Greetings. Welcome to Valero Energy Corporation's First Quarter 2022 Earnings Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. 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 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 expertise 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 costs. 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. And with that view, we're leveraging our operational and technical expertise that steadily expands 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 Navigators large-scale carbon sequestration project is progressing on schedule and is expected to begin start-up activities in late 2024. Valero is expected to be the anchor shipper with 8 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. And in refining, the Port Arthur Coker project, which is expected to increase the refinery's utilization rate and improve 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 6 months. And we continue to honor our commitment to stockholder returns with an annual target payout ratio of 40% to 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. So 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. The adjusted net income for the same period was $944 million or $2.31 per share, compared to an adjusted net loss of $666 million or $1.64 per share in the first quarter of 2021. For details regarding adjusted amounts, please refer to the financial tables accompanying the earnings release. The refining segment reported $1.45 billion in operating income for the first quarter of 2022, compared to an operating loss of $592 million in the first quarter of 2021. The adjusted operating income was $1.47 billion compared to an adjusted operating loss of $506 million in the prior year. Refining throughput volumes averaged 2.8 million barrels per day in the first quarter of 2022, which is 390,000 barrels per day higher than in the first quarter of 2021. The throughput capacity utilization was 89% in the first quarter of 2022, up from 77% in the same quarter a year earlier. Refining cash operating expenses were $4.73 per barrel in the first quarter of 2022, down by $2.05 per barrel from the first quarter of 2021, which had been impacted by excessive energy costs from winter storm Uri. The renewable diesel segment recorded operating income of $149 million for the first quarter of 2022, compared to $203 million for the same period in 2021. Renewable diesel sales volumes averaged 1.7 million gallons per day in the first quarter of 2022, an increase of 871,000 gallons per day from the first quarter of 2021, driven by the startup of the Diamond Green Diesel expansion project in the fourth quarter of 2021. The ethanol segment reported operating income of $1 million for the first quarter of 2022, reversed from a $56 million operating loss in the same quarter of the previous year. Ethanol production volumes averaged 4 million gallons per day in the first quarter of 2022, an increase of 483,000 gallons per day from the corresponding period in 2021. General and administrative expenses for the first quarter of 2022 were $205 million, and net interest expense was $145 million. Depreciation and amortization expense reached $606 million, and income tax expense was $252 million for the first quarter of 2022, resulting in an effective tax rate of 21%. Net cash provided by operating activities amounted to $588 million for the first quarter of 2022. Excluding the negative impact of a $722 million change in working capital and the other joint venture members' 50% share of Diamond Green Diesel's cash provided by operating activities without changes in working capital, the adjusted net cash provided by operating activities was $1.2 billion. In terms of investing activities, we made $843 million in capital investments in the first quarter of 2022, with $536 million dedicated to sustaining the business, including turnaround costs, catalysts, and regulatory compliance, while $307 million was aimed at business growth. Excluding capital investments for other joint venture members and related entities, the investments attributable to Valero were $718 million in the first quarter of 2022. Regarding financing activities, we returned $545 million to our stockholders in the first quarter of 2022, consisting of $401 million in dividends and $144 million in stock buybacks, leading to a payout ratio of 44% of adjusted net cash provided by operating activities for the quarter. On the balance sheet front, we executed debt reduction and refinancing transactions in the first quarter that lowered Valero's long-term debt by $750 million. As noted by Joe, these transactions, along with previous reductions and refinancings completed in the third and fourth quarters of 2021, have decreased Valero's long-term debt by $2 billion. At the end of the quarter, total debt and finance lease obligations stood at $13.2 billion, with cash and cash equivalents at $2.6 billion. The debt-to-capitalization ratio, after accounting for cash and cash equivalents, was 34%. We ended the quarter in a solid capital position with $4.9 billion in available liquidity, excluding cash. Looking ahead, we are projecting capital investments attributable to Valero in 2022 to be around $2 billion, which will cover expenditures for turnarounds, catalysts, and joint ventures. Approximately 60% of this amount is intended for sustaining the business, while 40% is for growth, with about half of the growth capital allocated to expanding our low-carbon initiatives. For modeling our second quarter operations, we anticipate refining throughput volumes to range as follows: Gulf Coast at 1.64 million to 1.69 million barrels per day; Mid-Continent at 395,000 to 415,000 barrels per day; West Coast at 225,000 to 245,000 barrels per day; and North Atlantic at 445,000 to 465,000 barrels per day. We project refining cash operating expenses for the second quarter to be approximately $5.15 per barrel, which is higher than last quarter, mainly due to increased natural gas prices. For the renewable diesel segment, we now estimate sales volumes will reach about 750 million gallons in 2022, with the anticipated startup of DGD 3 in the fourth quarter. Operating expenses for renewable diesel in 2022 should be $0.45 per gallon, which includes $0.15 for noncash expenses such as depreciation and amortization. Our ethanol segment is expected to produce 4 million gallons per day in the second quarter, with operating expenses averaging $0.48 per gallon, which also includes $0.05 per gallon for noncash costs like depreciation and amortization. For the second quarter, we anticipate net interest expense to be around $140 million and total depreciation and amortization expense to amount to approximately $630 million. For the entire year of 2022, we expect general and administrative expenses, excluding corporate depreciation, to be about $870 million. That concludes our opening remarks.

