Greetings and welcome to Valero Energy Corp Q4 2024 Earnings Conference Call. At this time, all participants are on a listen-only mode. A question-and-answer session will follow the formal presentation. If anyone requires 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, Homer Bhullar, Vice President of Investor Relations and Finance. Thank you. You may begin. Good morning, everyone, and welcome to Valero Energy Corporation's Q4 2024 Earnings Conference Call. With me today are Lane Riggs, our Chairman, CEO, and President; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and COO; and several other members of Valero's senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at investor.valero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted financial metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our investor relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our earnings release and filings with the SEC. Now I'll turn the call over to Lane for opening remarks. Thank you, Homer, and good morning, everyone. I would like to start by highlighting some of our team's accomplishments last year. 2024 was our best year for personnel and process safety and one of our best years for environmental performance. Safe and reliable operations drive overall performance and disciplined operations. In refining, we processed a record volume of heavy sour crude in the fourth quarter. This demonstrates our refining system's flexibility and highlights the capability of our commercial and operations teams to be able to secure and process the most economic crude oils. Finally, we set a record for ethanol production with the expansion of the Charles City plant and process optimization at other sites. Our team's relentless focus on operational excellence and low-cost operations enabled us to deliver positive results in the fourth quarter in an otherwise weak margin environment. On the strategic front, we continue to deliver on our commitment to grow Valero's earnings capacity through organic investments. The DGD Sustainable Aviation Fuel Project was successfully started up in the fourth quarter and is now fully operational. Looking ahead, we are progressing with a coker unit optimization project at St. Charles that will enable the refinery to increase the yield of high-value products, including high-octane alkylate. The project is estimated to cost $230 million and is expected to start up in 2026. We continue to pursue other short-cycle, high-return optimization projects around our existing refining assets. On the financial side, we continue to honor our commitment to shareholder returns with a strong payout ratio of 78% for the year. Earlier this month, our board approved a 6% increase in the quarterly cash dividend, further demonstrating our strong financial position. Looking ahead, refining margins should be supported by low-light product inventories ahead of the driving season. In longer term, we still expect product demand to exceed supply with the announced refinery shutdowns this year and the limited capacity additions beyond 2025, supporting long-term refining fundamentals. So with that, Homer, I'll hand it back to you. Thanks, Lane. For the fourth quarter of 2024, net income attributable to Valero stockholders was $281 million, or $0.88 per share, compared to $1.2 billion, or $3.55 per share for the fourth quarter of 2023. Excluding the adjustments in the earnings release tables, adjusted net income attributable to Valero stockholders was $207 million, or $0.64 per share for the fourth quarter of 2024, compared to $1.2 billion, or $3.57 per share for the fourth quarter of 2023. For 2024, net income attributable to Valero stockholders was $2.8 billion, or $8.58 per share, compared to $8.8 billion, or $24.92 per share in 2023. 2024 adjusted net income attributable to Valero stockholders was $2.7 billion, or $8.48 per share, compared to $8.9 billion, or $24.96 per share in 2023. The refining segment reported $437 million of operating income for the fourth quarter of 2024, compared to $1.6 billion for the fourth quarter of 2023. Refining throughput volumes in the fourth quarter of 2024 averaged 3 million barrels per day, or 94% throughput capacity utilization. Refining cash operating expenses were $4.67 per barrel in the Q4 of 2024. Renewable diesel segment operating income was $170 million for the Q4 of 2024, compared to $84 million for the Q4 of 2023. Renewable diesel sales volumes averaged 3.4 million gallons per day in the Q4 of 2024. The ethanol segment reported $20 million of operating income for the fourth quarter of 2024, compared to $190 million for the fourth quarter of 2023. Ethanol production volumes averaged 4.6 million gallons per day in the fourth quarter of 2024. G&A expenses were $266 million for the Q4 of 2024 and $961 million for the full year. Depreciation and amortization expense was $698 million, net interest expense was $135 million, and income tax benefit was $34 million for the fourth quarter of 2024. The effective tax rate was 19% for 2024. Net cash provided by operating activities was $1.1 billion in the fourth quarter of 2024. Included in this amount was $119 million of adjusted net cash provided by operating activities associated with the other joint venture member share of DGD. Excluding this item, adjusted net cash provided by operating activities was $951 million in the fourth quarter of 2024. Net cash provided by operating activities in 2024 was $6.7 billion. Included in this amount was a $795 million favorable change in working capital and $371 million of adjusted net cash provided by operating activities associated with the other joint venture member share of DGD. Excluding these items, adjusted net cash provided by operating activities was $5.5 billion in 2024. Regarding investing activities, we made $547 million of capital investments in the fourth quarter of 2024, of which $452 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, and the balance was for growing the business. Excluding capital investments attributable to the other joint venture member share