Greetings, and welcome to the Valero Energy Corp. First Quarter 2024 Earnings Conference. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Homer Bhullar, Vice President, Investor Relations and Finance. Thank you. Please go ahead.

Good morning, everyone, and welcome to Valero Energy Corporation's First Quarter 2024 Earnings Conference Call. With me today are Lane Riggs, our CEO and President; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and COO; and several other members of Valero's senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at 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 financial metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our earnings release and filings with the SEC. Now I'll turn the call over to Lane for opening remarks.

Thank you, Homer, and good morning, everyone. We are pleased to report strong financial results for the first quarter despite heavy planned maintenance across our refining system. Our team's ability to optimize and maximize throughput while undertaking maintenance activities illustrates the benefits from our long-standing commitment to safe and reliable operations. Refining margins remain supported by tight product balances with supply constrained by seasonally heavy refining turnarounds and geopolitical events. Product demand was strong across our wholesale system with diesel demand higher and gasoline demand about the same as last year. We continue to execute strategic projects and enhance earnings capability of our business and expand our long-term competitive advantage. The DGD sustainable aviation fuel or SAF project at Port Arthur is progressing ahead of schedule and is now expected to be operational in the fourth quarter of 2024. With the completion of this project, Diamond Green Diesel is expected to become one of the largest manufacturers of SAF in the world. In addition, we are pursuing shorter cash cycle projects that optimize and capitalize on opportunities and improve margins around our existing refining assets. These projects are focused on increasing feedstock flexibility, optimizing the value of our product mix, and maximizing utilization of existing conversion capacity. On the financial side, we were paid the $167 million outstanding principal amount of our 1.2% senior notes that matured on March 15. In January, we increased the quarterly cash dividend on our common stock from $1.02 per share to $1.07 per share. Looking ahead, we expect refining margins to remain supported by tight product balances and seasonably low product inventories ahead of the driving season. Longer term, product demand is expected to exceed supply even with the startup of new refineries this year and the limited announced capacity additions beyond 2025. In closing, we remain focused on things that have been the hallmark of our strategy, maintaining operating excellence, executing our projects well, disciplined around our capital investments, and our commitment to shareholder returns. So with that, Homer, I'll hand the call back to you.

