Greetings. Welcome to Valero Energy Corporation's first quarter 2022 earnings call. At this time, all participants are in listen-only mode. A question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero from your telephone keypad. Please note this conference is being recorded. At this time, I'll now turn the conference over to Homer Bhullar, Vice President, Investor Relations and Finance. Mr. Bhullar, you may now begin. Good morning, everyone, and welcome to Valero Energy Corporation's first quarter 2022 earnings conference call. With me today are Joe Gorder, our Chairman and CEO, Lane Riggs, our President and COO, Jason Fraser, our Executive Vice President and CFO, Gary Simmons, our Executive Vice President and Chief Commercial Officer, 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 investorvalero.com. Also, attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted 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 filings with the SEC. Now, I'll turn the call over to Joe for opening remarks. Thanks, Homer, and good morning, everyone. I'm pleased to report that today we delivered solid financial results for the first quarter, led by a continued recovery in our Refining segment. Refining margins were supported by strong product demand, coupled with very low product inventories globally. Refinery capacity rationalizations that have taken place in the last couple of years continue to contribute to the supply tightness. In addition, high natural gas prices in Europe are supporting product cracks to compensate for the higher operating cost. This, in turn, provides a structural margin advantage for U.S. refineries, particularly those located in the Gulf Coast, where natural gas costs are significantly lower than in Europe. Turning to our Low Carbon segments, the Ethanol business generated positive operating income despite a weak margin environment, and our growing Renewable Diesel business continues to generate good results with high demand for renewable diesel. We expect low-carbon fuel policies to continue to expand globally and drive demand for low-carbon fuels. With that view, we're leveraging our operational and technical expertise to steadily expand our competitive advantage. The DGD 3 renewable diesel project located next to our Port Arthur refinery is now expected to be operational in the fourth quarter of 2022. With the completion of this 470 million gallon per year plant, DGD's total annual capacity is expected to be approximately 1.2 billion gallons of renewable diesel and 50 million gallons of renewable naphtha. BlackRock and Navigator's large-scale carbon sequestration project is progressing on schedule and is expected to begin startup activities in late 2024. Valero is expected to be the anchor shipper with eight ethanol plants connected to this system, which should provide a lower carbon intensity ethanol product and result in higher product margins. We continue to evaluate other low carbon opportunities such as sustainable aviation fuel, renewable hydrogen, and additional renewable naphtha and carbon sequestration projects. In refining the Port Arthur Coker project, which is expected to increase the refinery's utilization rate and improved turnaround efficiency, is still expected to be completed in the first half of 2023. On the financial side, we remain committed to our capital allocation framework, which prioritizes a strong balance sheet and an investment-grade credit rating. We further reduced our long-term debt by $750 million in February through debt reduction and refinancing transactions, bringing our total long-term debt reduction to $2 billion in six months. We continue to honor our commitment to stockholder returns with an annual target payout ratio of 40%-50%. We restarted stock buybacks in the first quarter, which, combined with our dividend, returned $545 million to our stockholders. Looking ahead, the fundamentals that drove strong results in the first quarter, particularly in March, continue to provide a positive backdrop for the Refining segment. We expect product demand to remain healthy with light products demand near pre-pandemic levels, and the pent-up desire to travel and take vacations should drive incremental demand for transportation fuels as we head into the summer. Global product inventories remain low, particularly for diesel, and there's less refining capacity available to replenish inventories. In addition, natural gas price disparity between the U.S. and Europe should provide a structural margin advantage for U.S. refiners, especially for assets located in the Gulf Coast. In closing, we're encouraged by the refining outlook, which, coupled with our growth strategy and low-carbon fuels, should further strengthen our long-term competitive advantage and drive long-term stockholder returns. With that, Homer, I'll hand the call back to you. Thanks, Joe. For the first quarter of 2022, net income attributable to Valero stockholders was $905 million or $2.21 per share, compared to a net loss of $704 million or $1.73 per share for the first quarter of 2021. First quarter 2022 adjusted net income attributable to Valero stockholders was $944 million or $2.31 per share, compared to an adjusted net loss of $666 million or $1.64 per share for the first quarter of 2021. For reconciliations to adjusted amounts, please refer to the financial tables that accompany the earnings release. The Refining segment reported $1.45 billion of operating income for the first quarter of 2022, compared to a $592 million operating loss for the first quarter of 2021. First quarter 2022 adjusted operating income was $1.47 billion, compared to an adjusted operating loss of $506 million for the first quarter of 2021. Refining throughput volumes in the first quarter of 2022 averaged 2.8 million barrels per day, which was 390,000 barrels per day higher than the first quarter of 2021. Throughput capacity utilization was 89% in the first quarter of 2022, compared to 77% in the first quarter of 2021. Refining cash operating expenses of $4.73 per barrel in the first quarter of 2022 were $2.05 per barrel lower than the first quarter of 2021, which were impacted by excess energy costs related to Winter Storm Uri. The Renewable Diesel segment operating income was $149 million for the first quarter of 2022, compared to $203 million for the first quarter of 2021. Renewable diesel sales volumes averaged 1.7 million gallons per day in the first quarter