of DGD and other variable interest entities, capital investments attributable to Valero were $515 million in the fourth quarter of 2024 and $1.9 billion for the year. Moving to financing activities, we returned $601 million to our stockholders in the fourth quarter of 2024, of which $339 million was paid as dividends and $262 million was for the purchase of approximately two million shares of common stock, resulting in a payout ratio of 63% for the quarter. In 2024, we returned $4.3 billion to stockholders, consisting of $2.9 billion in stock buybacks and $1.4 billion in dividends, resulting in a payout ratio of 78% for the year. In fact, since the start of 2021, our total cash flow from operations has exceeded our total uses of cash over this period, including capital investments. During this time, we delivered over $4 billion of debt reduction and returned approximately $18.7 billion to stockholders through dividends and share buybacks. Through share repurchases, we reduced our share count by approximately 6% in 2024 and by 23% since year-end 2021. With respect to our balance sheet, we ended the quarter with $8.1 billion of total debt, $2.4 billion of finance lease obligations, and $4.7 billion of cash and cash equivalents. Debt-to-capitalization ratio net of cash and cash equivalents was 17% as of December 31, 2024, and we ended the quarter well-capitalized with $5.3 billion of available liquidity, excluding cash. Turning to guidance, we expect capital investments attributable to Valero for 2025 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts, regulatory compliance, and joint venture investments. About $1.6 billion of that is allocated to sustaining the business and the balance to growth. For modeling our first quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.72-1.77 million barrels per day; Midcontinent at 415,000-435,000 barrels per day; West Coast at 190,000-210,000 barrels per day; and North Atlantic at 455,000-475,000 barrels per day. We expect refining cash operating expenses in the first quarter to be approximately $4.95 per barrel. With respect to the renewable diesel segment, we expect sales volumes to be approximately $1.2 billion in 2025. Operating expenses in 2025 should be $0.51 per gallon, which includes $0.22 per gallon for non-cash costs such as depreciation and amortization. Our ethanol segment is expected to produce 4.6 million gallons per day in the first quarter. Operating expenses should average $0.41 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization. For the first quarter, net interest expense should be about $130 million, and total depreciation and amortization expense should be approximately $710 million. For 2025, we expect G&A expenses to be approximately $985 million. That concludes our opening remarks. Before we open the call to questions, please limit each turn in the Q&A to two questions. If you have more than two questions, please rejoin the queue as time permits to ensure other callers have time to ask their questions. Thank you. The floor is now open for questions. If you would like to ask a question, please press Star 1 on your telephone keypad at this time. A confirmation tone will indicate your line is in the question queue. You may press Star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up the handset before pressing the Star keys. Again, that's Star 1 to register a question at this time. Today's first question is coming from John Royal of JPMorgan. Please go ahead. Hi, good morning. Thanks for taking my question. So my first question is maybe to Gary, just broadly on market color. You've always given us a good view of the fundamental picture in the sector. How do you view the supply-demand balances today for products and the outlook for cracks for this year? And what do you think are the key things we should look out for in terms of just any early indicators of when this market might turn back up? Yeah, John, you know it's always difficult to get much of a read on the market this early. I'll tell you that we typically see our sales through our wholesale channel dip fairly significantly through the holiday season, kind of goes through the first couple of weeks of the year, then starts to recover. We saw that same dynamic this year. Sales kind of dipped to about 85% of average. The last couple of weeks, we've seen a nice recovery back to kind of a million barrels a day level that we typically see. I think yesterday we did a million forty thousand barrels a day. Gasoline sales in our system year-to-date are slightly down year over year. I think when you look at the concentration of our marketing, this makes sense. You know the snow in the south and southeast kept people off the road. And then the Colonial Pipeline outage limited our volumes we had available to sell in some markets. For that window, the pipeline was down. Our current seven-day average data shows gasoline sales up 2% year over year. Overall, what we can see is gasoline demand looks good, and we expect gasoline demand in the United States to be fairly flat to last year. Diesel sales year-to-date in our system are also off a few percent. This was a little more surprising to me, mainly because of the cold weather that we've seen. But I think if you look into the data a little bit more, it makes sense. You know we had about 10,000 barrels a day of Renewable Diesel from Port Arthur that was going to our wholesale channel that we were selling. That material is now going to produce Sustainable Aviation Fuel. That's a chunk in the year-over-year decline in diesel sales. In addition to that, we saw the same dynamic on diesel with some of the snow impacting on-road diesel demand. And then I think if you look at Valero, we don't have a big marketing presence in the markets where you see high heating oil demand. So we don't really see that big uplift from the cold weather that you may see. We definitely get that on the bulk side, but not through wholesale. Seven-day average shows diesel sales are up about 1%, and that's kind of what we expect for the year, about a 1% increase