Thanks, Lane. For the first quarter of 2024, net income attributable to Valero stockholders was $1.2 billion or $3.75 per share compared to $3.1 billion or $8.29 per share for the first quarter of 2023. First quarter 2024 adjusted net income attributable to Valero stockholders was $1.3 billion or $3.82 per share compared to $3.1 billion or $8.27 per share for the first quarter of 2023. The refining segment reported $1.7 billion of operating income for the first quarter of 2024 compared to $4.1 billion for the first quarter of 2023. Refining throughput volumes in the first quarter of 2024 averaged 2.8 million barrels per day. Throughput capacity utilization was 87% in the first quarter of 2024. Refining cash operating expenses were $4.71 per barrel in the first quarter of 2024, lower than guidance of $5.10 per barrel, primarily attributed to lower energy costs and higher throughput. Renewable Diesel segment operating income was $190 million for the first quarter of 2024 compared to $205 million for the first quarter of 2023. Renewable diesel sales volumes averaged 3.7 million gallons per day in the first quarter of 2024, which was 741,000 gallons per day higher than the first quarter of 2023. The higher sales volumes in the first quarter of 2024 were due to the impact of additional volumes from the DGD Port Arthur plant which started up in the fourth quarter of 2022 and was in the process of ramping up rates in the first quarter of 2023. Operating income was lower than the first quarter of 2023 due to lower renewable diesel margin in the first quarter of 2024. The ethanol segment reported $10 million of operating income for the first quarter of 2024 compared to $39 million for the first quarter of 2023. Adjusted operating income was $39 million for the first quarter of 2024. Ethanol production volumes averaged 4.5 million gallons per day in the first quarter of 2024, which was 283,000 gallons per day higher than the first quarter of 2023. For the first quarter of 2024, G&A expenses were $258 million, net interest expense was $140 million, depreciation and amortization expense was $695 million and income tax expense was $353 million. The effective tax rate was 21%. Net cash provided by operating activities was $1.8 billion in the first quarter of 2024. Included in this amount was a $160 million unfavorable impact from working capital and $122 million of adjusted net cash provided by operating activities associated with the other joint venture member share of DGD. Excluding these items, adjusted net cash provided by operating activities was $1.9 billion in the first quarter of 2024. Regarding investing activities, we made $661 million of capital investments in the first quarter of 2024, of which $563 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, and the balance was for growing the business. Excluding capital investments attributable to the other joint venture member share of DGD and other variable interest entities, capital investments attributable to Valero were $619 million in the first quarter of 2024. Moving to financing activities, we returned $1.4 billion to our stockholders in the first quarter of 2024, of which $356 million was paid as dividends and $1 billion was for the purchase of approximately 6.6 million shares of common stock, resulting in a payout ratio of 74% for the quarter. Through share repurchases, we have reduced our share count by over 20% since year-end 2021. With respect to our balance sheet, as Lane mentioned, we repaid the $167 million outstanding principal amount of our 1.2% senior notes that matured on March 15. We ended the quarter with $8.5 billion of total debt, $2.4 billion of finance lease obligations, and $4.9 billion of cash and cash equivalents. The debt-to-capitalization ratio, net of cash and cash equivalents, was 17% as of March 31, 2024, and we ended the quarter well capitalized with $5.3 billion of available liquidity, excluding cash. Turning to guidance, we still expect capital investments attributable to Valero for 2024 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts, regulatory compliance, and joint venture investments. About $1.6 billion of that is allocated to sustaining the business and the balance to growth, with approximately half of the growth capital towards our low-carbon fuels businesses and half towards refining projects. For modeling our second quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.79 million to 1.84 million barrels per day, Mid-Continent at 410,000 to 430,000 barrels per day, West Coast at 245,000 to 265,000 barrels per day, and North Atlantic at 430,000 to 450,000 barrels per day. We expect refining cash operating expenses in the second quarter to be approximately $4.55 per barrel. With respect to the renewable diesel segment, we expect sales volumes to be approximately 1.2 billion gallons in 2024. Operating expenses in 2024 should be $0.45 per gallon, which includes $0.18 per gallon for non-cash costs such as depreciation and amortization. Our Ethanol segment is expected to produce 4.5 million gallons per day in the second quarter. Operating expenses should average $0.38 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 $710 million. For 2024, we expect G&A expenses to be approximately $975 million. That concludes our opening remarks.

Today's first question is coming from Theresa Chen of Barclays.

I want to get a sense of your product supply and demand outlook from here, maybe talking on Lane's earlier comments. And specifically, what is happening with respect to diesel and jet margins from the recent pullback? And where do you think we'll go from here?

It's Gary. I can provide insight on what we're observing in the market today, along with some thoughts on your final question. Overall, we continue to see strong demand for light products. In our system, gasoline sales are trending at levels similar to last year, while diesel sales are about 2% higher than last year. Based on the data, we expect gasoline demand to remain flat to slightly increase compared to last year. The travel data for vehicle models looks promising, suggesting there may be some upside surprises in gasoline demand. Diesel demand appears to be flat to slightly down compared to last year. However, some freight indices seem to be improving, indicating we could see better demand soon. Jet fuel demand has increased year-over-year, which is not entirely consistent with the decline in distillates. This discrepancy may be due to the market reacting to headlines, especially concerning the drone attacks in Russia. Although diesel prices may rise sharply, there’s often a delay in the supply chain, and the physical market is not feeling that disruption yet. After the drone attacks, Russian exports actually increased, but they are now beginning to decrease. However, the market seems to have overlooked this, leading to a significant sell-off. The current weak state of diesel can be attributed to negative hydroskimming margins in Europe and negative cracking margins in Singapore. Unless there's major demand-side change that we are unaware of, we need our capacity to keep operating, which implies that margins will have to strengthen from this point forward.

