Greetings and welcome to the Valero Energy Corporation First Quarter 2025 Earnings Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Homer Bhullar, VP of Investor Relations and Finance. Thank you. You may begin.

Thank you. Our Chairman, CEO and President Lane Riggs, our Executive Vice President and CFO Jason Fraser, our Executive Vice President and COO Gary Simmons, our Executive Vice President and General Counsel Rich Walsh, and several other members of Valero's senior management team are with us today. If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures 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 and 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, and in January, our Board approved a 6% increase to the quarterly cash dividend, further demonstrating our strong financial position. We continue to progress the SEC unit optimization project at St. Charles that will enable the refinery to increase the yield of high-value products, including high-octane alkylates. 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 returns, 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. So 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's 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 pretax 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 a $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 membership 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 16, we announced a 6% increase to the quarterly cash dividend on common stock from $1.07 to $1.13, 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 February 19, 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 million to 1.8 million barrels per day, Mid Continent at 385,000 to 405,000 barrels per day, West Coast at 240,000 to 260,000 barrels per day, and North Atlantic at 320,000 to 340,000 barrels per day. We expect refining cash operating expenses in the second quarter to be $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 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. 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.

Good morning, Manav. This is Gary. Happy to address that and show you 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 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 1,000,000 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 planning season in Mid Continent. 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 underreporting gasoline demand a little. If you look at the ethanol blending data, it would indicate gasoline demand flat 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 vary 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 in 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. So total light product demand globally up a million barrels a day, 30,000 barrels a day of net refinery capacity additions, and then a little lower refinery utilizations due to turnaround. So you combine all that and you would expect it to see some inventory draws, which is what we've seen. Total light product inventory has drawn back to the point where once again below the five-year average range, currently 36,000,000 barrels below the five-year average, 8,000,000 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 inventories are 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 at a twelve-year low for this time of year. Unemployment remains low, which historically translates into good gasoline demand. Then the strength in European gasoline is really keeping their barrels in Europe versus the normal Transatlantic export flow in the New York Harbor. Additionally, that strength in European gasoline is opening up more 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 diesel inventory in the U.S. that we've seen in 2022 and 2023 the yard to ship on Explorer from the U.S. Gulf Coast to the Mid Continent is open due to the strong agricultural demand. Arb de 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. So, you know, 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. So, you know, 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, you know, the uncertainty around the economy. People have made assumptions about 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 into that than I do. Turning to the crude differentials, you know, 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, you know, when you look at bullish factors, certainly, the Lyondell refinery shutting down in the U.S. Gulf Coast put 200,000 to 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. And then we've had the announcement of 500,000 barrels a day additional OPEC plus production. News yesterday was that maybe even higher than the 500 barrels a day. Offsetting that somewhat, you know, we continue to see Mexican production decline a little. And then the potential for sanctions impacting Iranian and Venezuelan production. But 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 don't think there's much room for them to come in any because, you know, medium and heavy sours are already trading at economic parity to light sweet. And in fact, we're seeing economic signals approach the point where you would back off a heavy feedstock and even spare coking capacity.

Thank you so much.

Thank you. Our next question has come from the line of Roger Read with Wells Fargo. Please proceed with your questions.

Yes. Thank you, and good morning.

Hey. Good morning, Roger. I'd like to

Good morning.

Everybody. I'd like 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 Mid Con, you can see those quite a bit lower and that's all maintenance-driven. 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. And then 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. So 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. You know, is 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, it really depends on being able to get feedstocks into some of those particular markets. You think about the Mid Continent in particular, it's hard to bring other feedstocks in when you've got the front end of the plants down.

So probably don't see as much of that in those regions, North Atlantic as well as you would see in, like, the Gulf Coast.

Great. That's—

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.

Great. Thanks. Can you walk through the decision to close the Peninsula refinery? Why now? What's changed? How should we think about the future risk to or the environment for the Wilmington refinery?