in diesel demand in the United States. Most consultants I've read are showing about a 250,000 barrels a day increase in diesel demand just due to cold weather in the North Atlantic Basin. Not only do we expect diesel demand to be better, but we expect a greater percentage of that to be supplied by refinery-derived diesel. You know last year we had the big wave of bio and renewable diesel projects hitting the market. We don't see that same dynamic this year. So I think overall, things are shaping up pretty nicely. You know we're at total refined product inventory, 9 million-10 million barrels below where we were last year at this time. So inventory is in good place. I think at the beginning of the year, the supply-demand balances look similar to last year, but as you progress through the year, you'll see gradual tightening of supply-demand balances. Great. It's very helpful. Thank you, Gary. And then my second question is on capital allocation. You finished the year with another quarter well above your 40%-50% floor and high 70s% for the full year. But assuming we don't have a significant recovery in cracks from here, how should we think about that payout ratio in a lower crack environment in 2025? Should we expect you to move closer to that 40%-50% floor? Morning, John, this is Jason. I'm going to ask Homer to give you a little more detail on that. Sure. Yeah, John, I mean, you're right. We had a 78% payout for the year, but that was partly funded by our excess cash balance going into the year, but you know if you want to put this into context with some numbers, if we had held our shareholder payout ratio at 50% for the year, we would have built almost $1.7 billion of cash for the year. Even if you excluded the $795 million of positive impact for working capital for the year and include the $167 million debt repayment we did in the first quarter of 2024, we would have still built over $700 million of cash. Now, taking that a bit further, even if you look at the low-margin environment in the fourth quarter, we still would have been able to honor our minimum payout commitment of 40%-50% without leaning into the balance sheet or drawing down cash. So hopefully this gives you some context of the earnings capacity of the portfolio, even in a low-margin environment, and our ability to invest capital, obviously honor our shareholder commitment and flexibility with debt in our balance sheet. Thank you. Thank you. The next question is coming from Doug Leggett of Wolfe Research. Please go ahead. Oh, thank you. Thanks, guys. I think Gary might be the most popular man on the call today, Lane. I apologize, but there was obviously a lot going on. Doug, all okay with me, Doug? So, I'm going to try just a couple of. Someone's got to do it. I'm going to try a couple of high-level ones, if I may. The headlines I saw just a couple of hours ago was that Trump is still going to go ahead with tariffs on Canada. And I seem to recall that the last time there were problems with heavy oil supply from Canada, there was a second-order effect that everyone seems to have forgotten about. And I wanted to run this past you and just get your perspective on it. And that is that if you need to find a substitute for that much heavy oil, you're going to have run cuts, you're going to have utilization yield issues, flooding of your system, and so on. I wanted to see if you guys thought there was any sense to that in the context if it actually became a thing as it relates to the substitution of lighter crudes for the heavy crudes. What would you guys do? Yeah, so Doug, this is Gary, and I can tell you we've been aware of this for a couple of months, and so our commercial teams and optimization teams have been working hard to develop every possible scenario we can think of and how we would respond to that. Of course, it's why we like our position on the U.S. Gulf Coast, because you can source feedstocks from anywhere around the world, and where we also like our feedstock flexibility, but yes, there is a point where if heavy feedstocks become limited, it affects rate and production of clean products, certainly from our assets, and we'd expect industry-wide. Assuming this is transitory, it's not a big deal, but if it did drag on for an extended period of time, particularly as we switch into summer grade, I mean, could it be meaningful, or is that a rounding error? You want to, Greg. Hey, Doug, this is Greg. Yeah, when we think about it and look at some of those different scenarios, you might see a 10% change in throughput. A lot depends on how far it goes and how deep you have to back off on some of those heavy barrels. But it wouldn't be driving things to a much greater degree than that, I don't think. Okay. That was meaningful enough when you were talking about the situation you're going to run out. But we're searching for green shoots, guys. That's really what these questions are about. So I apologize. I'm going to try another high-level one, and it really relates to your throughput guidance. So obviously, everyone's focused on whether it's Dos Bocas or Lyondell closing or Grangemouth or whatever it happens to be. But it seems to me that coming out of COVID, utilization rates, you know the concentration or the absence of good maintenance got solved, and the concentration of great maintenance meant everybody ran well. And it seems to us, with no storms and all the things you've run through, Gary, there's probably about 3% or 4% of utilization that was kind of a best-in-class world for the U.S. last year, which is basically four refineries, if you think about it. And so when I look at your guidance for the quarter, you obviously don't give forward cadence for commercial reasons through the rest of the year. But at a high level, how do you see the likelihood that the industry, the U.S. industry specifically, can continue to run at those kind of levels, given the backdrop we've had and the fact that we're down 10% in the last three weeks in utilization? Yeah, so I think you know certainly what you've seen utilization in the last few weeks