Our first question comes from Doug Leggate with Bank of America. Please proceed with your question.

This one might be for Gary, actually or whoever, Joe, you want to allocate it to. But 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 crack indicators again in April. So that's my first question, the cadence of margins through the quarter and what it looks like in April so far.

Yes, Doug. So I would tell you, in the first quarter, we saw is really pretty strong distillate demand throughout the quarter. But to start first quarter, gasoline demand was a little bit soft. We had a wave of COVID go through, which impacted mobility. And so the quarter started with a little softer gasoline demand but it recovered rapidly throughout the quarter. So by the end of the quarter, we were seeing gasoline demand at or slightly above pre-pandemic levels. We are 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. So, really tight supply demand balance and then very, very low product inventories. So we're looking at a situation where total light product inventory is 41 million barrels below the 5-year average. So very, very tight, especially tight for diesel. Diesel inventories in the U.S. are 27 million barrels below the 5-year average. So the strength in crack spreads really been led by diesel. As long as inventories remain low, you would expect that to translate into a very strong refining margin environment. And in fact, so far in April, we've seen stronger margins than we even had in March. What we expect to see throughout the quarter is ultimately, as we get into driving season and gasoline demand continues to pick up, you're going to have to have compression between gasoline cracks and diesel cracks. A lot of the VGO that comes into the United States to fill conversion capacity is sourced from Russia. So VGO is tight. And we're going to have competition between an incremental barrel going to an FCC to make gasoline versus that barrel going to a hydrocracker to make diesel. So we would expect 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 a breakdown of earnings. But I think as Gary highlighted, obviously, March was a significant contributor.

Okay. My follow-up is focused on Joe's prepared remarks regarding structural cost advantages. Joe, we believe the U.S. has entered a sort of regional golden age due to its structural cost opportunities and capacity rationalization. Can you provide insights on how we can quantify this advantage, especially with Pembroke as a benchmark for comparison with the U.S.? What is the current difference, and what would you estimate as the normalized forward spread between U.S. and European gas concerning refining?

Yes, Doug, that's a good question. Let's let Lane take a whack at it here.

Yes. As you mentioned, we have the Pembroke refinery, which gives us some insight into this situation. Currently, natural gas prices in the U.K. are approximately $30 per million BTU, while in the United States, we are seeing prices between $5 and $6. When you compare $30 to $5, you would require about an $8 per barrel increase in the heat crack to achieve breakeven at Pembroke compared to the Gulf Coast asset.

If we normalize the long end of the curve right now, it indicates a spread of over $5 per Mcf. So it would be roughly around $1.5 in that regard.

Well, I'm not quite following what I would say is you split the burden of saying, "Hey, I get this - what heat crack do I need from Pembroke versus the 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.

Our next question is from the line of Roger Read from Wells Fargo. Please proceed with your question.

Probably a little bit to follow up on how we think about the second quarter here and capture and kind of contrast that with the guidance on volume. So the guidance on volumes would imply some more maintenance going on this quarter. So as we think about higher crude prices, lower secondary box I'll call it, kind of stratospheric diesel cracks and how we should think about the moving parts here affecting capture for you all.

Yes, this is Lane. I have been discussing this while traveling. It's currently challenging to compare prior capture rates with the current index. As you noted, the crude and product markets are experiencing backwardation. Additionally, our secondary products like propylene, pet coke, and asphalt do not react as quickly to rising crude prices. Furthermore, we had considerable turnaround activity in the first quarter. While we are providing our volume guidance for the second quarter, I believe it will be increasingly difficult to determine the margin capture moving forward as long as there is significant backwardation in the market.