Hey, Ryan. It's Lane. So, you know, when you think about the West Coast, I mean, California has been pursuing policies to move away from fossil fuels for the past twenty years. And the consequence of that is the regulatory and enforcement environment is the most stringent and difficult of anywhere else in North America. You know? And so if you sort of think about what's happened on the West Coast since COVID, you've had several refineries closed. You have another one closed this year. So then you start thinking about our asset base. You know, and we're looking at the difficulty of all that. So Venetia operates in the more difficult part of California with respect to the regulatory and enforcement side of this. And then on top of that, the Venetia cost considerably more to maintain versus Wilmington.

Okay. Thank you. And then maybe shifting to renewable diesel markets. Can you walk through where we are on the— I mean, the markets are trying to reach a new equilibrium under the new, you know, PTC regime. Can you walk through where you think we are on the path to normalization? And the timing to get there and, you know, within that, I know you booked some 45 z credits in the first quarter. How much should we expect to see you book? Should we expect to see that improve going forward from here? So I guess maybe just some thoughts on how that market normalizes and maybe improves over the course of the year.

Yes. So as you look at the first quarter, one thing that we should be clear about is that we had catalyst changes on DGD one and DGD two. So you had a pretty significant volume impact in the first quarter. That reduced a lot of the margin opportunity for the segment. But 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. So we didn't get a complete capture in the first quarter. We did get capture on NAFTA and staff 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 a percentage 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 a percentage of our full volume. It'll be a percentage of the eligible stocks. And so as that market is figuring out where the net balance is going to be between tariffs, PTC eligibility, and just flat price, we still see the market moving around there. But going forward, we think we've got that solved. So, you know, as I said before, if you look at the shift from the $1 lender's 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, we anticipate that to be 50 to 60 cents a gallon on primarily domestic feedstocks. Foreign feedstocks into SAF still count, but foreign feedstocks into RD do not. And so 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 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. So 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 in beginning in 2026 and 2027 into 5,250,000,000 gallons for D4 RINs. So you have a drop in production plus this anticipated increase in obligation, there is 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. So you've 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. So, in the next thirty days or so, we should hear from California on whether or not they're going to increase their LCFS obligation by 9%. Going back to January 1st. That should put another potential increase of LCFS prices on the horizon. So, hard to predict what California will do on that, but that is the time frame for when we should get an answer, know yes or no on LCFS modifications. So 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 10 to 20 cents a gallon on the PTC. You need RINs. You still need RINs to go up another 40 or 50 cents in order to offset that loss that veg oil is seeing, which is why you're seeing a big drop in domestic BD production. So 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. So it looks like, you know, the two in February, 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. And then I think for our platform specifically, which is still the most advantaged 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. So it sounds like the drop in production and imports is structural absent recovery. In deferments 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 you know, if you look at maybe I'll put it in context of this RIN obligation. At the current 3,300,000,000 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. And so what was really keeping a lot of that volume flowing was the BTC. And so when you take the BTC out, then suddenly, as we've always said, the BTC is what kept the marginal producer operating. So 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 or taking a pause in operations. And so everyone is looking to see when that marginal producer will come back into market because right now, there's not an incentive for them to run, particularly any kind of vegetable-based BD or RD.

So.

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. And you can kind of see this the D4, D6 RIN spread, which is you know, sometimes reaching 10 cents a gallon on the differential there. So there's some anticipation and recognition of this. I think as that continues through the year, if you see RIN prices react, like I said, it's got to be 40 or 50 cents additional move from what it's already moved. So we've seen go from the sixties up until the nineties, sometimes over a dollar. That is still not enough to incentivize the BD producer that used to get a dollar. And so how that will rationalize is I think everyone will, and there's no question from an ag standpoint, the farmers want to run their BD units and their soybean oil. Otherwise, you're going to see soybean oil continue to get stranded from a fuel market. So I think, you know, it's 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's the only way you're going to see incremental production come on in the back half of the year.

That's helpful. Thank you. And 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?