is somewhat weather-related, along with the maintenance activity. I think given the advantages that U.S. refiners enjoy on feedstock cost and energy cost, you should expect to see that U.S. refining continues to run at higher utilization rates. And when you have run cuts, they occur elsewhere in the world where they don't have the natural resource advantages that we have. You know, I think I was thinking more about the reliability aspect as opposed to the cost advantage aspect. Yeah, and I'm sure you know we've certainly seen an improvement in our system on mechanical availability, and I suspect our peers have as well, and it's something we always strive to get better and better at. Great stuff. All right, guys, sorry for the high-level questions, but I've had my two, so I'll leave it there. Thanks so much. Thanks, Doug. Thank you. The next question is coming from Neil Mehta of Goldman Sachs. Please go ahead. Yeah, good morning, team. Just a couple of questions on the quarter itself. Renewable diesel performance came in, I think, better than what most market participants were expecting and better than implied by the indicators. Just curious on any thoughts there and the outlook for that business as we work our way through 2025. Yeah, this is Eric. I think a lot there was a one-time benefit with some inventory optimization at the end of the year that was the bulk of that higher-than-expected performance. There is a little bit of SAF in that, but I would make it clear that that was mostly some inventory optimization we did at the end of the year. In terms of forward-looking in renewable diesel and SAF for us, you know we're all kind of waiting to see how this market is going to develop and how the policy is going to develop. But overall, things are very much staying in line with kind of what we thought was going to happen. The 45Z has now replaced the blender's tax credit. We can see that that's now going to limit product imports into the U.S. It is going to make it a carbon intensity scale rather than a flat dollar to every renewable product. All of that is advantageous to Diamond Green Diesel and our platform because, like the refining platform, our feedstock flexibility, our ability to export to any of the other markets, and I think, consistent with our outlook from last year, the most attractive markets are going to be in Europe and Canada compared to U.S. and California, so overall, we're waiting to see how RINs are going to respond, how LCFS is going to respond, and you know I think you will see those changes emerging in the market in the next couple of months as some of those production and credit reports emerge on how the year ended. Gary already mentioned that we don't see any increase in renewable production this year. It's still long compared to, say, D3 RIN Credit Bank or D4 RIN Credit Banks and LCFS Credit Banks. But we do also expect you're going to see some correction in production that will eventually start to pull those credit banks down throughout the year. That's helpful. And then independent of tariffs, it was notable the amount of heavy that you were able to run through the system. And I think there were some concerns about coking economics in the quarter, given how tight fuel oil was. But clearly, you were able to optimize the system to run over 600,000 barrels a day of heavy sour oil. So can you just talk about how you were able to do that and the commercial approach to maximizing heavy in a time when fuel oil is pretty tight? Hey, Neil, this is Greg. I'll start, and then Gary can talk some more about the market. But you hit on, I think, the key factor, which is as the fuel oil prices, those differentials narrowed, that with fuel oil typically being a feedstock in our Gulf Coast system, we pivoted away from that towards the heavy crudes as an alternative, which continued to show some good value. So that's why you see that shift towards more heavy sour crude. You also notice a reduction on the heavy resid feedstocks that we processed as well. And that's kind of how we got to the high level of heavy crude processing. Also, keep in mind, we've got the Port Arthur Coker online. That shifts us to a bit of a heavier feed slate as well. So that's part of what you see in that number as well. Thanks, team. Would you like to move on to the next question? Yes, please. Thank you. The next question is coming from Theresa Chen of Barclays. Please go ahead. Good morning. Thank you for taking my questions. On the tariff topic specifically, understanding that you're not captive to any specific source of crude based on your footprint and the optionality you have on the Gulf Coast. But as we think about the tariffs on Canada, Mexico, incremental sanctions, potentially on Venezuela, how are you thinking about light heavy differentials as we move through the year? Yeah, Teresa, this is Gary. I think you know I'll start with kind of fundamentals, but then cut to really what's driving the market. And certainly on the fundamental side, typically this time of year, you see less buying of medium and heavy sours just due to turnaround activity. In addition to that, Lyondell coming down puts another 200,000 barrels a day heavy on the market. Calls for OPEC crude second quarter 2025, 180,000 barrels a day of medium sour crude. So all those things would be supportive of wider quality differentials. But in reality, the discussions on sanctions and tariffs are really what's driving the market. And until we see some resolution to that, I don't expect any meaningful moves in the quality differentials. Understood. And related to the St. Charles FCC project, would you be able to provide a little bit more color on this, what the optimization means in terms of incremental improvement in the yield of high-value products? Sure, Teresa, it's Greg. You know Lane mentioned it costs about $230 million. It definitely meets our investment hurdle at mid-cycle pricing. And one of the key outcomes for the project is increasing the production of light olefin product out of the FCC. And what that really means is that's additional