Welcome to the Valero Energy Corporation First Quarter 2025 Earnings Call. At this time, all participants are in a listen-only mode. A `-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, Homer Bhullar, vice president of investor relations and finance. Thank you. You may begin. Good morning, everyone, and welcome to Valero Energy Corporation's First Quarter 2025 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; Rich Walsh, our Executive Vice President and General Counsel; 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 am pleased to report that we delivered positive results for the first quarter despite heavy maintenance activity across our refining system in a tough margin environment in the renewable diesel segment. This is a credit to the strength and discipline of our operations, optimization, and commercial teams. Refining margins improved through the quarter, with U.S. light product demand slightly higher than last year and product inventories below the same period last year. On the financial side, we continue to honor our commitment to shareholder returns with a strong payout ratio of 73% in the first quarter. In January, our board approved a 6% increase to the quarterly cash dividend, further demonstrating our strong financial position. We continue to progress the FCC unit optimization project at St. Charles that will enable the refinery to increase the yield of high-valued products, including high-octane alkaloids. The project is estimated to cost $230 million and is expected to start up in 2026. We are pursuing other short-cycle, high-return optimization projects around our existing refining assets. Looking ahead, we expect tight product supply and demand balances and low product inventories to support refining fundamentals ahead of the driving season. Longer-term product demand is expected to exceed supply as there are limited announced capacity additions beyond 2025. In closing, we remain focused on the things that we can control, pursuing excellence in operations, deploying capital with an uncompromising focus on return, and honoring our commitment to stockholder returns. Our commitment remains underpinned by a strong balance sheet that provides us plenty of operational and financial flexibility. With that, Homer, I'll hand the call back to you. Thanks, Lane. For the first quarter of 2025, we incurred a net loss attributable to Valero stockholders of $595 million, or $1.90 per share, compared to net income of $1.2 billion, or $3.75 per share for the first quarter of 2024. Excluding the $1.1 billion pre-tax or $877 million after-tax asset impairment loss related to the West Coast assets, adjusted net income attributable to Valero stockholders was $282 million, or $0.89 per share for the first quarter of 2025, compared to $1.3 billion, or $3.84 per share for the first quarter of 2024. The refining segment reported an operating loss of $530 million for the first quarter of 2025, compared to operating income of $1.7 billion for the first quarter of 2024. Adjusted operating income was $605 million for the first quarter of 2025, compared to $1.8 billion for the first quarter of 2024. Refining throughput volumes in the first quarter of 2025 averaged 2.8 million barrels per day, or 89% throughput capacity utilization. Refining cash operating expenses were $5.07 per barrel in the first quarter of 2025. The renewable diesel segment reported an operating loss of $141 million for the first quarter of 2025, compared to operating income of $190 million for the first quarter of 2024. Renewable diesel sales volumes averaged 2.4 million gallons per day in the first quarter of 2025. The ethanol segment reported $20 million of operating income for the first quarter of 2025, compared to $10 million for the first quarter of 2024. Adjusted operating income was $39 million for the first quarter of 2024. Ethanol production volumes averaged 4.5 million gallons per day in the first quarter of 2025. For the first quarter of 2025, G&A expenses were $261 million, net interest expense was $137 million, depreciation and amortization expense was $691 million, and income tax benefit was $265 million. Net cash provided by operating activities was $952 million in the first quarter of 2025. Included in this amount was $157 million favorable change in working capital and $67 million of adjusted net cash used in operating activities associated with the other joint venture member share of DGD. Excluding these items, adjusted net cash provided by operating activities was $862 million in the first quarter of 2025. Regarding investing activities, we made $660 million of capital investments in the first quarter of 2025, of which $582 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 $611 million in the first quarter of 2025. Moving to financing activities, we returned $633 million to our stockholders in the first quarter of 2025, of which $356 million was paid as dividends and $277 million was for the purchase of approximately 2.1 million shares of common stock, resulting in a payout ratio of 73% for the quarter. On January 16th, we announced a 6% increase to the quarterly cash dividend on common stock from $1.07 to $1.13 per share, delivering on our commitment of a growing dividend. With respect to our balance sheet, we issued $650 million aggregate principal amount of 5.15% senior notes due 2030 in February and repaid the outstanding principal balances of $189 million of 3.65% senior notes that matured in March and $251 million of 2.85% senior notes that matured in April. We ended the quarter with $8.5 billion of total debt, $2.3 billion of total finance lease obligations, and $4.6 billion of cash and cash equivalents. The debt-to-capitalization ratio net of cash and cash equivalents was 19% as of March 31, 2025. We ended the quarter well-capitalized with $5.3 billion of available liquidity, excluding cash. Turning to guidance, we still 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 second quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.75-1.8 million barrels per