Valero Energy Corporation (NYSE:VLO) Q1 2024 Earnings Call Transcript

Valero Energy Corporation (NYSE:VLO) Q1 2024 Earnings Call Transcript April 25, 2024

Valero Energy Corporation beats earnings expectations. Reported EPS is $3.82, expectations were $3.18. VLO isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Greetings, and welcome to the Valero Energy Corp. First Quarter 2024 Earnings Conference. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] 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.

Homer Bhullar: 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.

Lane Riggs: 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 benefit from our longstanding 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.

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 project mix, and maximizing utilization of existing conversion capacity. On the financial side, we repaid the $167 million outstanding principle amount of our 1.2% Senior Notes that mature on March 15.

And 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 is exceed supply even with the start of the new refineries this year and the limited announced capacity additions beyond 2025. In closing, we remain focused on [things] (ph) that have been a hallmark of our strategy; maintaining operating excellence, executing our projects well, discipline around our capital investments, and our commitments to shareholder returns. So, with that, Homer, I’ll hand the call back to you.

Homer Bhullar: 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, 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 was 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 was over 20% since yearend 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. Before we open the call to questions, please limit each turn in the Q&A to two questions, if you have more than two questions, please rejoin the queue as time permits to ensure other callers have time to ask their questions.

Operator: Ladies and gentlemen, the floor is now open for questions. [Operator Instructions] Today’s first question is coming from Theresa Chen of Barclays. Please go ahead.

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Q&A Session

Theresa Chen: Good morning. Want to get a sense of your product supply and demand outlook from here, and maybe touching 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?

Gary Simmons: Hey, good morning, Theresa. It’s Gary. I’ll you some insight just to what we’re seeing in the market today, and then some thoughts on your final question. Overall, we continue to see strong light product demand. In our system, we’ve seen gasoline sales trending at levels equal to last year. Diesel sales in our system are actually trending about 2% higher than last year. So, I think when we look at all the data, we would expect gasoline demand to be flat to slightly up from last year. Vehicle miles travel data is encouraging, would indicate we could see some gasoline demand surprise to the upside. Diesel demand, flat to slightly down compared to last year. However, again, some of the freight indices appear to be turning, and indicate we could start seeing better demand.

And then, jet fuel demand up year-over-year, I think that isn’t really consistent with the sell-off in distillates, like you’re seeing. And I think some of that’s just attributable to the fact that the market appears to be reacting to headlines. So, in particular, you have the drone attacks in Russia, diesel gets very strong. But then there’s a lag in the supply chain. So, the physical markets aren’t really seeing that interruption in diesel. In fact, Russian exports, following the drone attacks, was actually higher. And so, now, we’re finally getting to the point where Russian exports are starting to fall off, but the markets have kind of dismissed that, and sold off pretty hard. I think diesel is too weak. And the two things I would point to on diesel being too weak, hydroskimming margins in Europe were negative, cracking margins are negative.

And unless something significant has happened on the demand side that we don’t see, we need that capacity to run, which would indicate margins are going to have to get stronger from here on.

Theresa Chen: Very helpful. Thank you, Gary. And maybe following up on the point about Russia, and appreciate you going through the dynamics on the diesel exports, and such. Maybe looking at the naphtha side of things, and so if the naphtha exports 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 capacity added, like what is the next impact and the translation to gasoline margins as a result?

Gary Simmons: Yes, so I think in order 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 crude flat prices. As long as crude flat price is high, it’s hard for naphtha to compete as a feedstock into pet-chems. And so, when that happens, then naphtha is trying to find a home into — to gasoline, which creates strong octane in order to be able to get it blended into the gasoline pool.

Theresa Chen: Thank you.

Operator: Thank you. The next question is coming from Neil Mehta of Goldman Sachs. Please go ahead.

Neil Mehta: Good morning, team, another really strong quarter. And I want to ask about the cash flow payout as you’re well above the numbers that you’ve targeted as the floor. And so, 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?

Jason Fraser: Morning, Neil. This is Jason. I’m going to ask Homer to address that question.

Homer Bhullar: 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%. And you’ll remember, last quarter was 73%, which ended the year at 60%. So, I think 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 dividend is covered, you can think of that as the floor. So, the 40% to 50% of the floor, and I think reasonably expect any excess cash flow to continue to go towards buybacks.

Neil Mehta: And that’s helpful, Homer. And then, follow-up is just on DGD. There was a pull forward of the SAF project, so it looks like project is tracking well for ’24 startup. So, just how — and once it comes into service, what’s the back of the envelope of how we should think about the incremental economics? And what type of premium margins do you think you could sustain on SAF barrels?

Eric Fisher: Yes, this is Eric. The project continue — like you said, the project construction is going well. Startup will be in the fourth quarter. As far as what we see in uplift, I think if you look to see what state and federal tax program benefits are, there’s a lot of credits that have been stated in the IRA, whether it’s 45Z or BTC or PTC. And then, in Europe, you’ve got the Argus quote, that all kind of give you a good feel of what that product is going to be worth. We’ve got strong interest in sales, and we do not see a problem moving it at returns that are going to meet our project return threshold.

Operator: Thank you. The next question is coming from Roger Read of Wells Fargo. Please go ahead.

Roger Read: Yes, thank you, and good morning. 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, on us any day now. We have some tightness from some other places that typically have exported heavier crudes to the Gulf Coast. So, just curious what you’re seeing on the crude, call it, availability front, and expectations on differentials.