of 2022, which was 871,000 gallons per day higher than the first quarter of 2021. The higher sales volumes were attributed to the fourth quarter 2021 startup of the Diamond Green Diesel expansion project, or DGD 2. The Ethanol segment reported $1 million of operating income for the first quarter of 2022, compared to a $56 million operating loss for the first quarter of 2021. Ethanol production volumes averaged 4 million gallons per day in the first quarter of 2022, which was 483,000 gallons per day higher than the first quarter of 2021. For the first quarter of 2022, G&A expenses were $205 million, and net interest expense was $145 million. Depreciation and amortization expense was $606 million, and the income tax expense was $252 million for the first quarter of 2022. The effective tax rate was 21%. Net cash provided by operating activities was $588 million in the first quarter of 2022. Excluding the unfavorable impact from the change in working capital of $722 million and the other joint venture members' 50% share of Diamond Green Diesel's net cash provided by operating activities. Excluding changes in DGD's working capital, adjusted net cash provided by operating activities was $1.2 billion, of which $536 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, and $307 million was for growing the business. Excluding capital investments attributable to the other joint venture members' 50% share of Diamond Green Diesel and those related to other variable interest entities. Capital investments attributable to Valero were $718 million in the first quarter of 2022. Moving to financing activities, we returned $545 million to our stockholders in the first quarter of 2022, with $401 million paid as dividends and $144 million of stock buybacks, resulting in a payout ratio of 44% of adjusted net cash provided by operating activities for the quarter. With respect to our balance sheet, we completed debt reduction and refinancing transactions in the first quarter that reduced Valero's long-term debt by $750 million. As Joe already noted, these debt reduction and refinancing transactions, combined with the debt reduction and refinancing transactions completed in the third and fourth quarters of 2021, have reduced Valero's long-term debt by $2 billion. At quarter end, total debt and finance lease obligations were $13.2 billion, and cash and cash equivalents were $2.6 billion. The debt-to-capitalization ratio, net of cash and cash equivalents, was 34%. We ended the quarter well-capitalized with $4.9 billion of available liquidity excluding cash. Turning to guidance, we still expect capital investments attributable to Valero for 2022 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts, and joint venture investments. About 60% of that amount is allocated to sustaining the business and 40% to growth. About half of the growth capital in 2022 is allocated to expanding our low-carbon businesses. For modeling our second quarter operations, we expect refining throughput volumes to fall within the following ranges. Gulf Coast at 1.64 million-1.69 million barrels per day. Mid-Continent at 395,000-415,000 barrels per day. West Coast at 225,000-245,000 barrels per day. North Atlantic at 445,000-465,000 barrels per day. We expect refining cash operating expenses in the second quarter to be approximately $5.15 per barrel, which are higher than last quarter, primarily due to higher natural gas prices. With respect to the Renewable Diesel segment, we now expect sales volumes to be approximately 750 million gallons in 2022, with the anticipated startup of DGD 3 in the fourth quarter. Operating expenses in 2022 should still be $0.45 per gallon, which includes $0.15 per gallon for non-cash costs such as depreciation and amortization. Our Ethanol segment is expected to produce 4 million gallons per day in the second quarter. Operating expenses should average $0.48 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 $140 million, and total depreciation and amortization expense should be approximately $630 million. For 2022, we expect G&A expenses, excluding corporate depreciation, to be approximately $870 million. That concludes our opening remarks. Before we open the call to questions, we again respectfully request that callers adhere to our protocol of limiting each turn in the Q&A to two questions. If you have more than two questions, please rejoin the queue as time permits. Please respect this request to ensure other callers have time to ask their questions. Thank you. We'll now be conducting a question-and-answer session. If you'd like to ask a question today, please press star one from your telephone keypad and a confirmation tone will indicate your line is in the question queue. You may press star two if you'd like to remove your question from the queue. For participants who are using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment please while we pull for questions. Thank you. Our first question comes from the line of Doug Leggate with Bank of America. Please proceed with your question. Thanks. Good morning, everyone. Thanks for taking my questions. This one might be for Gary, actually, or whoever, Joe, you want to allocate it to. I'm curious about the cadence of the margin trajectory, realized margin trajectory through the quarter. Obviously, the world kind of changed at the end of February, but what we're trying to really get a handle on is what the kind of sustainable earnings momentum might look like, given what we saw in March and obviously stronger cracks indicators again in April. That's my first question, the cadence of margins through the quarter and what it looks like in April, so far. Yeah, Doug. I would tell you in the first quarter, you know, what we saw is really pretty strong diesel demand throughout the quarter. To start first quarter, gasoline demand was a little bit soft. You know, we had a wave of COVID go through, which impacted mobility, and so the quarter started with a little softer gasoline demand. It recovered rapidly throughout the quarter. By the end of the quarter, we were seeing gasoline demand at or slightly above pre-pandemic levels. We were seeing distillate demand above pre-pandemic levels, and that demand being met with significantly less refinery capacity as we had rationalization that occurred during the pandemic. Really tight supply-demand balances and then very, very low product inventories. You know, we're looking at a situation