day, Midcontinent at 385,000-405,000 barrels per day, West Coast at 240,000-260,000 barrels per day, and North Atlantic at 320,000-340,000 barrels per day. We expect refining cash operating expenses in the second quarter to be approximately $5.15 per barrel. With respect to the renewable diesel segment, we now expect sales volumes to be approximately 1.1 billion gallons in 2025, reflecting lower production volumes due to economics. Operating expenses in 2025 should be $0.53 per gallon, which includes $0.24 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 second 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 second quarter, net interest expense should be about $135 million. Total depreciation and amortization expense in the second quarter should be approximately $780 million, which includes $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia Refinery by the end of April 2026. We expect this incremental amount related to the Benicia Refinery to be included in D&A for the next four quarters, resulting in a quarterly earnings impact of approximately $0.25 per share based on current shares outstanding. For 2025, we still 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. 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. The 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 your handset before pressing the Star keys. One moment, please, while we pull for your questions. Our first questions come from the line of Manav Gupta with UBS. Please proceed with your questions. Good morning, guys. Very resilient earnings in a tough macro. I have two questions for Gary. I'll ask them upfront in the interest of time. Gary, there's a lot of chatter around here on tariffs and recessions and whatever. What are you seeing in terms of the market dynamic, supply demand out there for refined products? The second one is, can you talk a little bit about the crude differentials and the quality discounts given everything which is going around, OPEC probably raising volumes, LyondellBasell shutting down, and probably tariffs? If you could address those two questions. Thank you. Yeah, good morning, Manav. This is Gary. Happy to address that and kind of talk about what we're seeing on the commercial side of the business. Sales through our wholesale system were down in the first quarter a few percent from typical historic levels. Our product exports were up year over year, but down versus fourth quarter levels. None of this is really a reflection of demand, just more due to the heavy refinery maintenance we had during the quarter. If you look at the seven-day average trends to our wholesale system, we're back to just below that million barrel a day level. We're showing a 1% year-over-year increase in gasoline sales and a 6% year-over-year increase in diesel volumes. Diesel sales have really been supported by higher agricultural demand as we started planting season in the Midcontinent. If you look at the DOE demand data for total light products, it indicates a year-over-year increase in total light product demand in the neighborhood of 300,000 barrels a day, which we believe is pretty accurate. It looks to us like the DOE is under-reporting gasoline demand a little. If you look at the ethanol blending data, it would indicate gasoline demand flat to slightly up from last year. Jet demand year to date slightly up. And then a really nice bump in diesel demand driven largely by the cold temperatures we experienced early in the year. Globally, I think we've seen stronger light product demand as well and more than was expected. The consultants' data varies greatly here, but if you take an average of the data, it would show a year-over-year increase in total light product demand globally of around a million barrels a day, which we think is pretty close. Our data shows we had about 640,000 barrels a day of new refining capacity come online during the quarter, but then we had two refineries shut down with a combined capacity of 410,000 barrels a day. Total light product demand globally up a million barrels a day, 230,000 barrels a day of net refinery capacity additions, and then a little lower refinery utilizations due to turnaround. You combine all that and you would expect to see some inventory draws, which is what we've seen. Total light product inventory is drawn back to the point where once again below the five-year average range. Currently, 36 million barrels below the five-year average, 8 million barrels below where we were last year at this time. Gasoline inventory is drawn down to the bottom part of the five-year average range. Jet inventory is now below the five-year average levels. Diesel inventory is well below five-year average range, below last year, and now approaching the historically low levels we saw in 2022 and 2023. As we head into driving season, gasoline fundamentals look constructive. Gasoline inventory toward the bottom of the five-year average range. Demand at or slightly above last year. West Coast gasoline is a 12-year low for this time of year. Unemployment remains low, which historically translates into good gasoline demand. The strength in European gasoline is really keeping their barrels in Europe versus the normal transatlantic export flow into New York Harbor. Additionally, that strength in European gasoline is opening up more exports for U.S. Gulf Coast refineries into Latin America. Diesel looks very strong. We had good demand early in the year due to cold weather. We've seen imports as well as domestic production of renewable and biodiesel fall off, which has created incremental demand for refinery-produced diesel. Despite the fact that we're at or near record lows on total diesel inventory in the U.S. that we've seen in 2022 and 2023, the Arb to Ship on Explorer from the U.S. Gulf Coast to the Midcontinent is open due to the strong agricultural demand. The Arb to Ship on Colonial to New York Harbor is open. The Arb to Ship from the U.S. Gulf Coast to Europe is open, and the Arb to Ship to Latin America is open. When you look at record low inventories