Greetings, and welcome to the CVR Energy, Inc. third 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 of FP&A and IR. Thank you, Mr. Roberts. You may begin. Thank you, Camilla. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy third 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 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. This call also includes various non-GAAP financial measures. The disclosures related to such non-GAAP measures, including reconciliation to the most directly comparable GAAP financial measures, are included in our 2023 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. Yesterday, we reported third quarter consolidated net income of $354 million and earnings per share of $3.51. EBITDA for the quarter was $530 million. Our solid results for the quarter were driven by continued strength in gas and diesel crack spreads, along with significant decline in the price of RINs at the quarter end. We are pleased to announce that the board of directors has authorized a special dividend of $1.50 per share. This is in addition to the regular dividend, third quarter dividend of $0.50 per share, both of which will be paid on November twentieth to shareholders of record at the close of market on November thirteenth. Our year-to-date declared regular and special dividends total $4 per share, for a total cash return to shareholders of approximately 13%. In our petroleum segment, combined total throughput for the third quarter of 2023 was approximately 212,000 barrels per day, and light product yield was 98% on crude oil processed. Overall, our refineries operated well during the quarter with minimal unplanned downtime. We also completed the repairs to the gasoline hydrotreater at Wynnewood, which was impacted by a fire in the second quarter. Benchmark crack spreads remained elevated during the third quarter, with the Group Three 2-1-1 averaging $39.10 per barrel. The third quarter average RIN price declined from the second quarter but remained stubbornly high at over $7 per barrel. As we discussed in previous calls, we have filed lawsuits and received a stay in the Fifth Circuit Court of Appeals related to the denial of Wynnewood's small refinery exemptions for 2020 and 2021, and we have recently received a stay for 2022 as well. In early October, we were pleased to have our day in court as we presented oral arguments in front of the Fifth Circuit related to EPA's denial of small refinery exemptions. As we have continually, continuously stated, the RFS regulation was written specifically to protect small refineries like Wynnewood from disproportionate economic harm caused by RFS, and we continue to fight for the rights that we believe Wynnewood is entitled to. Our Wynnewood Refinery is the poster child for disproportionate economic harm in the industry, as we believe our relative cost of compliance with RFS is higher than almost all other refineries. For the third quarter of 2023, we achieved record throughput rates at the Wynnewood Renewable Diesel unit, processing nearly 24 million gallons of vegetable oil feedstock in the quarter. The HOBO spread widened from the second quarter with increased soybean oil prices. However, we generated another quarter of positive contribution from the RD unit due to increased throughput volumes and improvement in the California diesel price in the quarter. As a reminder, our renewable diesel business is currently reported in our corporate and other segment. In fertilizer segment, both facilities ran well during the quarter with a consolidated ammonia utilization rate of 99%. Nitrogen fertilizer prices reset in July, after which prices steadily rose through the summer, driven by a combination of strong demand and reduced supply, as well as a result of planned and unplanned outages across the industry. We believe market conditions have firmed in the fourth quarter, and we'll have a good book, good order book on for the fall. Now, let me turn the call over to Dane to discuss our financial highlights. Thank you, Dave, and good afternoon, everyone. For the third quarter of 2023, our consolidated net income was $354 million, earnings per share was $3.51, and EBITDA was $530 million. ... Our third quarter results include a reduction to quarterly RINs expense due to a mark-to-market impact on our estimated outstanding RFS obligation of $174 million, a favorable inventory valuation impact of $91 million, and unrealized derivative losses of $48 million. Excluding the above-mentioned items, adjusted EBITDA for the quarter was $313 million, and adjusted earnings per share was $1.89. Adjusted EBITDA in the petroleum segment was $281 million for the third quarter, driven by strong product cracks in the Mid-Con. Our third quarter realized margin, adjusted for inventory valuation, unrealized derivative losses, and RIN mark-to-market impacts, was $20.73 per barrel, representing a 53% capture rate on the Group Three 2-1-1 benchmark. Realized derivative losses of $44 million, or $2.28 per barrel, reduced our capture rate by approximately 6%. RINs expense for the quarter, excluding the mark-to-market impact, was $90 million or $4.64 per barrel, which negatively impacted our capture rate for the quarter by approximately 12%. The estimated accrued RFS obligation on the balance sheet was $413 million at September thirtieth, representing 367 million RINs, mark-to-market at an average price of $1.12. As a reminder, our estimated outstanding RIN obligation excludes the impact of any small refinery exemptions. Direct operating expenses in the petroleum segment were $5.39 per barrel for the third quarter, compared to $5.53 per barrel in the third quarter of 2022. The decrease in direct operating expenses was primarily due to lower natural gas and electricity prices and higher throughput volumes, somewhat offset by increased personnel costs, partially related to