Really helpful. And maybe following up on the point about Russia, and I appreciate you going through the dynamics on the diesel exports and such. Maybe looking at the naphtha side of things. If the naphtha export starts to fall off as well, what does that imply for octane economics? And in light of maybe more naphtha from some of the new refining capacities added, like what is the net impact and the translation to gasoline margins as a result?

Yes. To see any meaningful changes in the price of naphtha or discount to gasoline, you really need to see pet-chem demand pick back up for naphtha, and a lot of that is just tied to the crude flat price. As long as the crude flat price is high, it's hard for naphtha to compete as a feedstock into pet-chems. When that happens, naphtha is trying to find a home in gasoline, which creates strong octane to blend into the gasoline pool.

The next question is coming from Neil Mehta of Goldman Sachs.

Another really strong quarter. And I wanted to ask about the cash flow payout as you're well above the numbers that you've targeted as the floor. So I guess the $1 billion of repurchase level, do we view that as a sustainable run rate? And how do you think about how investors should anchor to a payout guidance?

Neil, this is Jason. I'm going to ask Homer to address that question.

Yes, Neil. I think given the strength of our balance sheet in the first quarter and the fact that we're not really looking to build more cash, we had a pretty strong payout at 74%. Remember, last quarter was 73%, which ended the year at 60%. You can think of the 40% to 50% range as a long-term through-cycle commitment. But in periods where fundamentals are strong, balance sheet is good, like it is now, and sustaining growth CapEx and the dividend is covered, you can think of that as a floor. So, 40% to 50% as a floor, and I think you can reasonably expect any excess cash flow to continue to go towards buybacks.

Okay. That's helpful, Homer. The follow-up is about DGD. There was a pull forward of the SAF projects, so it seems the project is on track for a 2024 start-up. Once it becomes operational, how should we estimate the incremental economics? Additionally, what kind of premium margins do you expect to maintain on SAF barrels?

Yes, this is Eric. The project construction is progressing well, and we expect to start up in the fourth quarter. Regarding the potential uplift, if you consider the benefits from state and federal tax programs, there are numerous credits outlined in the IRA, such as 45Z, BTC, and PTC. In Europe, the Argus quote will provide a good indication of the product's value. We have strong interest in sales and do not anticipate any issues in achieving returns that meet our project's return threshold.

The next question is coming from Roger Read of Wells Fargo.

Yes. Probably to come back on some of the macro stuff here. Crude differentials, we've got some, I guess, discipline out of OPEC, we've got TMX starting up, I guess, almost any day now, we have some tightness from other places that typically export heavier crudes to the Gulf Coast. So just curious what you're seeing on the crude, call it, availability front and expectations on differentials?

Yes, Roger, this is Gary. I think we saw crude differentials move a little bit wider in the first quarter, which we expected and that was mainly driven by demand with a heavy turnaround season in the U.S. Gulf Coast. Demand was off a little bit and allowed the differentials to widen. But we believe that the differentials will be relatively tight through most of the year until you get the OPEC production back on the market. At least the consultant supply-demand balances would indicate maybe the third or fourth quarter of this year you'll start to see OPEC production ramp back up. I would tell you, we're not having any trouble in terms of availability of feedstock, it's just more narrow differentials than what we would like.

Fair enough. To follow up on your earlier comments regarding the diesel market structure and the need for cracks to increase, this time last year we observed gasoline cracks temporarily surpass diesel cracks, and we are anticipating that seasonally again. Is there any particular reason you would prefer a focus on maximizing gasoline over diesel or a blended outlook compared to your approach in recent years?

No. A lot of that gets driven by availability of intermediate feedstocks, VGO. In a tight VGO market, then you're kind of forced to swing either gasoline or diesel. So far, availability of VGO has been okay. We've been able to fill all the conversion units, but we'll have to see how that goes moving forward.

The next question is coming from Manav Gupta of UBS.