and still have open Arbs to ship product domestically and globally from the U.S. Gulf Coast, I think that speaks well for diesel, not just domestically, but also globally. VGO remains fairly expensive, indicating tightness in that market, which likely says FCCs and Hydrocrackers have to compete for incremental VGO barrels. Again, the fundamentals look very strong and have exceeded our expectations so far for the year. I think when you go through all this data, it's actually surprising we don't see stronger refinery margins. Based on the strong fundamentals, I'd say refinery margins are undervalued. I think right now it's the uncertainty around the economy. People have made assumptions of what happens with the economy and its impact on demand for our products, and those assumptions are really driving the market right now. Thus far, the economy looks like it's been fairly resistant, but we'll have to see. All of you guys probably have better insight to that than what I do. Turning to the crude differentials, it's been hard to really have clarity on what's going to happen with the crude differentials in the quarter. A lot of the discussions on tariffs and sanctions have certainly made that hard to see where the direction that's going. I think when you look at bullish factors, certainly the LyondellBasell refinery shutting down in the U.S. Gulf Coast, you put 200,000-250,000 barrels a day of additional heavy sour barrels on the market. We saw record Canadian production in the first quarter, and it looks like Canadian production continues to ramp up. Then we've had the announcement of 500,000 barrels a day of additional OPEC Plus production. News yesterday was that maybe even higher than the 500,000 barrels a day. Offsetting that somewhat, we continue to see Mexican production decline a little, and then the potential for sanctions impacting Iranian and Venezuelan production. You combine all that, and I think the likelihood is that you see more medium and heavy sour barrels on the market, which speaks well to the differentials moving forward. I do not think there is much room for them to come in any because medium and heavy sours are already trading at economic parity to light sweet. In fact, we are seeing economic signals approach the point where you would back off of heavy feed stocks and even spare coking capacity. Thank you so much. Thank you. Our next questions come from the line of Roger Reed with Wells Fargo. Please proceed with your questions. Yeah, thank you. Good morning. Good morning, Roger. Morning, everybody. Just to come back on the guidance just for the second quarter, a little light relative to what I was anticipating, a little, I guess you could even say a little light relative to a year ago. Is this a function of maintenance? Because it seems to run a little counter to the explanation you were just offering there, Gary. Hey, Roger, this is Greg. Yeah, it is maintenance, and you can see it in a couple of the particular regions, North Atlantic and Midcontinent. You can see those quite a bit lower, and that's all maintenance driven. In the Gulf Coast and the West Coast, where most of the maintenance is complete, we're getting those kind of back to what you would typically see for throughput. Okay. Homer, I think this is just to clarify with you. When we talked about maintenance before, you've pointed out there can be a difference between crude unit maintenance and downstream maintenance. Presuming the guidance is crude unit maintenance, are we looking at the ability to run some of the downstream units, or should we take this at face value on volumes? Roger. It's Greg again. When you see those big throughput impacts, that tends to tell you that's the front end of the plant that's shutting down. We may try to run some downstream stuff, but it really depends on being able to get feed stocks into some of those particular markets. You think about the Midcontinent in particular, it's hard to bring other feed stocks in when you've got the front end of the plants down. You probably don't see as much of that in those regions, North Atlantic as well as you would see in the Gulf Coast. Great. That would have been my interpretation as well. Okay. Thank you. I'll turn it back. Thank you. Our next questions come from the line of Ryan Todd with Piper Sandler. Please proceed with your questions. Sure. Great. Thanks. Can you walk through the decision to close the Benicia refinery? Why now? What's changed? How should we think about the future risks to or the environment for the Wilmington refinery? Hey, Ryan it's Lane. When you think about the West Coast, I mean, California has been pursuing policies to move away from fossil fuels really for the past 20 years. The consequence of that is the regulatory and enforcement environment is the most stringent and difficult of anywhere else in North America. If you sort of think about what's happened on the West Coast since COVID, you've had several refineries closed. You're going to have another one closed this year. You start thinking about our asset base, and we're looking at the difficulty and all that. Benicia operates in the more difficult part of California with respect to the regulatory and enforcement side of this. On top of that, Benicia costs considerably more to maintain versus Wilmington. Okay. Thank you. Maybe shifting to renewable diesel markets, can you maybe walk through where we are on the, I mean, markets are trying to reach a new equilibrium under the new PTC regime. Can you maybe walk through where you think we are on the path to normalization and the timing to get there? Within that, I know you booked some 45Z credits in the first quarter. How much should we expect to see you booked? Should we expect to see that improve going forward from here? I guess maybe just some thoughts on how that market normalizes and maybe improves over the course of the year. Yeah, this is Eric. As you look at the first quarter, one thing that we should be clear about is that we had catalyst changes on DGD1 and DGD2. You had a pretty