Well, at least you got plenty of room to work with given where the crack spreads are. A follow-up question. So 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 maybe being more comfortable or you did, maybe, Jason, to 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 maybe hitting the upper end of the 40% to 50% or exceeding the $50, do you want to get to the 4 billion in cash first is it more to debt to pay down? Just kind of walk us through before what we should think about as we think about 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.

This is Jason. I appreciate the question. You're correct that we've achieved our three goals, which we aim to accomplish simultaneously. Our objectives include building cash, reducing debt, and honoring our commitment to our shareholders through buybacks. Over the past six months, we've successfully paid down $2 billion in debt. In the first quarter, we executed share buybacks that amounted to about 44% of our payout ratio, and we'll continue to evaluate this on an annual basis. You mentioned that we currently hold $2.6 billion in cash. We're targeting at least $3 billion as a minimum going forward, though this may fluctuate. We'll focus on increasing our cash reserves. While we have a minor debt maturity coming up next quarter, we will look for opportunities to repurchase shares as we advance. We do not have a specific sequence in mind for achieving $4 billion in cash before undertaking other actions. We'll pursue all these initiatives together.

Roger, the only thing I'd add to what Jason said is we live one day at a time in this business for sure. But 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, 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. And so we went ahead and did it, and we've got our commitment to honor the payout ratio target. And so Jason said it right. We're looking at doing all three of them simultaneously. But 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 going to be able to achieve all of these three things with the way things appear to be right now.

Our next question is from the line of Phil Gresh with JPMorgan. Please proceed with your question.

One follow-up to that, just as we think about the balance sheet and the fact that you effectively approach the leverage target side of the equation. If this is a really strong environment or a peakish type of year, would you consider moving the leverage target lower? A lot of question marks out there, recession risk or other things. Just curious how you're thinking about kind of managing through cycles from leverage.

Yes, this is Jason. We're comfortable with our 20% to 30% range. This allows us the possibility to decrease significantly from our current position of 34%. There is some distance to reach the upper end of our target, and we can achieve this by either retaining cash or reducing debt. We are considering both options. Overall, we feel confident about the range as it provides us with ample flexibility.

And then just on DGD 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?

Phil, this is Martin. You're right, the capture rate improved in the first quarter compared to the fourth quarter. In the fourth quarter, the main issue was feedstock costs in relation to soybean oil, which were actually priced above soybean oil. This was largely due to DGD 2 getting into the pit and changing feedstock flows. In the past, whenever we've expanded, we've seen feedstock prices rise. The positive news in the first quarter is that feedstock prices moderated in relation to soybean oil and actually ended the quarter below soybean oil. So that looks good. What impacted margin capture in the first quarter was primarily the backwardation that Lane mentioned; the prompt crack is just not achievable. This backwardation in the ULSD market affected the capture rate. As long as we have that backwardation, we will lag in the capture, but that is not expected to be a permanent situation.

Our next question is from the line of Connor Lynagh with Morgan Stanley. Please proceed with your question.

Just high level on distillate and 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, 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 occur in the industry. I think you couple with the fact that we came through a period of time where there was a lot of maintenance activity. People trying to catch up from maintenance that maybe didn't occur during the pandemic. So you saw low refinery utilization. And then you add to it the natural gas 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.

As we look ahead to the summer driving season and the anticipated recovery in jet demand, do you see any capacity within the global refining system, or specifically the U.S. refining system, to significantly increase production and replenish inventories? Or do you believe that some form of demand destruction is necessary to achieve market balance?

It's hard to see that refinery utilization can increase much. 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. So I don't think there's a lot of room on refinery utilization in terms of increasing supply. I think the markets will have to balance more on the demand side.

And just to sneak one more. And 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?

It depends on the market. In the domestic sector, jet demand appears to be recovering well. However, international travel is still affected by COVID restrictions in some areas and high prices are impacting air travel. Gasoline and diesel demand looks healthy, with a significant amount of pent-up demand. Many individuals who have not been able to travel in the past couple of years are eager to go on vacation. Therefore, we anticipate strong demand for both gasoline and diesel to continue.

Our next question is from the line of Paul Cheng with Scotiabank. Please proceed with your question.