stock-based compensation expense. Adjusted EBITDA on the fertilizer segment was $32 million for the third quarter, with strong production and reduced operating expenses for the quarter, offsetting the decline in nitrogen fertilizer prices relative to the third quarter of 2022. The partnership declared a distribution of $1.55 per common unit for the third quarter of 2023. As CVR Energy owns approximately 37% of CVR Partners' common units, we will receive a proportionate cash distribution of approximately $6 million. Cash provided by operations for the third quarter of 2023 was $370 million, and free cash flow was $318 million. Significant uses of cash in the quarter included $151 million paid for the CVI second quarter regular and special dividends, $67 million for cash, taxes, and interest, $52 million of capital and turnaround spending, and $28 million paid for the non-controlling interest portion of the CVR Partners' second quarter distribution. Total consolidated capital spending was $51 million, which included $26 million in the petroleum segment, $8 million in the fertilizer segment, and $16 million on the pretreatment unit for the RDU. Turnaround spending in the third quarter was approximately $2 million. For the full- year of 2023, we estimate total consolidated capital spending to be approximately $200- 225 million, and turnaround spending to be approximately $55- 65 million. Turning to the balance sheet, we ended the quarter with a consolidated cash balance of $889 million, which includes $89 million of cash in the fertilizer segment. Total liquidity as of September thirtieth, excluding CVR Partners, was approximately $1.1 billion, which was comprised primarily of $800 million of cash and availability under the ABL facility of $251 million. Looking ahead to the fourth quarter of 2023, for our petroleum segment, we estimate total throughput to be approximately 205,000-220,000 barrels per day. Direct operating expenses to range between $95 million-$105 million, and total capital spending to be between $40- 45 million. For the fertilizer segment, we estimate our fourth quarter 2023 ammonia utilization rate to be between 90%-95%. Direct operating expenses to be approximately $55-60 million, excluding inventory impacts, and total capital spending to be between $10 million and $15 million. For renewables, we estimate fourth quarter 2023 total throughput to be approximately 15-20 million gallons, direct operating expenses to be between $6 million and $8 million, and total capital spending to be between $13 million and $17 million. With that, Dave, I'll turn it back over to you. Thanks, Dane. In summary, we had another solid quarter driven by strong results in our refining segment, along with a positive contribution from the fertilizer segment, as well as the renewable diesel business. As we look ahead to the fourth quarter in 2024, we are cautious about the near-term outlook, given the significant geopolitical risk currently facing the market. Starting with refining, crack spreads remained elevated in the third quarter of 2023, with gas and diesel cracks both increasing relative to the second quarter. Although U.S. refining product demand is down in general, gasoline inventories are roughly in line with five-year averages, and distillate inventories are over 12% below the five-year average. Reduced refining capacity in the United States, ongoing turnaround activity, and a string of unplanned outages during 2023 have all helped keep refined product inventories in check. Exports of gasoline and diesel have also continued to be strong, consistently averaging over 2 million barrels per day so far in 2023. Gas cracks have recently declined, which is typical for this time of year as demand slows after the summer and supply increases with the RVP change. Distillate cracks sold off early in the fourth quarter, but rebounded quickly as winter approaches. Container shipments have increased recently for the first time this year, although rail and truck shipments remain lower. The potential for a cold winter in Europe and an increase in natural gas prices continues to present an upside for diesel cracks in the near term, in addition to the significant geopolitical risks we are currently experiencing. As we have discussed in previous earnings calls, we continue to watch the startup of new refining capacity around the world, although many of these projects are delayed. Turning to crude oil, shale oil production continues to increase in the U.S., and we reached a new quarterly record for crude oil gathering volumes in the third quarter of approximately 150,000 barrels per day. Export of crude out of the U.S. have averaged over 4 million barrels per day for the first nine months of 2023, and the Brent-TI differential has remained range-bound at $3-4.50 per barrel. WCS differentials have widened with delays in the new pipeline takeaway capacity out of Canada, while the WCS price at Cushing has tightened relative to WTI recently. We continue to make progress on some of the refined products that we have discussed in previous calls. As an update for the alkylation project at the Wynnewood Refinery, we have ordered long-lead equipment and are on target for completion in 2026. In addition to the benefits of eliminating the use of HF acid catalyst at Wynnewood, this project is expected to increase our alkylation capacity by 2,500 barrels per day, which should result in increased premium gasoline production. Regarding our diesel yield improvement projects, we have completed engineering work at Wynnewood and confirmed our initial estimates. We plan to complete tie-ins during the Wynnewood spring turnaround, 2024 turnaround. Our overall plan is to increase distillate yield from the two refineries by approximately 6,000 barrels per day over the next two or three years, which would increase our total distillate yield on crude