significant volume impact in the first quarter that reduced a lot of the margin opportunity for the segment. As you said, we got PTC guidance in January, and in February, we pivoted both operations and our contracts with customers in order to begin capturing the PTC. We did not get a complete capture in the first quarter. We did get capture on NAFTA and SAF, but only about half of the RD was able to be captured because it took us a little while to get those contracts and operations shifted over. Going forward, we see we should get 100% of eligible credits on PTC for all three of those product lines. Now, there are a lot of feedstock eligibility issues, so it's not 100% of our full volume. It'll be 100% of the eligible feedstocks. As that market is figuring out where the net balance is going to be between tariffs, PTC eligibility, and just call it flat price, we still see the market moving around there. Going forward, we think we've got that solved. As I said before, if you look at the shift from the $1 blender tax credit to this CI-based PTC, everyone knew there was going to be a drop in profitability going from the previous program to the current program. For PTC on waste oils, which are still the most favored feedstocks, that's 50-60 cents a gallon on primarily domestic feedstocks. Foreign feedstocks into SAF still count, but foreign feedstocks into RD do not. We have kind of a unique position there that as you look at your product allocations and your feedstocks, you have to take all of that into account. The other backdrop you have here is we've seen a big drop in domestic production, as Gary mentioned in his comments on the macro. You've also seen a big drop in foreign imports. The overall D4 RIN production has dropped pretty significantly. Combine that with this conversation that a lot of trade groups have gone to the EPA and asked for an increase of the RIN obligation beginning in 2026 and 2027 into 5.25 billion gallons for D4 RINs. You have a drop in production plus this anticipated increase in obligation. There is some potential tailwind out there in the future at some point if that gets proposed to the EPA and the EPA approves that probably sometime in the third or fourth quarter of this year. You have got a little bit of upside potential there. The other one that may be more recent or sooner to be revealed is the California LCFS program. Those obligations that were pushed off initially have been resubmitted to the OAL for approval. In the next 30 days or so, we should hear from California on whether or not they are going to increase their LCFS obligation by 9% going back to January 1. That should put another potential increase of LCFS prices on the horizon. It is hard to predict what California will do on that, but that is the timeframe for when we should get an answer, yes or no, on LCFS modifications. If you look at all of this and think about, okay, how does this all net out? We have seen the D4 RIN move. The LCFS price has not. On the D4 RIN, the increase is not enough to offset in the veg oil space. It only gets $0.10-$0.20 a gallon on the PTC. You still need RINs to go up another $0.40 or $0.50 in order to offset that $0.80 loss that veg oil is seeing, which is why you're seeing a big drop in domestic BD production. As the market tries to figure this out, the D4 RIN has to move up substantially. Whether that driver is a continued drop in production or imports and/or this anticipated increase beginning in the 2026 obligation, that's going to set what the overall volume looks like in terms of performance versus overall obligation. It looks like in 2Q, we're starting to see some of this potentially improve. I think it's still more of a the upside looks more like a back half of the year for the RD segment. I think for our platform specifically, which is still the most advantaged platform when it comes to CI market access and just overall ability to demonstrate compliance into all these different programs, we still see we'll capture the PTC, and we'll be the ones that can optimize between the feedstocks that are most desired into these compliance programs and then whether or not they're covered by the PTC. Great. Thanks for all the detail. Thank you. Our next questions come from the line of Theresa Chen with Barclays. Please proceed with your questions. Hi, Eric. Just to follow up on that last question. It sounds like the drop in production and imports is structural absent recovery in D4 RINs and maybe more to come on that front. From a supply and competitive landscape perspective, do you see some of that supply creeping back over time, or how does this settle out as the market tries to find equilibrium? I think if you look at maybe I'll put it in context of this RIN obligation. At the current 3.3 billion gallons versus what we've seen in the last couple of years, the RD and BD segment production capacity could far exceed that RIN obligation. What was really keeping a lot of that volume flowing was the BTC. When you take the BTC out, then suddenly, as we've always said, the BTC is what kept the marginal producer operating. We see a lot of those, and this is public. There's a lot of announcements of BD and RD operations that are either slowing down or taking a pause in operations. Everyone is looking to see when that marginal producer will come back into market because right now, there is not an incentive for them to run, particularly any kind of veg oil-based BD or RD. If you see the obligation increase or you see the RIN bank tighten to the point where we are physically short, I think this year we are still long in the D4 market, but it is starting to tighten. You can kind of see this in the D4, D6 RIN spread, which is sometimes reaching 10 cents a gallon on the differential there. There is some anticipation and recognition of this. I think as that continues through the year, if you see RIN prices react, like I said, it has got to be 40 or 50 cents additional move from what it has already moved. We have seen D4 RINs go from the 60s up into the 90s, sometimes