Actually, you mentioned earlier about the backwardation curve. I think we all understand how the crew market deputation curve will impact the margin capture. I'm not sure I fully understand how the port up 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 give it a try and maybe Gary can provide more clarity. When you're active in the market and the crack spread is increasing, selling into that doesn’t always allow you to take advantage of the highest price. There have been instances where the diesel crack increased by $0.20 or $0.30 a gallon, so it’s not always possible to hit the peak perfectly. Additionally, since we have established a steady book and are fully hedged, it becomes a bit more challenging for us to fully benefit from a sharply backwardated distillate market.

Does that mean that your vehicles in a commercial market your category will benefit?

Yes, for products. What structure is indicating is that there is a shortage. Your commercial alarms perform reasonably well in a contango market, but the underlying crack may not be as favorable as you would hope.

In the crude market, we can estimate the impact from the CMA. Is there a general guideline for the variation curve in the product market? Is it a one-to-one impact on your margin capture, or is it more of a fractional impact? If it is a fraction, what percentage might that be?

No, it's not as transparent because many of our barrels are essentially based on Brent. We need to consider the overall dated market and how we transition from the physical market to an ICE relationship. It's not as clear-cut, and it's more challenging to analyze, but you can look at something similar to understand the complex role of that. You can determine whether it's truly backward or not and then decide how you want to model that.

The second question is on the Russian innovation and correspondingly I mean there's a lot of moving parts. I mean, the European gas price is high, the feedstock availability on video or those have become reduced. And we've also seen, of course, that the product export from Russia in gas oil to Europe has been dramatically reduced. So how that your operation in Europe, Pembroke and also maybe that your Gulf Coast refining operation had been changed or more and adapt 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. And also that 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 on your operation?

Again, I'll go ahead and share my thoughts and Gary can correct me if I'm not entirely accurate. Starting with VGO, it's clear that the Russian balances are influenced by VGO, which is now the primary exporter of significant physical supplies of VGO to the market. We'll need to monitor how this situation develops. Currently, the high diesel crack versus gasoline is keeping us focused on diesel. As Gary mentioned earlier, we expect that as we enter the driving season and it becomes more challenging to supply these conversion units due to gas availability, we may have to begin sourcing molecules from the distillate market. If the distillate market remains tight, it will continue to drive up both cracks. We'll see how that unfolds. Regarding our M100 supply, we are actively purchasing replacement barrels primarily from the Middle East and South America. We would have been sourcing these barrels in any case if they were the most economical option, and we've managed to enhance our supply with barrels from these regions.

Our next question is from the line of Theresa Chen with Barclays. Please proceed with your question.

I have a follow-up question, Lane, on some of the comments around demand and gasoline. Clearly, there's a lot of concern on demand currently and much of that is driven by factors abroad that's outside of your control. But I was hoping if you could offer your thoughts on how elastic do you think that demand curve is currently. And you're already in like a tight product supply situation due to rationalization alone. And now the Russian VGO is coming out of the market. And to your point, the gas crackers, you just incentivize that barrel of VGO from the hydrocracker, which means that gasoline cracks need to go higher and if crude doesn't go lower prices used to go higher. So how does all that shake out as far as the demand picture goes for you?

Theresa, this is Gary. So it's difficult to tell 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 that kind of offsets that and allows people to tolerate a higher price point with personal savings up again, people pent-up demand. They're going to want to travel and they have money in the bank. So it probably offsets some of that to some degree. And then throughout the world, not so much in the U.S., but in many other countries, we've seen the government step in, in the form of tax subsidies ways to kind of offset those increases and keep the street price down. So 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.

And 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 in the Gulf Coast. How do you see the market evolve or Gulf Coast refiners as domestic supply has rationalized to some extent, and LatAm 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?

Yes. When considering the advantages of the U.S. Gulf Coast refining system, we have discussed natural gas, but there are also cost benefits from using domestic crude or Canadian and Mexican crude. This places us in a strong position to compete globally in export markets, and I believe this trend will continue. PADD 3 has an oversupply of diesel, and we can expect this surplus to move into export markets in Latin America and Europe throughout the summer.

Our next question is coming from the line of Paul Sankey with Sankey Research. Please proceed with your question.

These are have much follow-up questions. 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 into media and then Russian products that is now out of the market further to what you're saying. And it seems that you're saying that trade remains strong despite the strong dollar and the high prices. And the follow-up would be on the working capital movement, how is the environment affecting your trading and markets in general because 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. But if there's anything you can add on what it means for markets, that would be very helpful.