where total light product inventory is 41 million barrels below the five-year average. You know, very, very tight and especially tight for diesel. Diesel inventories in the U.S., 27 million barrels below the five-year average. The strength in crack spread's really been led by diesel. You know, as long as inventories remain low, you would expect that to translate in a very strong refining margin environment. In fact, you know, so far in April, we've seen stronger margins than we even had in March. What we expect to see, you know, throughout the quarter is ultimately, as we get into driving season and gasoline demand continues to pick up, you're gonna have to have compression between gasoline cracks and diesel cracks. You know, a lot of the VGO that comes into the United States to fill conversion capacity was sourced from Russia. VGO is tight, and we're gonna have competition between an incremental barrel going to an FCC to make gasoline versus that barrel going to a hydrocracker to make diesel. We would expect, you know, gasoline cracks to get stronger as we move through the second quarter. Sorry, Gary, to press you on this, but maybe I'll ask it like this. How much of the earnings in the quarter from refining were in March? Doug, we can't give you know, a breakdown of earnings, but I think as Gary highlighted, obviously March was, you know, a significant contributor. Okay. Sorry for trying. My follow-up is really on Joe's prepared remarks about structural cost advantage. Joe, I think you know where we stand on this. Our view is that, you know, the U.S. has moved into almost like a regional golden age, given your structural cost opportunities and the rationalization of capacity here. I'm wondering if you could just offer us some color on how we quantify what that advantage looks like, given you've got Pembroke as a benchmark relative to the U.S. What is the delta right now, and do you see? You know, what would you hazard a guess at as a kinda normalized go-forward spread between U.S. and European gas as it relates to refining? Yeah. Doug, that's a good question. Let's let Lane take a whack at it here. As we alluded to, we have the Pembroke refinery, so we have a little bit of insight on this. Today, natural gas prices over in the U.K. are roughly about $30 per million BTU. If you sort of look at the United States, and we're currently paying somewhere between $5, $6, you know, $6.5. If you specifically use $ 30 versus $5, you need about an $8 per barrel higher heat crack to sort of break even for Pembroke to break even versus a Gulf Coast asset. Is that kinda ratable? You know, as if we normalize, the long end of the curve right now shows about a $5+ spread per MCF. That would just be kinda ratable. That'd be like $1.50 or something like that, Lane? Well, I'm not quite following. What I would say is, you know, you split the burden of saying, "Hey, I get this. What hydrocrack do I need from Pembroke versus a Gulf Coast?" I need about an $8 per barrel higher heat crack, if I'm paying $30 per million BTU for gas in the U.K. versus sort of $5 in the U.S. Right. Okay. We can take it from there. Thanks so much, guys. I appreciate the answers. All right. Thank you. Our next question is from the line of Roger Read from Wells Fargo. Please proceed with your question. Yeah. Thanks. Good morning. Probably a little bit to follow up on how we think about the second quarter here and capture and kinda contrast that with the guidance on volume. The guidance on volumes would imply some more maintenance going on this quarter. As we think about higher crude prices, lower secondary products, I'll call it kinda stratospheric diesel cracks and how we should think about the moving parts here affecting capture for y'all. Yeah. This is Lane. You know, I've sort of been talking about this as we've been on the road. I mean, it's very difficult right now to sort of compare previous capture rates versus, you know, the indexes as they are today. I mean, as you said, first and foremost, it's backwardation in the crude markets and the product markets. Secondarily, it's our secondary products like propylene and petcoke and asphalt and some of these others that don't move quite as fast as crude has moved up in price. Of course, finally, we had quite a bit of turnaround activity in the first quarter. We're giving our volume guidance in terms of how the second quarter looks. I think going forward, as long as there's this much backwardation in the markets, it'll make trying to figure out what the margin capture is going to be on a go-forward basis a little more difficult. Well, at least you got plenty of room to work with given where the crack spreads are. Exactly. Yeah. Follow-up question. End of the quarter, cash, if I remember correctly, was $2-something billion. Joe, at the last management meeting at the beginning of April, you talked about, you know, maybe being more comfortable, or you did, maybe Jason did, you know, carrying $4 billion of cash. You restarted the share repos here in Q1. Presumably, those will keep going. What's the right way to think about, you know, maybe hitting the upper end of the 40%-50% or exceeding the 50%? Do you wanna get to the $4 billion in cash first? Is there more debt to pay down? Just kinda walk us through before we... You know, at what we should think about as we think about, you know, better than expected cash flows I think most of us had coming into the year and how that may play out as we go through the rest of this year? Yeah, this is Jason. I'll take a shot at it. No, you're right. You hit our three goals, which we've talked about and we'll try to do simultaneously. We wanna build up cash, we wanna continue to pay down debt. We paid down $2 billion over the past six months. Also definitely honor our commitment to our shareholders with the buybacks. I believe with what we did in the first quarter, we were at about 44% on the share buybacks with regard to the payout ratio, and then we'll still look at it on an annual basis. You said we're at $2.6 billion on cash, so we're not even at the target. We talked about having at least $3 billion probably going forward as a minimum. Of course, it'll vary around, but that's kind of what we're looking at. We'll build some more cash. We don't have any maturities coming due. Well, we have a small one next quarter, but we'll be looking at opportunistic debt repurchases as we move forward. Yeah, we'll try to do them