feedstock we can use to fill the alkylation capacity we have downstream of the FCC there. And you might remember we started up a C5 alkylation unit at St. Charles back in late 2020. And with some tweaks and optimizations we've done to that unit since, we've got some spare capacity in the alky. And with this project, you will increase high-octane alkylate production by something on the order of 6,000-7,000 barrels a day. That's one of the key outcomes and things that drive the value. It's really a good example of identifying some key equipment constraints within the operation that when we modify those constraints or that equipment, it allows us to take full advantage of the capability, not only of the FCC unit in this case, but other equipment and other units in the refinery, and again, in this case, the alky, and that's how we generate a good return from the project. Thank you very much. Thank you. The next question is coming from Manav Gupta of UBS. Please go ahead. Good morning. I wanted some additional color on the North Atlantic capture. Looks like it jumped from 102% last quarter to about 118%. And similarly, the Gulf Coast capture jumped from about 76% to 86%. So Gary, if you could help us out a little, what were some of the factors helping you drive that kind of capture improvement? Sure, I'll let Greg answer. Hey, Manav. A couple of things I'd point out on the North Atlantic. It really is a bit of a system question. It is North Atlantic and Gulf Coast as well. But we go into the wintertime, we start blending more butane into the high RVP gasoline. That gives us a bit of a bump in capture as that adds value into the gasoline pool. In both those regions as well, you had good contributions from the wholesale side of the business, the commercial part. So we saw some benefit from that. On the Gulf Coast, the other notable item would really be, if you look at Maya relative to the Canadian grades that we use for the benchmark, Maya was a bit more discounted, certainly when you look at it quarter over quarter. And so that helped to improve the crude costs that we saw for the heavy crudes into the Gulf Coast. Quick follow-up here, Riggs. We are seeing a very strong diesel margin and slightly weaker gasoline. And I know Valero can move the yield around a lot. So are you already operating in max diesel mode, or how much more can you swing the yield more towards diesel, or do you think this is very temporary, like once you come February and March, the gasoline demand will improve and the cracks will start to balance out each other? No, Manav, this is Greg. Yeah, we are definitely in max diesel mode. As you mentioned, the cracks would drive us in that direction. And we'll see as we get into gasoline season whether the gas crack shifts enough to push us the other way. Thank you for taking my questions. Thank you. The next question is coming from Paul Sankey of Sankey Research. Please go ahead. Hi, everyone. Just continuing on the themes that we've had this morning. Can you talk a bit about the Atlantic Basin and all the trade arbitrages? I think it's obviously tough to make a firm outlook here with all that's moving around. But I wondered, what have you been seeing, let's say, over the past two to six months in terms of the major Nigerian refinery? There's been a lot of action in the dollar versus the euro. There's obviously been all the cold weather effects. So I just wondered if you could describe a little bit what we've been seeing in the market in the Atlantic Basin and what your outlook is for the coming year. Thanks a lot. Tough question. Yeah, so I'll start with the Dangote Refinery. I think from what we can see and what we read, they do have their resid FCC up and running. We see that commercially. They're not offering out the fuel oil or the resid that we were buying from them. We also see less imports of gasoline into West Africa, which is all consistent with Dangote continuing to ramp up. With that, though, however, you know what we've seen is that generally tends to impact Europe more than it does the U.S. Gasoline that was going to West Africa gets backed into Europe. We haven't really seen much of an impact from that. Our gasoline exports primarily go to Latin America. You can see in the fourth quarter, we were 98,000 barrels a day of gasoline exports into that market, which is consistent of where we've been. I can tell you in the first quarter, we're right about that same level again. Diesel's been somewhat interesting. The cold weather in the U.S. kind of has the U.S. market strong. So you actually see a few cargoes from Europe actually booked into New York Harbor, which is an abnormal trade flow. We do see that correcting when you get to the second half of February. We're already seeing an open ARB to export back from the U.S. to Europe. So nothing too abnormal on trade flows. I think by and large, what you've seen is that the Dangote startup in the North Atlantic Basin has been largely offset with Lyondell coming down and Grangemouth coming down, and they're kind of counterbalancing each other and keeping trade flows about what we've seen historically. That's brilliant. Thanks very much. And just if I could follow up, thinking about the reality of tariffs, could you describe maybe a situation of how they would work? I mean, what happens? Do you just suddenly have to start paying it overnight? Or how does it work? If you've got any ideas, I'd be grateful. Thanks. You know, without having really any clarity on what's going to happen, there's no reason for us or no way we can really speculate on how we deal with it. We're just going to have to deal with it when it comes up. Hey, Paul, Lane, all I add is it depends on the market, right? If you're a captive market, it'll somehow get shared between the refinery and the, say, the Canadian crude producer because there's some captive markets in the Midcontinent. In the Gulf Coast, somehow that'll all ultimately get sort of priced in depending on how that refinery is configured and what their alternatives are. And then we'll just have to see how