Yes. To begin with, we've observed a decline in diesel and M100 exports from Russia. However, crude exports from Russia remain stable so far. It appears that trade flows are being adjusted rather than experiencing a decrease in overall exports. India and China are increasing their intake of Russian barrels, while some Latin American and West African grades are being directed to Europe. In the United States, we are also seeing more Brazilian and Colombian grades being shipped to India and China. Although we haven't noted a significant change on the crude export side, there is definitely a decline in exports related to M100, residuals, and distillates.

Paul, this is Lane. I'll give it a try. What you're getting at is that in the area of working capital, the small traded derivatives market is involved. The trading companies and operating companies are trying to determine who will have the physical supply that needs to go either across the Atlantic or to South America based on trade flow. This is due to the volatility present in the derivative market. So, I would say that this situation is still being worked out.

If I just sneak in a quick follow-up. Your light sweet crude, they look like they are an all-time record high at the moment, right?

Yes, they are.

Our next question is from the line of Manav Gupta with Credit Suisse. Please proceed with your question.

I'm going to try for one. I'm not sure if I get the answer, but it's my job to try. So if we go back a decade, 2015 was the best year in earnings. And let me know how if I'm wrong, but I think you made over $9 in EPS in '15. So 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 an $8 or $9 EPS number hidden there combined for the 2 quarters. And then the last quarter is generally our strongest. So that's another 2.50. We put all three 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 about how the management is thinking about a record high earnings in over a decade.

So Manav, I mentioned earlier that we take each day as it comes. We appreciate your perspective and mindset. From what the team shared this morning, it's clear that all segments of our business are currently looking positive. While we’re optimistic, we remain cautious and don't want to count our successes before they happen. We will keep doing our work, focusing on safe and reliable operations while being environmentally responsible and optimizing where possible. If we maintain this approach consistently, we believe we will position ourselves well for the future.

And one quick follow-up here is, every quarter, we see a very positive trend. DGD moves ahead by one quarter. And so 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 projects. I'm just spotting a trend here, sir. So let me know what you think about that.

Well, Martin, do you want to?

We have a long history in this area, and DGD 3 is essentially a larger version of DGD 2. This has been beneficial, as we have the same construction teams and contractors, and the weather has been ideal. We still need to get through hurricane season, but everything is looking great at Port Arthur.

Manav, the one thing that I would say, too, and 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 and our team's ability to execute significant projects and the partners that we've got helping execute those prospects are extraordinary. And at least to the kind of results that you said look like a trend, and it's a trend that we like and we'll try to maintain.

Our next question comes from the line of Neil Mehta with Goldman Sachs. Please proceed with your question.

First question is on the U.S. Gulf Coast. We've seen a lot of capacity retirement down there, whether it was Lyondell here recently, obviously, Shell can and then the alliance refining assets as well, something like 7% 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? And what changes of that anything? Or is that market just so deep and interconnected that retirement doesn't have a meaningful impact on the way you think about product basis?

Yes, I would say, overall, Neil, PADD 3 is an export market on both gasoline and diesel. So I wouldn't expect to see a material impact from shutdown capacity in terms of the product market. We do see it gives us some advantages on the crude stock. 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.

I would like your thoughts on the current situation in the Chinese product markets. It seems that product demand might decrease by a couple of million barrels a day, but at the same time, China isn't significantly exporting products. As a result, Singapore margins remain robust. Considering this, how much should we be concerned about China's situation? Do you believe the impact could be mitigated due to inventory levels and product quotas?

Well, Neil, I think the answer is kind of in what you just stated. Thus far, although the COVID restrictions have impacted demand in China, they're not exporting a lot of product. If there were 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.

Our next question is from the line of Sam Margolin with Wolfe Research. Please proceed with your question.

Question on capital allocation. A significant amount of your growth CapEx is low-carbon projects, and those projects come early, but they're very regimented processes. And just because a project comes early doesn't mean the next one is going to start early. So you might develop kind of a lumpy pattern of growth CapEx. And I'm just wondering if that has an effect on your other elements of your capital allocation, the other components, return on capital or if you harvest that cash, what happens when you have maybe a lean year in growth CapEx just because of the cadence of your gated process.

Are you suggesting that in a year with limited growth capital expenditures, we are looking at a situation where we invest less in growth capital expenditures?

Yes, because if you finish DGD 3 early, it doesn't mean you're going to start the next one early as well, right, because you're still going through the process for it. So you might have a gap in spending given the magnitude of your growth CapEx in that portion.