over a dollar. That is still not enough to incentivize the BD producer that used to get a dollar. How that will rationalize is I think everyone will, and there is no question from an ag standpoint, the farmers want to run their BD units and their soybean oil. Otherwise, you are going to see soybean oil continue to get stranded from a fuel market. I think it is really waiting to see if that RIN is going to move to offset the loss of the transition from the BTC to the PTC. I think that is the only way you are going to see incremental production come on in the back half of the year. That's helpful. Thank you. On Mexico within the refining segment, would you be able to provide an update on your suspension from the registry of importers? What led to this and what is the path forward from here? Yeah, Theresa, this is Gary. If you haven't heard, happy to announce that we have had our import permit reinstated. Go through a little of the history. On April 9, we were notified by Mexico's tax administration service that our import permit was being temporarily suspended. We were told at the time that customs in Mexico had some questions as a result of an investigation that they had done that we weren't privy to. Since we began our operations in Mexico, we maintained a policy of full cooperation with all the authorities there, implemented rigorous traceability and security controls throughout the supply chain. It was disappointing to us that our permit was suspended without any prior notification or opportunity to clarify. The timing of all this right before the Easter holiday was especially bad. Nevertheless, once we had the opportunity to reach out to the stakeholders in country, sit down, go through all the records and data with customs in Mexico, the customs authority recognized that Valero was in full compliance of our import reporting and tax obligations, and we were quickly exonerated of any wrongdoing. Although this is all unfortunate and created significant supply disruption for our customers, it is part of an effort in Mexico to limit the importation of illegal fuel, which is an effort we very much applaud and will positively impact our business down there going forward. Thank you. Thank you. Our next questions come from the line of Neil Mehta with Goldman Sachs. Please proceed with your questions. Ed, good morning, Lane team. You guys have done a great job of continuing to return cash to shareholders, and you've talked about cash balances of $4 billion to $5 billion, and I think you're at $4.6 billion right now. Just talk about in this period of macro uncertainty, how are you thinking about taking advantage of the balance sheet to shrink the share count? Hey, Neil, it's Homer. Yeah, you're right. I mean, obviously, given the strength of our balance sheet and our current cash position, we have plenty of flexibility, and we continue to lean into buybacks with excess free cash flow going to shareholder returns. In fact, as I'm sure you're aware, we've drawn down excess cash the last three quarters as we've guided to. Hopefully, this quarter demonstrates the resilience of the portfolio even in a low-margin environment. I think looking forward, assuming the balance sheet is strong as it is now, and like we've said in the past, where our CapEx and dividend are covered, that commitment to shareholder returns should remain afloor, and any sort of excess free cash flow will continue to go towards share buybacks. Okay. Thank you. To follow up, Gary, to your comments about just inventories for diesel in particular, distillate, it looks really tight relative to the margins. Can you speak specifically to that product and if you think about the distillate pool, how you're thinking about the outlook for jet as it feeds into that? A lot of moving pieces in diesel, but it feels like it's ground zero for the refining debate. Yeah, I agree. Again, kind of some of the things I pointed out, I mean, it's kind of amazing when you're close to historic lows on diesel inventory in the United States, and yet we have open arms to export to Latin America and Europe. It tells you both those regions are very short diesel as well. On jet, we saw very strong nominations the first part of the year. You're starting to see some of the airlines talk about weaker jet demand moving forward. We haven't seen signs of that yet. Historically, though, when people start to switch and not take flights for their summer vacation plans, it translates into higher gasoline demand. Thanks, Gary. Thank you. Our next questions come from the line of John Royall with the JPMorgan. Please proceed with your questions. Hi, good morning. Thanks for taking my question. My first question is a follow-up on your 2Q guide. Lane mentioned operational flexibility in his opener. Should we think about throughputs as relatively locked in sitting at the end of April, or could we see some economic adjustments if this downside demand case were to materialize and reflect more in spot cracks? Hey, John, it's Greg. I would tell you that's how we see the quarter shaping up as we look at it now. Obviously, as we always do, we evaluate market conditions and adjust our plans accordingly. I think if you think about what Gary just shared, kind of the macro view, it'd be hard to imagine in this short-term period, this next few months, that we would see ourselves moving to some kind of a lower throughput on an economic basis. I think you can probably say this is where we expect to be. If things improve market-wise, we're obviously going to continue to maximize throughput, maximize margin to capture as much value as we can. Yeah. Really, our lower guide is a function of maintenance, not some outlook that we think there's lower demand in the future. Yeah, absolutely. Maybe just on that, we always talk about doing a lot of maintenance in the first quarter. Again, if you think about the regions we're talking about, the Midcontinent and the North Atlantic, those aren't regions that really lend themselves from a weather perspective to doing a lot of work