all simultaneously. We don't have an order where we'll get up to $4 billion of cash before we do X or anything like that. Hey, Roger. The only thing I'd add to what Jason said is, you know, we live one day at a time in this business for sure. If you look at what we're looking at in the market today, you feel pretty comfortable with the ability to go ahead and achieve all those things that we mentioned. You know, building some cash as we go forward. We thought it was opportunistic to buy back shares with the outlook that we had for the market going forward. We went ahead and did it, and we've got our commitment to honor the payout ratio target. Jason said it right. You know, we're looking at doing all three of them simultaneously. I guess what it speaks to from my perspective is kind of the general outlook that we have on the market going forward, and that we're gonna be able to achieve all of these three things, with the way things appear to be right now. No, it's great to see. Thanks. You bet. Thank you. Our next question is from the line of Phil Gresh with JPMorgan. Please proceed with your question. Yes, good morning. One follow-up to that, just as we think about the balance sheet and the fact that, you know, you effectively approached the leverage target, side of the equation. If this is a really strong environment or a peak-ish type of year, would you consider moving the leverage target lower? You know, there's a lot of question marks out there, recession risk or other things. Just curious how you're thinking about kind of managing through cycles on leverage. Yeah. This is Jason. We're pretty comfortable with our 20%-30% range. It definitely gives us range to get a lot lower than we are now. I believe we're at 34% now, so we still got a little ways to get down to our, the upper end of our target. Of course, we can do that by holding cash or paying down debts. We'll look at both of those tools. Yeah, I mean, I think we're comfortable with the range, and it gives us a lot of flexibility within it. Okay, fair enough. Then just on DGD, you know, I think you've talked about a go-forward capture rate there on the gross margin, somewhere around 100%. The capture rate was definitely better in 1Q relative to some of the headwinds in 4Q. I was just curious if there were any other headwinds there in 1Q to think about that might have been transitory and just how you're thinking about the go-forward margin outlook. Hey, Phil, this is Martin. You're right. The capture rate improved in 1Q versus 4Q. T he issue on 4Q was really feedstock costs relative to soybean oil, you know, and actually priced above soybean oil or feedstock. As we talked about before, that was largely due to the DGD 2 getting into the picture, changing feedstock flows. Every time we've done that in the past, when we've expanded, you know, we've seen feedstock prices go up. The good news in the first quarter is feedstock prices moderated relative to soybean oil. Actually, they ended the quarter below soybean oil. So that all looks good. What impacted margin capture in the first quarter was really the backwardation that Lane's talked about. That prompt crack is just not achievable. So that was the issue. It's really the backwardation in the ULSD market that impacted the capture. You know, as long as we have that backwardation, we'll lag on the capture, but you know, that won't be a permanent thing. Great. That's helpful. Thank you. Thank you. Our next question is from the line of Connor Lynagh with Morgan Stanley. Please proceed with your question. Yeah, thanks. Just high level on distillate inventories. I mean, do you attribute the supply tightness entirely to what's been happening in Europe, either on the natural gas cost side of things or the outright disruptions in Russia? Or do you feel there's some sort of bigger global issue here? Well, I think it's a number of factors, but certainly, you know, as I alluded to, distillate demand has remained fairly strong throughout the pandemic, and you're trying to supply that demand with less refining capacity as we've had rationalization, you know, occur in the industry. I think you couple with the fact that, you know, we came through a period of time where there was a lot of maintenance activity, people trying to catch up from maintenance that, you know, maybe didn't occur during the pandemic, so you saw low refinery utilization. You add to it, you know, the natural gas you know presenting challenges in Europe and less Russian distillate flowing into the market as well, and it kind of puts us in the position where we're in. I guess where I'm sort of driving at this is, you know, as we look into summer driving season and presumably further recovery in jet demand, you know, is there slack that you guys see in the global refining system or in the U.S. refining system to really significantly increase runs and refill those inventories? Or do you think we need to see some sort of demand destruction to balance the market? It's hard to see that refinery utilization can increase much. You know, we've been in this 93% utilization, and historically, although we've been able to hit 93% utilization, generally, you can't sustain it for long periods of time. I don't think there's a lot of room on refinery utilization in terms of increasing supply. I think you know, markets will have to balance more on the demand side. Got it. Just to stake one more in, do you think that's more likely on the gasoline, diesel or jet side, or how would you think about that in terms of product? Well, I think it depends. You know, in the domestic market, it looks like jet demand is recovering nicely. Certainly, you'll have an impact to international travel, you know, still with COVID restrictions in place some places and then high prices impacting, you know, some air travel as well. Gasoline and diesel seem very constructive, and a lot of it is just, you know, we have still a lot of pent-up demand. People that have been unable to travel for a couple years are ready to get out and take vacation. In our mind, we'll see very good demand continue for both gasoline and diesel. All right. Thanks very much. Thank you. Our next question is from the line of Paul Cheng with Scotiabank. Please proceed with your question. Hey, guys. Good morning. Hi, Paul. Lane, actually, you mentioned earlier about the backwardation curve. I think we all understand how the crude market backwardation curve will impact