long it lasts, you know? Got it. Have there been examples of it happening in the past that you can think of where you'd suddenly have to pay 25% more for a given crude? No, and I've been around a long time. Yeah. Gotcha. I'll take that, Lane. Thanks. Thank you. The next question is coming from Roger Read of Wells Fargo. Please go ahead. All right, Lane, I'm still chuckling from you've been around a long time answer there. Maybe coming back a little bit on the whole changing in capacity. So obviously, you mentioned the shutdown of Grangemouth. We have the shutdown here locally of Lyondell, and we have some more stuff likely coming in Europe beyond what's been announced. I'm just curious how y'all are seeing some of those dynamics play out in terms of just crude availability. Let's leave the tariff thing aside and maybe how that's playing out along the Gulf Coast. Yeah, so I think the only thing we can see is you've definitely seen the dynamic in the market of Lyondell stopping to buy. And they were buying a lot of, especially a lot of Canadian. And so we've seen more of those barrels become available to us as they backed off the market. Is that materially changed price, or is it just an availability question? It's so difficult to tell because it's been going along at the same time with all these tariffs and sanctions discussions, so it's kind of those discussions have muted any market impact there would be of Lyondell pushing the barrels back so far. Okay. And then as a follow-up question from earlier about, I think Doug was asking it about the industry's ability to maintain utilization as you look forward through the year, thinking about some of these closures that have happened. And if you look at on a year-over-year change of U.S. inventories, whether you look at crude alone or crude plus products or just products, all are down year-over-year, a little more severe on the crude side than on the product side, but it would imply a lot of tightness. And if you can't, I say if you can, if the industry cannot maintain these levels of utilization, it would imply either much lower inventories or lower exports. But is there anything I'm missing in that general thought process? No, I think you've got it nailed on the head. When we look at the balances, the inherent assumption that you're going to see similar supply-demand balances the last year and gradually tightening is the fact that the industry at a high actually utilization is going to go up to meet demand. And so that certainly, we haven't had a major weather event the last year. Any kind of a major weather event that knocks capacity offline or unreliability event can tighten things up a lot. If you look, especially on the diesel side, we're within 10% on inventory where we were in 2023. In 2023, we had a $45 diesel crack versus where it is today. I mean, the inventory position is not significantly different, yet the margin environment is fairly significantly different. It could change in a hurry. Appreciate that. Thank you. Thank you. The next question is coming from Ryan Todd of Piper Sandler. Please go ahead. Thanks. Maybe a couple of follow-ups on the biofuel side. I mean, you talked somewhat about your broader 2025 outlook with all the moving pieces there. As we think about the early part of this year, like first quarter in particular, BTC goes away December 31st. It feels like it's going to take some time, at least a few months for the market to kind of reach a new equilibrium with the 45Z and some of the impacts on imports and domestic production. Is there a risk to how does this play out in the first quarter? Is there a risk that economics kind of fall off the table in the first quarter as this stuff gets sorted before it reaches kind of a better equilibrium later on in the year? Yeah, I think if you look at the conversion of the BTC, where everyone got $1, to now this carbon-intensity-based credit. We've run the U.S. GREET model that was just released. For veg oils, it's zero for canola oil. It's $0.16 for soybean oil. And waste oils are in the $0.50-$0.60 per gallon range. And so at the end of the day, that is all less than $1. So if you needed that $1 to break even and now you're getting $0.16, it's a fairly negative margin environment for non-waste oils. I think everyone can see that. I think there's growing recognition that this is going to be very difficult to see a lot of the biodiesel side and veg oil side operate at these lower incentives. How that plays out in terms of production reconciliation through the first quarter, everyone's looking to see, well, but hand in hand, we also see the imports that were coming to the U.S. to get that dollar are now stopped. So how all that balances out? We haven't seen a lot of change in feedstock prices to reflect a lot of this, but I think there's growing recognition that there's going to be some movement in overall production and overall feedstock prices kind of as you go through the first quarter and see some of these early reports coming in on what are we seeing in terms of generation of credits. And so again, I think being a waste oil unit on the Gulf Coast, we're the most advantaged in terms of how we can react to these things. And it still mostly favors waste oils, which is what our platform is based on. So I think we're still in a good position versus our competitors. It's just, but there's no doubt overall, there's lower incentive for all of this in this PTC world. Thanks. And then maybe a follow-up on SAF. I mean, can you maybe just provide a little bit of an update in terms of your SAF operations at this point, maybe some idea of level of production and how you think about the contribution of SAF economics here in 2025? Yeah. So Lane mentioned this in his opening comments. The project started up in the fourth quarter. Again, credit to our project team on finishing ahead of schedule and under budget. We had a flawless startup. It started up on spec. We spent most of the time in the fourth quarter doing test runs and initial fills on tanks. But throughout all our test run trials, we showed