early in the year. You kind of wait till you've got a little better weather, take less risk from that standpoint. That is why you see a bit more work in the second quarter than you might typically see out of us. You do not see a lot in the Gulf Coast where we tend to do that in the first quarter. That's very helpful. Thank you. My follow-up is just another one on Benicia. Forgive me if I'm over-analyzing this, but just reading the wording on the press release, it struck us as maybe not 100% definitive in terms of the plan. Maybe my question is, is the door open for the state or the city to make any changes or concessions that could cause you to think differently about your plans for Benicia? Do you expect that there will be some sort of discussion there? Yeah, this is Rich Walsh. Let me try to answer that. I mean, just to be clear, our current intent is to close the refinery. Obviously, there's been some initial concern from the state leadership, and we've already had meetings with the CEC, and we're working with them to minimize the impacts that would result from the loss of the refinery. I do think there's a genuine interest in California to avoid the closure, but it's also a really very complex regulatory and policy-driven environment that we're dealing with. If you understand that challenge and how significant it is, I think you need to factor that in. Yeah, we are having discussions with the state, but our intent right now is to close the refinery. Very clear. Thank you. Thank you. Our next questions come from the line of Doug Leggate with Wolfe Research. Please proceed with your questions. Thanks. Good morning, everyone. Lane, I'm sorry to pound on the West Coast, but I also have a question on that, if you don't mind. In the press release, you—sorry, I feel like it's been hammered pretty heavily this morning already, but in the press release, you did mention that you also had impaired Wilmington. I think that was the implication of the language. Can you talk about what the prognosis is for Wilmington as part of this overall debate over the future viability of the West Coast assets? Now, I've got a follow-up on the same topic, please. I'll let Homer start to explain the impairment process, and then I'll add to it. Go ahead. Yeah, Doug, so obviously, we performed an asset impairment on both of these assets based on the continued evaluation of strategic alternatives, right, which remains. Based on the analysis, we obviously concluded that the current book value of the refinery was not recoverable. Therefore, we revised it down to reflect the fair value of the assets, which resulted in an impairment loss, as you cited, both for Benicia and for Wilmington. In terms of the overall impairment, it was $1.13 billion, of which about $900 million was for Benicia, $901 million, and Wilmington was $230 million. Okay. That's helpful. My follow-up, guys, is really to think about implications going forward. I don't know the extent to which you can share, but obviously, presumably, these are free cash flow negative. Otherwise, you wouldn't be taking the impairment. You can give some idea of what the implications are for your capital spending going forward when Benicia does go offline and whether Wilmington is still free cash flow positive. I'll leave it there. Thanks. Doug, this is Greg. I'll take a shot at answering that the best I can. Others might jump in. Yeah, we don't tend to talk about refinery by refinery performance, but I think it's probably fair to say on the West Coast, if you look back over the last 10 years, Benicia was generally higher operating expense, lower EBITDA, higher capital, and, as a result, obviously, lower cash flow compared to Wilmington. I'm not sure we'll break it down any more detailed than that, but that would give you some sense for how those perform relative to each other. I think it's been mentioned when you have a large turnaround in front of you, which is a large cash outlay, and you think about how the facility has performed looking back, that's no guarantee of the future. It does give you some sense or cause you to pause as to whether or not this is the time to take different action, which is what you see us doing. Great. That's very helpful, guys. Thanks so much. I'll take the rest offline. Thank you. Our next questions come from the line of Paul Chang with Scotia Bank. Please proceed with your questions. Hey, guys. Good morning. I have to apologize because I want to ask a slightly different angle on Wilmington. Wilmington, can you tell us that when was the last major turnaround that you did at Wilmington? Let me go back and look. The biggest one's the FCC out. We just did it last year. Yeah. Just recently, we did the FCC unit, Paul, if that's what you're looking for. Yeah. I mean, should we assume that as a result, at least for the next two or three years, you do not have any major outlay that you will expect for Wilmington? In other words, then whatever decision that you're going to make, it's probably going to be post two or three years? Hey, Paul, nice try, but unfortunately, we can't comment on our future turnaround plan. Okay. That's fair. Second question on SAF, maybe this is for Eric. What's your production expectation in the second quarter based on the current margin for SAF? Also, what's the current timeline and game plan for the second unit, FID? Yeah. Second quarter, I would say we are still not in a max SAF mode. If you look at Europe, which the mandate there is still one of the primary outlets for SAF, we see HBO over SAF in the Argus quotes. Our last barrel economics are still looking at some barrels are more economic to put into an RD product into Europe. Overall, we see growing interest in SAF. We see actually some growing interest in the voluntary markets with some companies that are remaining committed to their carbon reduction commitments. We do see that SAF is continuing to grow and the contracts are continuing to grow. In terms of when we would look at a second unit, I think we still have to see how this market develops