throughput by approximately 3%. In the fertilizer segment, nitrogen fertilizer prices have increased since the summer reset in July. With harvest nearly complete, we expect a strong fall ammonia application this year and have a good book of orders. Looking ahead to 2024, grain market conditions remain steady and bode well for nitrogen fertilizer demand, and we believe prices for the spring pre-pay season should be favorable. Geopolitical risks continue to present a wild card for the nitrogen fertilizer business as well, with meaningful fertilizer production capacity residing in countries across the Middle East and North Africa. Finally, in renewables, construction on the PTU is progressing, and we expect the unit to be mechanically complete in the fourth quarter of 2023. Over the past few months, RIN prices have fallen dramatically, primarily due to EPA setting an RVO for D4 RINs way too low in the face of all the renewable diesel capacity that has been ramping up and should be coming online over the next couple of years. With D4 prices at these levels, prompt, renewable diesel margins are break even. We continue to explore opportunities to modify our renewable diesel unit at Wynnewood to shift a portion of production from renewable diesel to sustainable aviation fuel, and we continue to have discussions with various parties interested in securing an offtake of sustainable aviation fuel. We also continue to develop a potential renewable project with the option for sustainable aviation fuel production at our Coffeyville location. The board recently authorized spending for scope definition and a detailed cost estimate, which enables us to have more in-depth discussions with potential partners. Although the prompt market for renewable diesel is not favorable, we continue to believe there will be a place in the market for renewable diesel and sustainable aviation fuel, and we believe our Coffeyville location is strategically advantaged in the heart of the Ag Belt. Looking at the fourth quarter of 2023, quarter- to- date metrics are as follows: Group 2-1-1 cracks have averaged $31.96 per barrel, with a Brent TI spread of $2.98 per barrel. The Midland differential at $0.72 per barrel over WTI. Prompt fertilizer prices are approximately $700 per ton for ammonia and $285 per ton for UAN. As of yesterday, Group three 2-1-1 cracks were $22.43 per barrel. The Brent TI was $5.14 per barrel, and WCS was $26.02 under WTI, where ends were approximately $480 per barrel. We continue to strive to operate our plants in a safe, reliable and environmentally responsible manner, and continue to explore opportunities to grow our renewables business. We also continue to focus on maximizing free cash flow, which underpins our peer-leading dividend yield. 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 that your line is in the question queue. You may press star two if you'd 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.... Our first question comes from the line of Manav Gupta with UBS. Please proceed with your question. Hi, guys. My first question is more on the RIN side. Right now, the way you are positioned, what EPA has done is actually benefiting you. We've seen that in the RFS reevaluation, D4 is dragging D6 down. So in a way, you are very well positioned for what EPA has done in the near term. If you look and try and expand your Renewable Diesel capacity meaningfully from these levels, then in a way, you are countering what EPA has done for you in terms of the RFS obligations. I'm just trying to understand these two balancing forces, where a lower RIN is actually good for you, but you do want to grow your Renewable Diesel franchise, in which scenario you would like to see a higher value of the RIN for a higher margin. So if you can help us understand those dynamics. Well, Manav, we've always said that it was important for EPA to disconnect D6s from D4s. And if you really look at if you're really attempting to do something about climate change, you know, the renewable diesel is the molecule that makes a difference. The ethanol blend of gasoline does really little to do anything to reduce carbon emissions. So it's still our position that EPA should have disconnected these two, and there's several legislation moves that are in the works to try to make that happen. But they also should have increased the D4 to more in line with what the industry is building and is planning to come online. So, you know, I think it's just a misguided program still, and it's something has to break to fix it. So, in an ideal world, Dave, you would like a D4 obligation to be set like 8 or 9 billion versus... and a D6 to be set at 13-13.5. That would be the ideal scenario which you are hoping for, right? Yes, correct. SRE is allowed. Right. And, frankly, E15 should be allowed too. So, you know, it's, you know, you can argue whether it's 13.2 on the, on the, D6 or it's, something higher like 14, but it certainly isn't 15, which is above the blend wall. And, you know, the demand of gasoline is, is up in, in question going forward, and, EPA has to be flexible with that. Perfect. My quick follow-up is, you mentioned this in the comment that, you know, the gasoline is down seasonally and the RVO has, and, you know, RVP has increased. So I'm just trying to understand, in your system, sir, have you seen any real signs of concern of weaker gasoline demand, which could have an impact going ahead? Or you believe what we are seeing right now is just basically seasonal and some overproduction, and should correct itself as we move along next three or four months? Well, in our markets, Manav, it's, you know, our demand is really, and I've said this since about three months into the pandemic, our demand really didn't move much, and it still hasn't. If you look at the seasonal liftings out of the Magellan system, they're almost right on spot to where they've