Congrats on a strong quarter again, guys. My first question here is the bear thesis on refining somewhere was not playing out. One of them doesn't have enough hydrogen, the other doesn't even have an FCC. So most likely will not be providing products to the market, maybe even by year-end 2024. But my point is, even if they do start providing the products to the market somewhere in 2025, are these the last two ones that you are aware of or is there a big wave coming after this? So I'm trying to understand: even if these two come on, they don't really change the global supply dynamics. After this, again, we could see the market tightening up again. So could you help us out there?

Yes. We see it exactly like you've described. This year was the year where you had kind of a peak in terms of new capacity additions. From this point forward, you get to where global petroleum demand outpaces new refinery capacity additions significantly, and we see several years of tightness.

Perfect. The other point is that we generally see big projects get delayed, cost overruns. You are somewhere unique. Your projects get announced and the actual start date keeps moving forward from the announcement, which is absolutely unique to you. I'm just trying to understand, how are you doing this? And I'm hoping I get an answer which is more than we have the best people because we already know that. So help us understand how you are pulling forward your projects.

Manav, it's Lane. That's exactly what I wanted to address. It reflects our culture, which emphasizes high discipline, accountability, and teamwork. We ensure that we place the right individuals in the right positions and hold them accountable. When I refer to the right people, I mean those who are competent and willing to collaborate with team members who might not be in their direct line. Ultimately, everyone is working for the benefit of Valero. We maintain a high level of visibility at the upper management level because of our relatively flat organizational structure. This allows us to be well-informed about the status of projects and understand where we stand in the development cycle once a project begins. Ultimately, it comes down to alignment, competency, and accountability; that's really our key to success. You just need to execute.

The next question is coming from Ryan Todd of Piper Sandler.

Maybe a follow-up a little bit on some of the crude mix questions from earlier. I mean, with TMX, there's a lot of focus on what the impact is going to be, particularly on complex Mid-Con refineries that are going to have to run more light sweet crude going forward. But in some ways, it's similar to what's happened across the broader refining system that's been running more and more light crude across a system that's not always optimized for this. Can you talk about what you think this might mean for the optimization of the global refining system with more light sweet crude? What sort of impact does this have on utilization or optimization or general supply as we think about the broader market?

Yes. So this is Gary. Globally, TMX doesn't have that much of an impact. It's just rebalancing the barrels. You see some of the heavier barrels from South America that were going to the West Coast won't travel there and they'll probably go more to the Far East and some more TMX barrels starting to go to the West Coast. So globally, not a big impact. We definitely see that hard-to-see differentials will come in because, for a period of time, we'll have the logistics to completely clear Western Canadian production and that could cause some switching of Mid-Continent refiners that they back off on some of the heavies and go to a lighter diet. Yes, to your comment, certainly in the Gulf Coast as we try to run a lighter diet, that has resulted in lower overall utilization because we hit light limits on the crude units.

And that's probably something that's happening across the system with a general global crude mix being lighter, right?

Yes. I think overall, the average crude gravity is up about 1.5 numbers, which certainly results in lower utilization, especially since most new capacity was designed for medium and heavy sour crudes.

Maybe switching gears to Diamond Green Diesel. As you consider the broader context, we've experienced a downturn in renewable diesel margins due to low RINs and LCFS pricing. Looking ahead to the latter part of this year and into 2025, could you discuss your perspective on the factors that might tighten that market and enhance the profitability of renewable diesel or potentially SAF in 2025?

Yes. For the remainder of this year, the situation will largely depend on the performance of various startups. We've noticed numerous reports of slowdowns, project delays, and even some shutdowns. If some of that capacity decreases or slows, we need to consider how that will balance against the new projects impacting the overall D4 RIN balance by year-end. It's challenging to predict the exact outcome. Currently, the market for vegetable oil, whether biodiesel or renewable diesel, appears negative. Agricultural products seem to be over-supplied at this moment. We anticipated more competition in waste oils, but it hasn't materialized as much as expected given the announced startups. The month-to-month balance is unclear; however, we don't foresee any changes in RVO obligations. There's still uncertainty regarding how much new capacity will be added against a fixed credit bank under fixed obligations. Looking further ahead to 2025, the long-term prospects for renewable diesel remain positive, especially given the number of LCFS programs being considered for legislation this year, and the strong growth in Canada and the U.K. Additionally, the SAF mandates that will be implemented in 2025 across Europe and the U.K. are expected to drive demand. For our company, diversifying our product offerings beyond California and expanding our product line into SAF will be advantageous. I maintain a positive long-term outlook for 2025 and beyond. Predicting 2024 is more challenging. I believe we will continue to see a surplus in D4s, and it may still be a tough year overall. However, we anticipate that the second quarter will show some margin improvement due to price lag, while the second half of the year remains uncertain with many variables at play. In the long run, there is still a positive outlook for 2025 and beyond.