through the rest of this year. We see in the U.S., there's interest in the U.S., and like I said, particularly some of these corporations that are maybe looking to buy direct rather than through an airline. Until we see demand exceed our capacity and we get some certainty on an outlook in terms of policy, maybe going back to the LCFS and RIN comments I made earlier, it's hard. We hard. We have the engineering done to do the same project at St. Charles, but right now, I think we'd have to wait and really see how this market develops before we did any further commitment from a certainty standpoint. Hey, Eric can you help us understand the economic? Because I thought with the PTC, you get a dollar per gallon for SAF. That should help to really move up the economic and assume you get some premium for selling SAF compared to RD. You're saying that even in today's economic and with the PTC, it's still not sufficient for you to try to max out the SAF compared to RD? That is correct. The PTC is not adequate by itself to justify the project. The other thing to keep in mind is when you are allocating, if you have a unit that makes 50% RD, 50% SAF, you can't allocate all the feedstocks to one product. You have to allocate based on your product mix coming off the tower. What you see is, given, say, a domestic feedstock, you'll get 50% of PTC on your SAF product and then 50% of your PTC on your RD product. You can't allocate 100% to SAF. Because of that split and the fact that half of the product you make gets a lower PTC, you have to look to SAF to carry more of the work in order to justify the project. As I said before, the PTC is much lower compared to the BTC, and that is reducing the overall RD margin. If you think about if RD was break-even and SAF was positive, then the SAF market has to be even stronger in order to meet your minimum 25% return, whereas before, both products were positive. Really what we're looking for is you've got to see the RD market become more attractive. I think you still have to see the SAF demand exceed our current capability before we would commit to a further project. Yes, on paper, it looks like it should work, but I think you've got to see the market actually create a pull before we would commit to doing that project. Okay. Thank you. Thank you. Thank you. Thanks, Paul. Thank you. Our next questions come from the line of Joe Laetsch with Morgan Stanley. Please proceed with your questions. Great. Thanks. Good morning. Thanks for taking my questions. I was hoping to get your perspective on pad size going forward. With one refinery closing this year, Benicia closing early next year, California is going to become even more reliant on imports. Does this result in just a more volatile and probably higher margins to pull sufficient imports on the West Coast, or how do you see it playing out? Yeah, this is Gary. Our view has been California will potentially be short gasoline for several years with periods of higher import needs during turnarounds and unplanned outages. Diesel, the market looks well supplied, but the tighter supply-demand balances will likely cause more volatility in the market when unplanned refinery outages occur. However, from what we've seen so far, these tend to be fairly short-lived and only last until waterborne barrels can make their way into the market. Great. Thanks. That makes sense. Shifting gears, I wanted to ask about the ethanol segment. While margins are still challenged, capture came in a bit better than we had expected. Could you just talk to the latest dynamics for that segment and outlook going forward for this year? Yeah, this is Eric. I think it's interesting. We're about where we were last year. If you look at the dynamics of this current outlook, you're going to have a record planting for corn. Brazil has a record crop that is in the ground. We expect corn prices, flat corn prices, to be at or below where they are from last year. Natural gas is cheap. From a feedstock standpoint, ethanol looks advantaged. Obviously, it follows a lot of gasoline demand. We're the largest exporter of ethanol, so we saw record exports in the first quarter. I think it's going to be a question of, do you see the gasoline demand that Gary mentioned earlier? If so, then I think ethanol will look stronger, certainly in the second and third quarter. Right now, I'd say we're kind of right around mid-cycle. Last year was right around mid-cycle. I'd say ethanol looks like sort of a mid-cycle year from an outlook standpoint. From our operation plan, I mean, we'll be at max production given these economics. Great. Thanks for taking my questions. Thank you. Our next questions come from the line of Jason Gabelman with Cowen. Please proceed with your questions. Yeah. Hey, morning. Thanks for taking my questions. The first one's related to natural gas dynamics, and it's a two-parter. In the U.S., you see natural gas prices move higher, impacting your operating expense. I wonder if you're doing anything on the ground to mitigate that expense. Conversely, in Europe, given you have an asset there, as natural gas prices are moving lower, are you seeing the ability for that region to run its secondary units at higher rates and add more product to the market? Thanks. Hey, Jason. It's Greg. I'll start in the U.S. You've seen a lot of volatility in the natural gas market, and it's been regional as well. A lot of that has been both expectations and actual performance of some of these LNG facilities. You've had a fair amount of transportation and logistics disruptions as well. With that volatility, we've been a bit cautious to try to go out and do anything on a forward basis and have stuck to buying gas on a kind of rateable as-needed basis. The big question there still remains to be the LNG market and how that materializes in terms of actual liftings out of the U.S. Again, as you know, some of that depends on where that LNG is pointed and some of the economic factors that will drive that. In Pembroke, the only thing I could really say about that is where natural