on the margin capture. I'm not sure I fully understand how the product backwardation curve will impact on the margin capture or the profitability. Can you maybe help me understand a little bit better on that? That's the first question. I'll take a shot, and maybe Gary can firm it up. You know, when you're trading in the cycle, right, if the crack is rolling up towards you and you're out there sort of selling into it, you know, you're not necessarily capturing the peak number all the time. It's just you know we've had days where the diesel crack's gone up $0.20 a gallon, $0.30. You're not gonna hit it perfectly. Of course, since we write a ratable book and we're sort of fully hedged, there again, it's a little bit more difficult for us to fully capture a steeply backward distillate market. Does that mean that if it is in a contango market, you will capture a wider benefit? Yes. For products. Anchored, really. For products. Yes. Yes. Right. Yeah. What structure's telling you is that the world is short, right? It's either short. You know, that's what structure's telling you. Yeah, your commercial arms actually do pretty well in a contango market. It's just the underlying crack's not necessarily as good as you would like. Right. In the crude market, if it is in backwardation or contango, I mean, we can pretty much do a relatively easy estimate, what's the impact from the CMA. Is there any rule of thumb that is the backwardation curve in the product market? Is it a dollar to a dollar impact on your margin capture or not really? It's a fraction, and if it is a fraction, is there any rule of thumb that what percentage that may be? No, it's not as transparent, you know, because so many of our barrels are essentially Brent-based, and so you have to look at the overall sort of dated market and sort of how we build up to, you know, to get from sort of the physical market to an ICE relationship. It's a little not as transparent, and it's not as easy to see. You can obviously look at what something similar or the complex roll of that to see, is it really structurally backward or not, and then just we'll have to sort of come up with how you guys wanna model that. I see. Okay. The second question is on the Russian invasion and correspondingly, I mean, there's a lot of moving parts. I mean, the European gas price is high. The feedstock availability on VGO, all those have become reduced. We also seen, of course, that the product export from Russia in gas oil to Europe has been dramatically reduced. So how has that affected your operation in Europe, Pembroke, and also maybe your Gulf Coast refining operation had been changed or even more adapted to this new. I mean, is the product yield had been any meaningful differences because of the market condition or the current situation that we see? Because you no longer can buy the M100, when you purchase the other similar type from Latin America or Middle East, how that impact on your product yield or your operation? Again, I'll say, hey, Paul, I'll take a shot, and Gary can correct anything that I say that's not exactly correct. So starting with the first item, you know, VGO definitely, you know, when you look at how the Russian balances work, VGO and is essentially they're the final sort of exporter of a major physical supply of VGO to the market. We'll just have to see how that plays out. You know, today it's not as, you know, because the diesel crack is so high versus gasoline, you're still in max diesel mode. I mean, Gary kind of touched upon it earlier. I think our anticipation is as you get more into the driving season, as you sort of enter into a period where maybe it's a little more difficult to fill up these conversion units because the availability of gas oil, you'll have to start bidding molecules away from the distillate market. As long as the distillate market remains tight, it just gonna keep pulling up both cracks. We'll just have to see how that works out. With respect to our M100 supply, you know, we're out buying sort of replacement barrels in the areas that you alluded to, which is largely the Middle East and South America. We'd have been buying those in the base if they were the most economic, but we've certainly been able to certainly shore up our supply situation with those, with barrels from those areas. Does that mean that those barrels, when you run them through your refinery, yield differently or do you need to change the way you operate? Well, we're blending differently, right? What it means is 'cause yeah, there's all these feedstocks, you know, even M100 has variability from different areas and all these intermediates have different variability and qualities, and we're always, I mean, that's part of the sausage making. We figure out how to blend to something that we think is the most economic for us to run. All right. Thank you. Thank you. Our next question is from the line of Theresa Chen with Barclays. Please proceed with your questions. Morning. I have a follow-up question, Lane, on some of the comments around demand and gasoline. Clearly, there is a lot of concern on demand currently, and, you know, much of that is driven by factors abroad that's outside of your control. I was hoping if you could offer your thoughts on how elastic do you think the demand curve is currently. You're already in like a tight product supply situation due to rationalization alone. Now the Russian VGO is coming out of the market, and to your point, the, you know, cat crackers need to incentivize that barrel of VGO from the hydrocrackers, which means that, you know. Gasoline prices need to go higher, and if crude doesn't go lower, prices need to go higher. How does all that shake out as far as the demand picture goes for you? Hey, Theresa, this is Gary. It's difficult to tell, you know, at what price point do you see demand destruction on gasoline. I think there's a number of factors that come into play there. Certainly you would expect elevated price to have an impact on demand. However, we've seen wage inflation, you know, that kind of offsets that and allows people to tolerate a higher price point. With personal savings up, you know, it again, people, pent-up demand. They're going to wanna travel, and they have money in the bank, so it probably offsets some of that to some degree. Then throughout the world, not so much in the U.S., but many other countries, we've seen the government step in, you know, in the form of tax