Yes, Theresa, this is Gary. If you haven't heard, I'm 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 the 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. So it was disappointing to us that our permit was suspended without any prior notification or opportunity to clarify, and the timing of all this right before the Easter holiday was especially bad. Nevertheless, once we had the opportunity to reach out to stakeholders and countries, sit down and go through all the records and data with customs in Mexico, the customs authority recognized that Valero was in full compliance with our import, reporting, and tax obligations, and we were quickly exonerated of any wrongdoing. So, you know, 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. 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 $4,000,000,000 to $5,000,000,000. I think you're at $4,600,000,000 right now. So 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 you can as I'm I'm sure you're aware, we've drawn down excess cash the last three quarters as we've guided to. And hopefully, this quarter demonstrates the resilience of the portfolio even in the low margin environment. So 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 a floor and any sort of excess free cash flow will continue to go towards share buybacks.

Okay. Thank you. And then the follow-up, Gary, to your comments about just inventories. For diesel, in particular, distillate, it looks really tight. Relative to the margins. So can you speak specifically to that product as you think about the distillate pool? How you're thinking about the outlook for J. T. 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, you know, kind of some of the things I pointed out, I mean, 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, you know, both those regions are very short diesel as well. You know, 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, you know, when people start to switch and not take flights for their summer vacation plans, it translates into higher gasoline demand.

Thank you. Our next questions come from the line of John Royall with JPMorgan. Please proceed with your questions.

Hi, good morning. Thanks for taking my question. So my 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 April? Or could we see some economic adjustments 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 the market conditions and adjust our plans accordingly. Think if you 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. So I think you can probably say this is where we expect to be. And if things improve market-wise, we're obviously gonna continue to maximize throughput, maximize margin to capture as much value as we can. Yes. So really our lower guidance is a function of maintenance, not some outlook that there's lower demand in the future.

Yeah. Absolutely. And 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 Mid Continent 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 until you've got a little better weather, take less risk from that standpoint. So that's why you see a bit more work in the second quarter than you might typically see out of us, and you don't see a lot in the Gulf Coast where we tend to do that in the first quarter.

That's very helpful. Thank you. And then my follow-up is just another one on Venetia and forgive me if I'm overanalyzing this, but just reading the wording on the press release, it struck us as maybe not a definitive in terms of the plan. So 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? And do you expect that will be some sort of discussion there?

Yes. This is Rich Walsh. Let me try to answer that. You know what? I mean, just to be clear, our current intent is to close the refinery. And, you know, obviously, there's been some initial concern from the state leadership and we've already had meetings with the CEC. 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, you know, it's also a really very complex regulatory and policy driven environment that we're dealing with. And so, you know, if you understand that challenge and how significant it is, I think you need to factor that in. But, you know, 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. Liam, 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 well, sorry. I feel like it's been hammered pretty heavily this morning already, but in the press release, you did mention that the 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, you know, debate over the viability and future viability of the West Coast assets? Now I've got a follow-up on the same topic, please.

Well, I'll start. I'll let Homer explain the impairment process, but then I'll add to it. So go ahead.

Yeah, Doug, the impairment— so obviously, we performed an impairment asset on both these assets based on the continued evaluation of strategic alternatives, right, which remains. But based on the analysis, we obviously concluded that current book value of the refinery was not recoverable. And so therefore, we revised it down to reflect the fair value of the assets. Which resulted in an impairment loss, as you cited, both for Venetia and for Wilmington. In terms of the overall impairment, it was $1.13 billion. Of which about $900 million was for Venetia and Wilmington was $230 million.

That's helpful. So my follow-up, guys, is really to think about implications going forward. And 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. But yes, so 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 ten years, Venetia was generally higher operating expense, lower EBITDA, higher capital, and then as a result, obviously, lower cash flow compared to Wilmington. So 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. And then 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, while 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 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 Cheng with Scotiabank. Please proceed with your questions.

Hey guys, good morning. I have to apologize because I want to ask slightly different angle on where we can. Can you tell us that when was the last major turnaround that you did? At Remington?

Let go back and look. The biggest one was the SEC. Okay. We just did it last year.

If that's what you're looking for.

Yeah. So 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 Remington? In other words, then whatever decision that you're going to make, this probably going to be posed two or three years.

Hey, Paul. Nice try, but unfortunately, we can't comment on our future turnaround plans.