gas prices are currently for our operation, they are not causing us to really change our mode of operation. They are in a place where we are going to run the way we typically run, maximizing throughput, maximizing production. The only thing we ever look at there is maybe shifting fuel sources between natural gas and different NGLs that might prove to be a bit more economic. That is a fairly typical optimization we do on a regular basis. Okay. I think most of my other questions were answered, so I'll leave it there. Thanks. Thanks. Thank you. Our next questions come from the line of Jean Ann Salisbury with Bank of America. Please proceed with your questions. Hi. Good morning. Can you talk about what you expect for the one-time overall cash impact that you expect from closing Benicia between the land value, selling down inventory, and then just closure cash costs? Is Benicia a good proxy for the exit cost of a U.S. refinery? Yeah. You might have seen in our 8K, we disclosed what the ARO for the asset was going to be. Yeah. Yeah. I Yeah. I mean, I think that's the number. I guess you also have the liquidation of inventory, right, as a part of the. Yeah. From a cash flow standpoint. Yeah. Yeah. This is Jason. You'll get the cash for the inventory fairly quickly. The other cash will be expended that's represented by the ARO for a series of years, several years after the closure, as we undertake cleanup and dismantling and things like that, and any realization of real estate-related proceeds several years out too. Okay. Thank you. As a follow-up, LPG tariffs on U.S. LPG have kind of gone into effect in China. Do you see this materially impacting feedstock costs or just naphtha or light ends pricing if it continues? Jean, this is Greg. Yeah. I'll start. Gary may have something to add. At this point, we haven't seen it have much of a disruption on overall trade flows and market prices here in the U.S. I think it'll remain to be seen whether that starts to develop as the year progresses. Yeah. I think the combination of what's happening in China and Venezuela, naphtha is still flowing to Venezuela as diluent, but that'll kind of come to an end at the end of May. At that time frame, it's likely that you could see naphtha get a little weaker. Okay. Great. That's all for me. Thank you. Thank you. Our final questions will come from the line of Matthew Blair with Tudor Pickering Holding Company. Please proceed with your questions. Great. Thanks. Good morning. You provided some helpful commentary on the biofuel regulatory front in regards to things like the RVO and the California Low Carbon Fuel Standard. I wanted to get your take. Do you see momentum building for nationwide E15? If so, could you talk about how that might affect your business? Yeah. This is Eric. I think there's a little bit of a mess in the Midwest right now where the seven governors asked for E15 without the one-pound waiver and then realized within weeks of converting to summer grade that that creates a lot of complexity in terms of the supply into the Midwest, that they then asked the EPA to grant a 20-day emergency waiver again for the one-pound waiver for both E10 and E15. I do not think you see a lot of positive support for that supply chain completely shifting to E15. There is still a lot of complexity at the retail level, at the consumer level's willingness to switch. Now, that all being said, in a lot of those Midwest states we are watching, we do see some incremental E15. It is not substantial growth in those sales, but we are seeing some incremental sales of E15. I think nationally, we're still far away from that becoming a reality or even a proposal. The governors did ask for that, but I doubt EPA is going to do that from a blanket standpoint for the entire U.S. The other thing I would say, just from a fundamental standpoint, the U.S. ethanol production is slightly long into an export that we mostly perform, but there is not enough ethanol in the U.S. to go to E15. I think we've done the math, and you can get to a max of about E12. If there was some kind of mandate to go to E15, you would be short in the U.S., and it would require probably in the short term some import of ethanol from likely Brazil. You look at all of that from a policy standpoint, I think you'll continue to see the Midwest states push for E15. They are getting some traction there, but that commercial growth is very slow, and I don't see that going beyond the Midwest states anytime soon. Great. Thank you. Then on the refining side, do you think it's reasonable to assume a quarter-over-quarter improvement in capture for the second quarter as you roll off the maintenance from the first quarter, or are there other considerations that we should take into account? Hey, this is Greg. You know how this goes. There's lots of factors that will have an impact on capture, a lot of the secondary products, market structure on the crude side. It's hard to say where things go. A couple of things that tend to be fairly structural on a seasonal basis. As we pull butane out of the gasoline pool as we move into the summer, that tends to work against us on capture. That's one thing to watch. Other than that, it's hard to say this early in the quarter where things would go. As far as maintenance goes, to the extent that our outages have a larger impact on throughput, probably says they'll have less of an impact on capture rate. We'll have lower throughput, but you'll see the margin will move kind of in concert with that. Great. Thanks for your comments. Thank you. We have reached the end of our question and answer session. I would now like to hand the floor back over to Homer Bhullar for closing comments. Thanks, Daryl. I appreciate everyone joining us today. Obviously, feel free to contact the IR team if you have any additional questions. Thanks, everyone, and have a great day. Ladies and gentlemen, thank you. This does conclude today's teleconference. We appreciate your participation. You may disconnect your lines at this time. Enjoy the rest of your day.