a very wide range of operability, all of which more than met our project goals operationally. So unit hardware looks great. Production has been very smooth. And we made our first sales in November. And we saw the QAQC and all of the traceability and accreditation flow all the way from production to neat SAF to blended SAF to delivery to final customer. And so we spent a lot of time in the fourth quarter just sort of proving the system out. In terms of going forward, we're not going to really get into a lot of detail of because what I'd say is what we have now is very good flexibility to meet all the project economic goals that we set out with the original project. But if you look at, say, the Argus market in the E.U. and the U.K., right now you see HVO at or better than SAF. So we have flexibility to make either barrel into the European market. And so really what we're doing now is just tuning that optimization as we see SAF customers really starting up in the first quarter because of the 2% mandate that you see in the E.U. and U.K. Great. Thank you. Thank you. The next question is coming from Paul Cheng of Scotiabank. Please go ahead. Hey, guys. Good morning. Good morning. Maybe this is one to go back to Eric. The PTC, I don't think that the detail is out. So when you guys report the first quarter, should we just assume that in your gross margin, the BTC also that you will drop by $1 per gallon, that you're not going to record any benefit, or that you will put some kind of provisional and think that it will just come through? And also whether you can share how much is the fourth quarter inventory benefit or optimization benefit that you are referring to earlier. That's the first question. The second question, maybe for Lane, U.S. natural gas price looks like it's going to be higher. So, if we look at your system, do you see a lot of opportunity of reducing your energy cost further, or that you have already done so much is really difficult, or that would be too expensive if you're trying to have any meaningful reduction in the energy cost from the current level? Okay. So I'll start on the margin indicator. We had the same discussion that our margin indicator still includes the dollar BTC in the calculation. One of the challenges in this PTC environment is because it's carbon-intensity-based, that will vary with our feedstock slate. And so we haven't had enough runtime or, as you said, enough clarity to really know how this is all going to line out because we can think of scenarios where certain feedstocks get very cheap that might have a higher CI, or we'll continue to see the incentive to run the lowest CI feedstocks, and those will obviously have higher benefits in the PTC. So it's a little hard to nail down how we want to adjust the margin indicator. Our decision, we're going to keep it the same for now until we see a little more development on how we're going to be running in this new policy environment. Lane, I'm sorry. I'm not asking about the margin indicator. I'm asking that when you report the first quarter result in your release, should we just assume that you will take out the $1 per gallon for the BTC in your margin and not including any benefit from the PTC because that's not being finalized, or that when you report the result for the first quarter, you actually will do some provisional estimate of what your DGD result should be under the PTC as you understand? Hey, Paul, this is Lane. The way we do our financials, particularly on that side, it's really on the there won't be a provisional like, "Hey, we think the PTC benefit's going to ultimately be this." If we don't have clear policy in the first quarter, it'll be whatever it is. Okay. So we would just take out the BTC benefit, but not including any estimate for the PTC for you guys? Correct. Okay. And how about in terms of earnings, can you share what is the inventory benefit in the fourth quarter? Yeah. I don't think we're going to give that level of detail out, but it was just an end-of-year optimization that we did at both units in the fourth quarter. All right, so how about Lane about the energy cost? Hey, I'm going to at least initially pitch this over to Greg. So go ahead, Greg. Hey, Paul. So with low energy costs, and a lot of that meaning low natural gas and low cost for power for our plants in North America, you don't see a lot of incentive to try to do a project to further reduce your energy consumption. There's just not a lot of opportunity there from a value standpoint. We do see opportunities in Pembroke. We've done some things at the refinery there to improve energy efficiency because their costs are quite a bit higher. So I would say in general, unless you see a marked change in the cost of natural gas or power, it's going to be hard to justify some kind of an improvement project. Always trying to be as efficient as we can be in the base operation. So there's no change there. But in terms of some kind of investment to make a step change, that's hard to do in the current environment. Perfect. Thank you. Thank you. The next question is coming from Joe Laetsch of Morgan Stanley. Please go ahead. Great. Thanks. Good morning, everyone. Thanks for taking my questions. So I wanted to ask a couple on the quarter. From our standpoint, it looked like the Midcontinent came in stronger on throughput and capture while the West Coast was, I'd say, remained a bit weaker, which I think was driven in part by maintenance. Could you just talk to any specific drivers during the quarter for the Midcontinent West Coast in particular from a capture and throughput standpoint? Yeah, Joe, this is Greg. So West Coast is fairly simple, and you hit on it. It was maintenance work primarily at Benicia that impacted not so much throughput there, but it impacted the amount of transportation fuel we could make. And so that had an impact on the capture rate. In the Midcontinent, throughput was higher. We actually saw pretty good incentive to continue to maximize throughput there. Good demand for products. And so we were able to push throughput a little