always been, even pre-pandemic. So I attribute a lot of that to the growth in Oklahoma. Oklahoma City, if you've been there recently, is really a growing place. So is Kansas City to some degree. And those are the main markets we serve. Tulsa also. And our liftings at our racks are actually up, compared to pre-pandemic. When I'm talking about the U.S. demand, I'm really talking about the whole U.S., and that's where we're seeing the main part of the decline. Thank you so much, sir. You're welcome. Thank you. Our next question comes from the line of Matthew Blair with Tudor, Pickering, and Holt. Please proceed with your question. Hey, good morning, Dave. On WCS, what do you think is widening out differentials to that 26-20 that you mentioned? And what's your outlook next year with the Trans Mountain expansion, what kind of impact do you think that'll have on this? Sure. Well, you know, I think, you know, seasonally, WCS usually softens in the winter a bit. You get more diluent injected into it. But a lot of it was just a built inventory that built in in Hardisty and backed up the system to some degree. What's interesting is, you know, Trans Mountain has been delayed, but, you know, the cost of that thing and what the tariff's gonna be, it looks like to me that, you know, the tariff to go to the Gulf Coast is gonna be the same as going to the West Coast, and or something very close to that. So I don't know that it'll have a huge impact other than it does increase the takeaway capacity and does open the spigot for some more projects up there if somebody would invest in them. Your second part of your question was? Oh, I think you touched on it. My follow-up is on the product crack hedges. If I caught that right, I think it was a 6 percentage point headwind to capture in Q3. Should we expect, you know, just kind of based on where the futures curves are now, should we expect that impact would probably be less in the fourth quarter just with lower gasoline cracks rolling through? Yeah, I would so our open positions are around 15% for the fourth quarter and then about 15% throughout 2024. But it would be a fair assumption if the market holds where it is, that the bulk of the impact is behind us. ... Sounds good. Thanks so much. You're welcome. Thank you. Our next question comes from the line of John Royall with JPMorgan. Please proceed with your question. Hi, good afternoon. Thanks for taking my questions. So Dave, you gave an update on the court situation for the Wynnewood SREs, which was very helpful. Do you have a timeline in mind for when you think you could have a final answer there? And if you get to the point where you feel like it's you can't really fight it anymore, do you then start to close out your RIN short? Well, you know, it's difficult to always predict what a court will do. This case is no exemption from that. There's two parts to the case. First is the venue that the court has to decide whether it stay in the Fifth Circuit or go to the D.C. Circuit. We think we're optimistic that they'll keep it, but you never can be sure. The second part of the case is the merits of the EPA's argument on denying all small refinery waivers, and we feel very good about that piece. The question is: How long will it take them to rule? And then how will they rule? A lot of times in these cases, they just rule to remand it back to EPA to fix. We really are gonna fight to try to get more definition on that, should we win. That limits what EPA can do, because if you look at history, they just kind of invent something new to deny it again, and we're back in court. So it's very difficult to predict timing, but you know, hopefully before the end of the second quarter next year, we should have a ruling one way or the other, at the latest, so. Then your second part of your question was: Would we liquidate? You know, whatever we do here is gonna be a structured settlement because none of those RINs from the past years are available anymore or will be by that time. And, somehow it'll have to be negotiated what, what it would be, should we lose. Pretty optimistic that we won't. So, that, that case may never come to be. Understood. That's very helpful. Thanks, Dave. And then, you got a question on WCS diffs. I just had another, differential question. This one's on Brent WTI, which I think you addressed a little bit last quarter, but, specifically, Cushing inventories are, are meaningfully lower today, and I think below five-year ranges. But we haven't really seen a significant narrowing of Brent to WTI. So, any color on why you think Brent to WTI is, is where it is, and, and how you think about that going forward would be helpful. Yeah, I think I've always said that, you know, continued growth in shale oil is important for the Brent TI to maintain its position in this range bound between $3-4.50 that we mentioned. And it's really to force the barrel offshore. It requires that kind of differential to make up for shipping and wherever the destination point is, to be competitive in the world market. And that's what's driving it to us. So, as shale oil matures and continues to slowly grow, which is probably the best scenario, there's still plenty of takeaway capacity. We think that bodes well for the Brent TI. Great. Thank you. You're welcome. Thank you. We have reached the end of our question- and- answer session, and now I'd like to turn the floor back over to management for closing comments. Again, we'd like to thank you all for your interest in CVR Energy. Additionally, I'd like to thank our employees for their hard work and commitment towards safe, reliable, and environmentally responsible operations. We look forward to reviewing our fourth quarter 2023 results during our next earnings call. Thank you. This concludes today's teleconference. You may now disconnect your lines at this time. Thank you for your participation.