subsidies, ways to kind of offset those increases and keep the street price down. I think a lot of those factors will kind of offset some of the things that we typically see and that would cause the demand destruction to occur on gasoline. Got it. Just on the export side, what are you seeing in terms of the competitive dynamics in the export markets? Clearly you're well-positioned given your geographical concentration, the Gulf Coast. How do you see the market evolving for Gulf Coast refiners as domestic supply has rationalized to some extent and Latin America continues to grow over time? There seems to be a structural bid for diesel into Europe, given their shortage. How do you see these factors playing out? Yeah. I think as long as you know, when you look at the advantages the U.S. Gulf Coast refining system has, we've talked a lot about natural gas, but you know, also feedstock cost advantages running domestic crude or Canadian or Mexican crude. It puts us in a very strong position to be able to compete you know, globally into the export markets. I think you'll see that continue. PADD 3 is long diesel, and so you'll see that length move into the export markets you know, Latin American and Europe throughout the summer. Thank you. Thank you. Our next question is coming from the line of Paul Sankey with Sankey Research. Please proceed with your questions. Morning, all. Excuse me. Morning, Paul. These are pretty much follow-up questions. Sorry. Pretty much follow-up questions given everything you said. Just specifically, do you have a number for how much Russian crude and I guess VGOs, intermediates and then Russian products that is now out of the market further to what you're saying? It seems that you're saying that trade remains strong despite the strong dollar and the high prices. The follow-up would be on the working capital movement, how is the environment affecting your trading and markets in general? Because, you know, we're all aware that there's been a falling off of open interest. I assume that the working capital commitment will stay high as long as prices stay high. If there's anything you can add on what it means for markets, that would be very helpful. Thank you. Thanks, Paul. Yeah. I guess, you know, to start with, we have seen, you know, it looks like diesel coming out of Russia and M100 coming out of Russia have fallen off. Thus far, we haven't really seen the fall off in crude exports from Russia. So far, you know, it looks like it's been more of a rebalancing the trade flows rather than a reduction in exports. You can see India taking more Russian barrels, China taking more Russian barrels, some Latin grades and West African grades flowing into Europe. Then in here in the United States, you're seeing more Brazilian and Colombian grades that were going to India and China starting to flow in the U.S. I don't know that we've seen so much on the crude export side, but certainly on the M100, the resids, and the distillate, you're starting to see export fall off. Working capital discussion. You want me to take it? Yeah. Hey, hey, Paul, this is Lane. I'll take a shot at it if this is what you're trying to get at. One of the things that you've seen in the working capital ideas is that, you know, with this thinly traded derivatives market, the paper markets, it's sorta trying. What you're seeing is the trading companies and the operating companies are sorta trying to sort out who's gonna have the physical length that's going, you know, either across the Atlantic or to South America, depending on trade flow. It's because there's just this volatility that's in the derivative market. Everybody's trying to. That's still being sorted out, I guess is the best way I would say that. If I could sneak in a quick follow-up. Your light sweet throughputs, I assume they look like they're an all-time record high at the moment, right? Yeah. Yes, they are. Thanks. Thanks a lot, guys. Take care, Paul. Our next question is from the line of Manav Gupta with Credit Suisse. Please proceed with your questions. Good morning. I'm going to try for one. I'm not sure if I'll get the answer, but it's my job to try. If we go back a decade, 2015 was the best year in earnings. Let me know, Homer, if I'm wrong, but I think you made over $9 in EPS in 2015. That's right. When we move forward today, first quarter, $2.31. The next two quarters, most of us who really believe in Valero believe there's like a $8 or $9 EPS number hidden in there combined for the two quarters. Then the last quarter is generally your strongest, so that's another $2.50. We put all two things together, this high that will be achieved in 2022 will be materially higher than the 2015 earnings number. If I'm thinking about it right, can you comment on about how the management is thinking about the record high earnings in over a decade? Well, Manav, I'll just say that I said it earlier, we live one day at a time in this business. We certainly like your thinking and your mindset. Frankly, I think everything you've heard from the team this morning is that things look constructive on all segments of our business right now. You know, we're optimistic, but we don't count our chickens before they're hatched. We'll continue to do what we do, and that is come in every day and try to operate safely and reliably in an environmentally responsible way and to optimize to the extent we can. If we just keep doing that day after day after day, I think we're gonna find ourselves in a really good place. Perfect. Thank you, Joe. One quick follow-up here is, every quarter we see a very positive trend. DGD moves ahead by one quarter. If you spot that trend, the logical conclusion here is that on your 2Q call, you would basically say that we have achieved mechanical completion and we are starting the RD project. I'm just spotting a trend here, sir. Let me know what you think about that. Well, Martin, do you wanna take that? Well, you know, obviously we've got a long track record here, and DGD 3 is pretty much a duplicate of 2, just a little bit bigger, so that helped a lot. Same construction team, same contractors, perfect weather. We gotta get through hurricane season still, Manav. Yeah, everything looks great over at Port Arthur. You know, Manav, the one thing that I would say, too, and you know, we don't talk about it a lot, but our team's ability to execute major projects like this. I mean, Lane has really worked very hard on this