The next question is coming from John Royall of JPMorgan.

So my first question is on turnarounds, I guess, for Valero and maybe in terms of expectations for the broader industry. Given you and others had a heavy turnaround quarter in the spring, should we expect a lighter fall season and maybe that global supply won't come on as expected, but we could see more supply in the second half coming out of the U.S. because it just lower turnaround than usual?

John, this is Greg Bram. I'll talk about our turnaround activity. Particularly in the first quarter, we had a pretty heavy turnaround load. You can really see that when you look at our throughput, particularly in the Gulf Coast being much lower. It's just reflective of the work that we had going on. Looking forward, as you know, we've always got turnaround activity going on in our system to varying degrees. The first quarter tends to be the heaviest period. Other periods of the year will be lighter, which is driven by what we see from a margin standpoint. There are certain times of the year like the holiday season where you're tending not to try to go into that kind of work, which is very intensive. As far as different periods of time, I won't speak so much to our plans. We have the same information others see about industry turnarounds. It looks like the fourth quarter will be more in the typical range of outages, but it's early to tell. Many things will change between now and when we get to the fall season, and we shall see where that lands. But people at least are indicating something that looks like the more typical turnaround level of activity.

Great. And then I just had a follow-up on Neil's question on returns of capital and probably for Jason or Homer. You're essentially at a full free cash flow payout now. That's what we saw in the first quarter and Homer's comments suggested that that's the expectation going forward. I know you've characterized the 40% to 50% of the floor, but is there any thought to changing that framework given that you have your balance sheet where you want it, and you seem to be kind of in this new era on returns of capital that don't seem to be peeling back to the old way of looking at things?

Well, this is Jason. Yes, I can take a stab at that. I mean, we do think about that. And really, we ask you to look more at our actions rather than that statement because we've been above it the majority of the time over the past several years. But we also view that more as a long-term indication through the cycle. I know we talk about that sometimes as a target, and it is, but we don't see any problem with being above it over a consistent period and you should expect us to behave as you said. The last couple of quarters are probably the best indication of how we're going to behave with regard to cash.

The next question is coming from Jo Laetsch of Morgan Stanley.

Congratulations on a strong quarter. I wanted to ask about SAF. Are you noticing enough demand from customers to possibly support an additional project? If that’s the case, would any announcement be made after the first facility is operational? I’m just considering the overall timing.

Yes. I think the commercial interest we are seeing exceeds our current capacity with the first project. As we've said, we're doing engineering on the second project. In terms of timing, that's always for us, that's always an issue that we're not going to talk about until we've decided internally on committing to that. What I'd say is from a macro view, you could clearly see that the units are cookie cutters of each other. The project is nearly identical, and the execution timeline and all of that is going to be very similar. So it's not a technically challenging project or something that would be difficult to fund. It's a question of how we see this market develop and when we decide internally is when we would say something externally.

Great. Yes, that makes sense. And then I was hoping to go back and dig into your comments on Asia refining dynamics earlier, just given the decline in margins that we've seen over the past couple of months. Do you think we're close to a floor over there? And then we've also seen China exports tick up in recent months. How do you think that's been impacting U.S. margins?

Yes. I think my comment there, when you have cracking margins in Singapore negative and you have hydroskimming margins in Europe negative, it kind of tells you we've hit a floor. We need the capacity to run, and I think you'll see margins start to tick back up.

