4% number I kind of talked about earlier. Okay, perfect. And the 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 1 million barrels of refining capacity, have more product terminals, pipelines. Would there be any, you know, 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. 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 about flat or decreasing in the recent months? I mean, anything that you can tell us that, in terms of, say, do you think that you are going to be able to gather more, or that it's going to be sustaining at this level? Well, Paul, you know, we've 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, there's probably a slight gain, going through 2025, 2026. After that, we don't have much visibility on what might occur. You know, a lot of the Anadarko Basin is fed by not only shale oils, but but just legacy conventional wells that just kind of sit there and and produce. So as we gain market share, you know, we'll get more and more of those, but the bigger volumes of new stuff is really the shale oil plays in the frack zones. And there are 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 gross margin? And also, I mean, if we're excluding the market condition, what kind of self-help or initiative that we could expect 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 three quarters for the fourth quarter. So I think we ended the year slightly negative, but you know, not too far from breakeven. We really anticipate that the pretreater is gonna make a huge difference, 'cause most of the time on these catalyst beds that we have on untreated feeds, or even bleached, refined and deodorized our bean oil, the particulates and the other stuff that's in there just plugs up the bed. So, with the pretreater on, we're gonna fix a lot of that, we believe. That's gonna lead to yield improvements and lower costs all the way across. But, you know, 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 gonna 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. 'Cause if we did SAF, that would solve a lot of those problems, and 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. You know, today, we're a single reactor. We have the ISOM catalyst in with the regular called 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 ISOM catalyst life will be vastly improved 'cause you're stripping all the impurities away that tend to poison that catalyst. So that's how you do it. I see. A final one for me. You're talking about the distillate, trying to improve the distillate yield and those projects. Yes. What is the capital cost may look like and how long it take for the project if you do sanction it? Well, we're still working on the numbers, but, you know, preliminary, it looks like Wynnewood's probably around $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, 'cause there's two 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, that if it is so great, I mean, I would imagine you guys have done it in the past. So the fact that it have not been done, is there any reason that why this 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, you know, you know, brainstorming, looking at cracks, gas and distillate cracks in 2022 and 2023, kinda 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. Ladies and gentlemen, this does conclude today's teleconference. You may disconnect