over the years. Our team's ability to execute significant projects and the partners that we've got in helping execute those projects are extraordinary. It leads to the kind of results that you said look like a trend. It's a trend that we like and we'll try to maintain. Thank you so much for taking my questions. Good. Thank you. Our next questions come from the line of Neil Mehta with Goldman Sachs. Please proceed with your questions. Good morning, team. First question is on U.S. Gulf Coast. We've seen a lot of capacity retirement down there, whether it was LyondellBasell here recently, obviously Shell Convent and then the Alliance refining assets as well, something like 7% of PADD 3 capacity is now out of the market as of next year. How do you guys see that impacting the structural outlook of the U.S. Gulf Coast? What changes, if anything? Is that market just so deep and interconnected that retirement doesn't have a meaningful impact on the way you think about product basis? I would say, you know, overall, Neil, you know, PADD 3 is an export market on both gasoline and diesel. I wouldn't expect to see a you know material impact from shutdown capacity in terms of the product market. We do see. You know, it gives us some advantages on the crude stock. You know, we've certainly seen that as refineries come down, especially those refineries in the Eastern Gulf. It gives us access to some U.S. grades that maybe we didn't have access to before. The follow-up's also on the product markets and just love your perspective on what's happening in China right now. Certainly looks like 2 million barrels a day of product demand could be down. But at the same time, China's not exporting product into the market in as meaningful of a way. Singapore margins continue to be very strong. But as you look at the balances here, how much of a concern is China. Or do you think that, again, that impact could be contained because of inventory levels but also product quotas? Well, Neil, I think the answer is kind of in what you just stated. You know, thus far, although certainly the COVID restrictions have impacted demand in China, they're not exporting a lot of product. You know, I think if you had weak demand in China and high refinery utilization resulting in very high exports, that would be concerning, but we're not seeing that in the market today. Great. Thank you so much. Thank you. Our next question is from the line of Sam Margolin with Wolfe Research. Please proceed with your question. Morning, everybody. How you doing? Hey, Sam. Question on capital allocation. A significant amount of your growth CapEx is low carbon projects, but those projects come early, but they're, you know, they're gated by a very regimented process. Just because a project comes early doesn't mean the next one is gonna start early. You might develop kind of a lumpy pattern of growth CapEx. I'm just wondering if that has an effect on your other elements of your capital allocation, the other components, you know, return of capital or if you harvest that cash. You know, what happens when you have maybe a lean year in growth CapEx just 'cause of the cadence of your gated process? You're saying if we have a year in a lean year for growth CapEx, you're talking about a year where we spend less on growth CapEx? Yeah, because, you know, if you finish DGD 3 early, it doesn't mean you're gonna start the next one early as well, right? Because you're still going through the process for it. You might have a— No. A gap in spending given the magnitude of your growth CapEx in that portion. Gotcha. Okay. Hey, Sam. It's Lane. I'll take a stab at this. It's an interesting idea, and I do think you'll see our strategic capital as well as our sustaining capital. We've always said that we guide to $2 billion-$2.5 billion on the overall capital budget, nominally $1.5 billion. These are all averages. By definition, our strategic capital is going to be $500 million - $1 billion nominally, at least on an average. They're, you know, it'll be lumpier because they are sizable projects and, you know, so I think directionally that's true potentially from a year to year. I don't think you'll see us go from zero to $2 billion or something like that, but you'll certainly see $ 500 million of variability with respect to our strategic capital spend here in the near term. You want to comment? I mean, I think Yeah, I mean, it just fits into the mix, right, with excess cash. I don't think we'd change our model based on the variability around CapEx. Right. Yeah, I mean, and Sam, I think it was mentioned earlier, Jason mentioned earlier, we haven't yet achieved the three targets that we're shooting for as far as the, you know, the use of cash, whether it be the debt ratio, buybacks and so on. So we've got a little bit of work to do around that yet, but, you know, building a little bit of cash never is very troubling to us. Got it. Yeah, this is sort of a follow-up, and it is kind of a hypothetical around DGD 4. You know, we're talking a lot on this call about clear evidence of a distillate shortage that's driven by some structural factors. Now you have a consideration for renewable diesel supply that goes beyond just policy and the regulatory framework because we just need more diesel, period, renewable or otherwise. I'm wondering if that's a consideration that's now going into, you know, the commercial analysis behind incremental RD projects. Yeah, Sam, this is Martin. I'm not sure we've looked at it that way. Overall, I would just tell you the demand for renewable diesel, when we look at the balances, you know, we just think that, you know, demand's gonna outstrip supply. We've got a lot of speculation in the market that a lot of demand's coming on. We'll see how much of that happens. We feel good about supply. You know, the European demand for renewable diesel. We feel good about demand. Demand for renewable diesel in Europe is gonna rebound a lot with, you know, no more COVID lockdowns. It hasn't been the case. You know, we've got RED II out through 2030. You know, what they're talking about in the Fit for 55 program, what they're gonna do for the RED III is pretty aggressive. California, Oregon, Washington, the CFS in Canada. We just see a lot of demand out there. Thanks so much. Thank you. Our next question is from the line of Ryan Todd with Piper Sandler. Please proceed with your questions. Thanks. Maybe, just a couple of, high-level strategic