The next question is coming from Paul Cheng of Scotia.

The first question, I think, is either for Gary or for Lane. Peer mix startup is going to bring the WCS, which is mostly the main mix in heavy oil with really heavy barrels. So when that happens, will your system be able to convert all your heavy intake and the medium intake using some combination of WCS plus some light barrel, or that is not as simple? Will the industry be able to eliminate all the imports from heavy barrels from the Middle East replacing them with WCS?

Yes, Paul, this is Gary. I think what we anticipate is there's a lot of coking capacity on the West Coast. I'll just use our Benicia refinery as an example. Benicia was really designed to run A&S. We think with the barrels coming off TMX, both the heavies and the lights, you'll be able to blend those together to form something that looks a lot like A&S. We would expect most West Coast refiners will be doing something similar to that.

Okay. And second question then, Gary, can you give us some comments on what you see in the Mexican market for both gasoline and diesel?

Yes. Our sales in Mexico have been consistent with historic levels. We're selling just over 100,000 barrels a day. We expect demand in Mexico remains very strong. We would expect to see that kind of ramp up later this year when we get our marine terminal in Altamira up and running, that will make us more competitive in the north and allow us to continue to grow volumes in Mexico.

Gary, do you have an export number you can share for the first quarter?

Yes. We did 103,000 barrels a day of gasoline exports. We did 153,000 barrels of diesel exports and 25,000 barrels a day of jet exports. The diesel number in the first quarter was down year-over-year, quarter-over-quarter. I wouldn't read that as a lack of demand. That was really a result of the heavy turnaround activity, and we simply didn't have barrels available for export.

The next question is coming from Matthew Blair of Tudor, Pickering, Holt.

Could you talk about your M&A appetite for refining assets? I think it's been about a decade since you did a major deal. Has anything changed regarding your outlook on M&A?

This is Lane. Not really. I mean we always look at everything. If you look at the most prompt sort of big deal that's out there, we sorted as a corporation decided not to engage in that. For whatever reason, if whoever the successful buyer can sort everything out and wants to liquidate some of the assets, we'll certainly look at them at that time. But in terms of philosophy, we look at everything. Because we have done so much buying refineries and merging and acquiring, we understand the full cost to make a refinery run at the level that we expect. Ultimately, that goes into our valuation models.

The next question is coming from Jason Gabelman of TD Cowen.

I had two market-based questions. The first, just wanted to get a sense of what you're seeing on the West Coast as we move into the summer now that another asset will be permanently shut down there? Are you seeing ratable exports coming from overseas product-wise into that market, or do you expect kind of heightened volatility and elevated prices there?

Yes. This is Gary. I would tell you, in the first quarter, we saw a little lower demand, at least in our system, in California for gasoline, which I think was related to weather. We've seen demand kind of return to normal patterns. It's very difficult to just speculate and put barrels on the water to import into the California market. We don't think a lot of people are doing that, and you need to see the market react before you would go ahead and put barrels on the water for import into California. We think there will be a lot of volatility, and it really is dependent on how refineries on the West Coast run throughout the driving season.

Got it. And then my second question, just going back to the commentary around the global lighting crude slate. You had previously made a comment that crude gravity over the past few years has gone up 3 to 4 points, and that's maybe reduced global capacity available by 3 to 4 percentage points. Can you just comment on that dynamic?

I don't know that I can quantify that. Certainly, that is our view that as the crude gravity goes higher, there's a lot of refining capacity around the world that was designed for a heavier gravity crude diet. It causes some derate to crude units, but quantifying it, I don't know that I can do that. I don't know, Greg, if you have any thoughts?

I don't have any rules of thumb either.

At this time, I would like to turn the floor back over to Mr. Bhullar for closing comments.

Thank you, Donna. Appreciate everyone joining us. Obviously, please feel free to contact the IR team if you have any follow-up questions. Thank you, everyone, and have a great day.

Ladies and gentlemen, thank you for your participation. This concludes today's event. You may disconnect your lines at this time or log off the webcast and enjoy the rest of your day.