bit higher than we had planned going into the quarter. And then on the capture side, one of the factors there, you saw crude market structure on WTI less backward than you saw in the prior quarter. That had a benefit to capture rates in addition to some of the things I talked about earlier on butane blending. Great. Thanks. That's helpful. And then I wanted to shift gears and ask about the ethanol segment. So the indicator continues to grind lower to start the year. Could you just talk to some of the puts and takes going on in the industry as well as your forward outlook? And then also the potential for year-round E15, which was included in the executive orders released last week. Thank you. Yeah. The ethanol margin has been challenged with high inventories and high production rates. I'll say surprisingly high production rates that have been sustained really for the third and fourth quarter and into the beginning of this year. We have seen some weather-related impacts to production rates, but I think overall you're looking at high inventories and high production rates. And so it's keeping ethanol margins currently, I would say, below mid-cycle. So in terms of E15, there's always a lot of positive outlook for that. As you know, we've continued to see E15 approved by emergency order every 20 days. We don't see a lot of E15 movement. We don't see a lot of growth in that market. We do see Canada still talking about moving to E15 this year through their CFR program. I think there's a high likelihood you're more likely to see incremental E15 in Canada before appreciably in the U.S. But I mean, we'll see how this develops this year by policy. It's still a fairly significant logistics challenge to convert retail to E15. But overall, I mean, it's still something that certainly the ethanol and ag industry sees as a positive development for ethanol outlook. Great. Thank you all. Thank you. The next question is coming from Matthew Blair of Tudor, Pickering, Holt & Co. Please go ahead. Good morning. Thanks for taking my question. Regarding the Canadian tariffs, you talked about some of the impacts on the crude side. How about the product side for Valero, and especially in regards to your Quebec City plant? What kind of volumes does Quebec send to the New York Harbor? And if there were tariffs imposed, do you think it'd be pretty easy to ship those volumes to Latin America or Europe, or would we expect to see lower operating rates at Quebec City? Thanks. Yeah. This is Gary. For the most part, our Quebec system is short gasoline, so we import gasoline. A lot of that tends to come from Pembroke. There are periods in the year where we're long diesel, and typically that does go to New York Harbor. We could place those barrels anywhere in the world. So I wouldn't expect to see a throughput reduction as a result of tariffs. Sounds good. And then you mentioned some of the potential impacts from the 45Z. One other impact is that RD from foreign UCO appears to no longer qualify for a credit. Is DGD a major importer of foreign UCO? And if so, how would you expect to replace those volumes? Yeah. So you're correct. Foreign UCO no longer qualifies for domestic RD. Our foreign UCO is and has always been pointed at SAF going into Europe and the UK. So the PTC doesn't really change what we were going to do strategically with that feedstock. And so that's our view is we'll continue to run that into SAF, into the Europe and UK markets. Great. Thank you. Thank you. The next question is coming from Jason Gabelman of TD Cowen. Please go ahead. Yeah. Hey, morning. Thanks for taking my questions. I wanted to ask first on the CapEx budget. I believe you said $1.6 billion of sustaining CapEx, which is about $300 million above the five-year average. It's the highest level since 2019. So I'm wondering if that is an indicator of above-average turnaround activity in your system for 2025. And if not, what's driving that higher sustaining spend? Hey, Jason. This is Lane. So normally we sort of talk about our sustaining capital in terms of sort of average. And so we average about. We sort of think about it being $1.5 billion. That's inclusive of turnaround, inclusive of sort of CapEx for ongoing sort of sustaining operations. And so if you sort of and catalysts. And so when you think in your mind, well, if it's lumpy, if it gets lumpy on the higher side or the lower side, the only thing it can be is additional turnaround work. Okay. Thanks. And my follow-up is just sorry, I'm going to ask another one on the Canadian tariffs. Valero, I believe, has a lot of its refineries within foreign trade zones, and those foreign trade zones typically aren't subject to tariffs. So given that, one, can you just clarify that most of your U.S. Gulf Coast system is in foreign trade zones? And because of that, do you think you would be able to, if the tariffs are implemented in a very direct way, you'd be able to sidestep those tariffs? And also, do you get any benefit now from operating in those foreign trade zones? Thanks. Yeah. This is Rich Walsh. I would just say that you can't tell anything until you see what the program comes out with, right? So it just depends on how this is all structured. So we also bring in a lot and export a lot. And so that's really what the foreign trade zone helps with. And so I don't know that it's really trying to avoid domestic tariffs in any way along those lines. So until you see what they're proposing and how it's structured, you really can't tell whether there's going to be benefit or not. But we do have Foreign Trade Zones. Yeah. Oh, yeah. We have foreign trade zones. Got it. Great. Thanks for the caller. Thank you. At this time, I would like to turn the floor back over to Mr. Bhullar for closing comments. Thank you, Donna. Appreciate everyone joining us today. Obviously, feel free to contact the IR team if you have any additional questions. Have a great day, everyone. Thank you. Ladies and gentlemen, this concludes today's event. You may disconnect your lines or log off the webcast at this time and enjoy the rest of your day.