ones. I mean, clearly, we've talked a lot here about how attractive the setup is, for the rest of this year, with markets looking tight and margins strong. Outside of a potential recession, what risks do you worry about that could materially change the outlook, Joe? Well, I mean, if we ended up in a huge recession, I think those are the kind of things that certainly are out of our control, but it would likely affect demand. You know, another bout of COVID that would shut down people's mobility would impact us. You know, outside non-controllable factors like that, right now, I mean, I think we're generally pretty bullish about the way things look. You had anything, you guys? No, I mean, Joe's comments are right. I mean, we didn't really see. I think people's tolerance of COVID is a little different than the last time, so I don't know that we'll see the demand destruction. COVID sort of, you know, some form of a variant of COVID comes running through for whatever reason. Yeah, recession has to be our biggest risk at this point. Yeah. All right. Maybe it feels like it's been a long time since you've been in the market for the purchase of a refining asset. I wonder if you have any comment on developments in the refining asset market. You know, particularly, we have news of a failed sale process for the LyondellBasell refinery. Is this just a gap in bid-ask range that you're seeing? Or do you see it as increasingly difficult for large assets to transact going forward? If that's the case, what does it mean for medium to longer term supply-demand balances globally? You know, are we more likely to see more closures versus sales going forward and keeping markets tighter than they might be otherwise? Well, you know, I mean, probably the safest way for us to talk about that is from our own perspective. You know, there haven't been assets in the market that were compelling for us to buy. That doesn't mean there aren't attractive assets that we'd be interested in. With our experience in acquisitions of assets, you go through the periods of being super enthusiastic about it, and then you get deal heat, you wanna go do it, and then you buy it, and then you get in there, and you start looking at it, and Lane tells me it's gonna cost $3 billion to get it up to a Valero standard. I look at it and go, "Hmm, maybe that wasn't exactly the best thing." You know, for us, truly, it is simply a matter of asset allocation, Ryan. I mean, where do we want to spend our money? Right now, it's not that these assets aren't good or aren't attractive, it's just we feel we've got higher return, better uses for the capital that we wanna employ than buying a refinery that's on the market at this point in time. I'll stop there. Anything you would add, any of you guys? This is Lane. I do think what it does mean is that you potentially, you know, versus transacting a large refinery or even certainly smaller ones, the likelihood that they may shut down is probably higher, at least directionally versus the past. That's what we're seeing. Yeah. Great. Thank you. You bet. Thank you. Our final question this day comes from the line of Jason Gabelman with Cowen. Please proceed with your questions. Hey, morning. Thanks for taking my questions. Sure. I had two. The first will be a follow-up on the refining margin outlook. You know, we're getting a lot of inbounds asking how long this strong margin environment can last, and you've obviously been very bullish on the call. Maybe a couple of near-term things we've seen that I was hoping to get your comment on. One is the kind of somewhat rapidly tightening spread between European gas prices and U.S. natural gas prices. Do you think that impacts the margin environment at all? Could you see Europe increase utilization on some of its secondary distillate processing units? The other one is the IEA suggesting that there could be a 5 million barrel per day increase in refining throughput from now through summer as refining capacity that's in maintenance comes back, which is kind of double the typical rate I think you would see over that period. Just wondering if that factors into your bullish outlook on refining and if you expect either of those to weigh on the market at all. I have a quick follow-up on capital allocation. Thanks. Hey, so this is Lane. I'll start off. Your first note of seeing a rapidly closing of the arbitrage between U.S. gas and European gas has a barrier there because these export facilities are full. To the extent that that'll happen, you need to get some more export. You gotta get to where you have open capacity on these liquid natural gas facilities to fully get there. You kinda need to go out there and look at what pace and when the next ones are all being built. In terms of refining, worldwide refining capacity and how we think about it, we keep saying all along, we don't spend a lot of time trying to figure out what the rest of the world's doing on this. You guys have the same data that we have. You know, we focus on doing what we do well, and that's what we focus on. With that said, I mean, there's gonna be refinery closures based on the rest of the call that we've talked about versus certain parts of the world are going to build refineries. We certainly, at least, we don't worry so much about how these balances are gonna necessarily affect us. Got it. Just a quick follow-up on capital allocation moving forward. It seems like you have this coker project, and then after that, no major refining projects, but you've been discussing some other low-carbon energy investments. Is the intention for over time, more of the growth capital or nearly all of it to kind of gravitate towards that low-carbon bucket? I wouldn't say that by any stretch. I mean, you know, You know our MO, right? We talk about stuff after we fully developed it, understand how much it's gonna cost, and have a good feel for the market. I think it's fair for you to assume that, you know, Lane and the team are looking at all the projects and we evaluate them against each other. I wouldn't wanna tell you that there'll never be another refining project, but I can tell you a lot of the stuff that's in the hopper that he and the team are looking at tend to be more towards the cleaner fuel side of things. You know, honestly, I would never say never on another refining project. Great. Thanks for the time. Great. Thanks for all. Thank you, everyone. We appreciate you guys dialing in.