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 Sandd? And also that, what's the current timeline and game plan for the second unit FID?

Yes. So second quarter, we 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 and the Arcus quote. So know, our last barrel economics, are still looking at some barrels are more economic to put into an RD product into Europe. So, but 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. So 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. You know, we see in the U.S., there's interest in the U.S. and, like I said, corporations that are maybe looking to buy direct rather than through an airline. But until we see, you know, demand exceed our capacity, and we get some certainty on an outlook in terms of policy, you know, maybe going back to the LCFS and RIN comments I made earlier, it's hard. We have the engineering done to do the same project they say Saint Charles. But right now, I think we'll have to wait and really see how this market develops before we did any further commitment from a certainty standpoint.

Hey. I mean, can you help us understand the economics? Because I thought, with the PTC, you get a solar per gallon for SAF. And so that should help to really move up the economic and assume you get some premium. For 7% comparing to Audi. So you're saying that even in today's economic and with the PTC, yes, still not sufficient for you to try to max out the SAF comparing to your RD?

So 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— so 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. And so what you see is given, say, a domestic feedstock, you have you'll get 50% of PTC on your SAF product and then 50% of your PTC on your RD product. You can't allocate a percentage to SAF. So because of that split and the fact that half of the products you make gets a lower PTC, you have to look to SAF to carry more of the work in order to justify the project. And as I said before, the PTC is much lower compared to the BTC, and that is reducing the overall overall RD margin. So if you think about if RD was breakeven and SAF was positive, then the SAF market has to be even stronger in order to meet your minimum 25% return whereas before, you know, both products were positive. And so really, what we're looking for is you've got to see the RD market become more attractive. And then I think you still have to see the SAF demand exceed our current capability before we would commit to a further project. But 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.

Thanks, Paul.

Our next questions come from the line of Joe Laetsch with Morgan Stanley. Please proceed with your questions.

Great. Thanks. Good morning, and thanks for taking my questions. So I was hoping to get your perspective on PAD5 going forward with one refinery closing this year, Venetia closing early next year. California is going to become more even more reliant on imports. This result in just a more volatile and probably higher margins to pull sufficient imports in the West Coast, or how do you see it playing out?

Yes. This is Gary. Our view has been California will be potentially 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, you know, 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.

That makes sense. And then shifting gears, I wanted to ask about the ethanol segment. While margins are still challenged, traffic 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, you know, it's interesting. We're about where we were last year if you look at the dynamics of this current outlook going to have a record planting for corn. Brazil has a record crop that is in the ground. So we expect corn prices to be at or below where they are from last year. Natural gas is cheap. So from a feedstock standpoint, ethanol looks advantaged. You know, obviously, it follows a lot of gasoline demand. We're the largest exporter of ethanol, so we saw record exports in the first quarter. But I think it's going to be a question of do you see the gasoline demand that Gary mentioned earlier? And if so, then I think ethanol will look stronger in the second and third quarter. But right now, you know, I'd say we're kind of right around mid-cycle. Last year was right around mid-cycle. So I'd say ethanol looks like sort of a mid-cycle year from an outlook standpoint. But 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.

Yes. Hey, morning. Thanks for taking my questions. The first one is 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. And I wonder if you're doing anything on the ground to mitigate that expense. And then 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. So 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. So 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 ratable 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 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 aren't causing us to really change our mode of operation. They're in a place where we're 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. But that's 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.

Thank you. Our final questions will 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 Venetia between the land value, selling down inventory, and then just closure cash costs? And is Venetia a good proxy for the exit cost of a U.S. refinery?

Yeah. So you might have seen, you know, in our 8k, we disclosed what the ARO hope for the was going to be.

Well, I guess I also have to look. Placement of inventory. Right? That's part of the—

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 is several years out too.

Okay. Thank you. And then 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 pricing if it continues?

Gene, this is Greg. Yeah. I'll start. Gary may have something to add. But 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. So I think it'll remain to be seen whether it 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 that May. At that time frame, it's likely that you could see NAFTA get a little weaker.

Okay. Great. That's all for me. Thank you.

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, and 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.