Okay, it's Lane. I'll give it a try. It's an interesting idea. I believe you'll notice our strategic and sustaining capital. We've consistently guided to an overall capital budget of 2% to 2.5%, typically around 1.5%. These are averages, so our strategic capital usually ranges from $0.5 billion to $1 billion. It will fluctuate due to the size of the projects, so while it's true there will be some year-to-year variation, I don't anticipate a drastic jump from $0 to $2 billion. You can expect about $0.5 billion of variability regarding our strategic capital spending in the near term. Do you want to add anything?

Yes, it just fits in the bar with excess cash. I don't think we'd change our model based on the variability and growth CapEx.

Right.

Yes. I mean 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 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 building a little bit of cash that never is very troubling to us.

Yes. And this is sort of a follow-up, and it is kind of a hypothetical around DGD 4. We're talking a lot on this call about clear evidence of a distillate shortage that's driven by some structural factors. And so 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. And so I'm wondering if that's a consideration that's now going into the commercial analysis behind incremental R&D projects.

Yes, this is Martin. I don't think we've approached it that way. However, I would say that the demand for renewable diesel is expected to surpass supply. There's a lot of speculation coming into play, and we will see how that unfolds. We have a positive outlook on supply and the European demand for renewable diesel. We believe that demand in Europe will significantly rebound now that there are no more COVID lockdowns. With RED 2 in place until 2030 and the aggressive plans for RED 3 in the Fit for 55 program, along with developments in California, Oregon, Washington, and the CFS in Canada, we see substantial demand ahead.

Our next question is from the line of Ryan Todd with Piper Sandler. Please proceed with your question.

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 that can tight and margins strong. Outside of a potential recession, what risks do you worry about that could materially change the outlook, Joe?

If we were to experience a significant recession, it would likely affect demand, as those circumstances are beyond our control. Additionally, another COVID outbreak that restricts mobility would also have an impact on us. However, aside from these uncontrollable factors, I generally feel optimistic about the current outlook. Do you have anything to add?

No, those comments are accurate. I believe people's tolerance for COVID has changed compared to the past. Therefore, I am not sure we will see the same level of demand destruction if a new variant of COVID arises. However, at this point, the biggest risk we face is a potential recession.

Yes.

It seems like quite a while since you've been looking to acquire a refining asset. Could you share your thoughts on the current state of the refining asset market? Specifically, we've heard about a failed sale process for the Lyondell refinery. Is that primarily due to a discrepancy between bidding and asking prices, or do you think it's becoming more challenging for large assets to be sold in the future? If that's the case, how might that impact the global supply and demand balance in the medium to long term? Are we likely to see more closures rather than sales, which could keep the market tighter than expected?

Well, I mean, probably the safest way for us to talk about that is from our own perspective. And 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. But 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 want to 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 going to cost $3 billion to get it up to a Valero standard, and I look at it maybe that wasn't exactly the best thing. So for us, truly, it is simply a matter of asset allocation, Ryan. I mean where do we want to spend our money. And 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 we want to employ than buying a refinery that's on the market at this point in time. So I'll stop there. Anything you would add, you guys?

This is Lane. I do think what it does mean is that you potentially versus transacting on a large refinery or even certainly smaller ones, the likelihood that they may shut down is probably direct. At least directionally versus the past is more likely and that's what we're seeing.

Our final question today comes from the line of Jason Gabelman with Cowen. Please proceed with your question.

I have two. The first will be a follow-up on the refining margin outlook. 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. But 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? And then 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, as 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? And then I have a quick follow-up on capital allocation.

This is Lane. I'll begin. Currently, there is a noticeable gap between European gas and U.S. gas prices due to full export facilities. For this gap to close, additional export capacity is required at liquid natural gas facilities. It's essential to identify the timeline and progress of upcoming facility constructions. Regarding global refining capacity, we have consistently stated that we don't invest a lot of effort in analyzing what others are doing in this space since we have access to the same information as you do. Our primary focus is on our own operations. That being said, we anticipate refinery closures in some regions while others will be expanding. However, we don’t overly concern ourselves with how these market dynamics will specifically impact us.

And 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 at all. You know our approach, right? We discuss matters only after fully developing them, understanding their costs, and having a solid grasp of the market. So, it's reasonable to presume that Lane and the team are assessing all projects and comparing them. I wouldn't claim that there will never be another refining project, but I can tell you that many of the initiatives they are currently considering are leaning more towards cleaner fuel options. However, I would never completely rule out the possibility of another significant project.

Great. Thanks. Thank you, everyone. We appreciate you guys dialing in.