Gary Simmons: 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 just driven by demand. With heavy turnaround seasonally in the U.S. Gulf Coast, demand was off a little bit, and allowed the differentials to widen. But we believe that the differentials would be relatively tight to most of the year, until you get the OPEC production back on the market. At least the consultant supply-demand balances would indicate maybe 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 narrowed differentials than what we would like.

Roger Read: Fair enough. And then, to follow-up on your earlier comments about the structure of the diesel market, the need for cracks to go up, this time, last year, we saw gasoline, for a little while move above — gasoline cracks move above diesel cracks. We have that seasonally again. But is there any reason that you would lean into a max gasoline over a max diesel or a blended sort of outlook relative to what you’ve been doing over the last couple years here?

Gary Simmons: I think a lot of that gets driven by availability of intermediate feedstock’s VGO. In a tight VGO market, then you’re kind of forced more 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.

Roger Read: Okay, thank you.

Operator: Thank you. The next question is coming from Manav Gupta of UBS. Please go ahead.

Manav Gupta: Congrats on a strong quarter again, guys. And my first question here is the [bare pieces] (ph) on refining somewhere was [Des Baggott] (ph) and Dangote. And it looks like it’s not played out these assets or from what we can read and hear, one of them doesn’t have enough hydrogen, the other doesn’t even have an FCC [receipt] (ph), so, most likely, will not be providing products to the markets maybe even year-end 2024. But my point is, even if they do start providing products to the market somewhere in 2025, are these the last two ones that you are aware of or there’s a big wave coming after this? So, I’m trying to understand if even if these two come on, they don’t really change the globally supply dynamic. So, after this, again, we could see the markets tightening up again. So, if you could help us out there?

Gary Simmons: Yes, so 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. And then, from this point forward, you get to where global petroleum demand outpaces new refinery capacity additions significantly. And we see several years of tightness.

Manav Gupta: Perfect. The other point is that we generally see big projects get delayed, cost overruns. You’re somewhere unique, your projects get announced and the actual start date keeps moving forward from the announcement, which is absolutely unique to you. And I’m just trying to understand, like, 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 are you pulling forward your projects?

Lane Riggs: Well, Manav, obviously, that’s what I was going to say. But it speaks to the culture. Our culture is very much about high discipline, high accountability, and teamwork. We make sure we get the right people into the right jobs and hold them accountable. And making sure that they’re — and when I say the right people, they have to be people who are A, competent and B, they’re willing to work with the other team members who may not necessarily be under them or adjacent to them, and ultimately working on behalf of Valero. And we have a high level of visibility with upper level management because we’re a pretty organization. So, we all know the status of the projects. We all understand where we are in the development cycle. And once the project starts, I mean, it’s not like there’s, it’s just ultimately it’s about alignment, competency, and accountability. And that’s really the secret sauce. You just got to execute you know.

Manav Gupta: Thank you, sir.

Operator: Thank you. The next question is coming from Ryan Todd of Piper Sandler. Please go ahead.

Ryan Todd: Thanks. 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 optimized for this. I mean, 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 broader market?

Gary Simmons: Yes. So, this is Gary. So, globally TMX doesn’t have that much of an impact. It’s just rebalancing the barrels. I think 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 here, 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. And, yes, to your basically to your comment, certainly in the Gulf Coast, as we tried to run a lighter diet, it’s resulted in lower overall utilization because we hit light limits on the crude units.

Ryan Todd: Thanks. And that’s probably something that’s happening on a broader sense across the system with general global crude mix being lighter, right?

Gary Simmons: Yes, I think overall, the average crude gravity is up about one and a half numbers, which certainly results in lower utilization because especially most new capacity always designed for medium and heavy sour crudes.

Ryan Todd: Thanks. Maybe switching gears to diamond green diesel. I mean, as you think about the broader, obviously, we’ve been through a soft spot here on renewable diesel margins with RINs and LCFS pricing low. As you think about the outlook into the back part of this year and into 2025, can you maybe walk through how you view some of the moving pieces that could tighten up that market and improve kind of the relative profitability of whether it’s renewable diesel or then eventually SAF in 2025?

Gary Simmons: Yes, I think the rest of this year, it’s really going to be a question of what some of the other startups look like. , we’ve seen in the news a lot of announcements of slowdowns, project delays, even some shutdowns. Is that capacity comes offline or slows down? How does that balance versus some of the projects that are starting up in the overall D4 RIN balance at the end of the year? It’s a little difficult to throw a dart and know exactly how that’s going to end. What we can see is veg oil, whether it’s BD or RD is negative. Ag products all look very long right now. We do see — we were expecting more competition on waste oils. We haven’t seen as much of that as we thought we would considering the announced startups.

So, how all that balances out for the rest of the year, the thing there is we don’t see any change in the RVO obligation. So, it’s still a question of how much capacity is going into a fixed credit bank in a fixed obligation. And so longer term, if you look at ’25, I would think the long-term outlook of RD is still positive because you look at the number of LCFS programs that are still being contemplated by legislation this year, the ramps in Canada and the UK continue to be strong. The SAF mandates that are kicking in, in 2025 in Europe and the UK are going to create demand. And for us diversification of your product away from California and your ability to diversify your product slate into SAF are going to be very beneficial to DGD. So, I still like the longer-term outlook of ’25 and beyond.

’24 is a little hard to predict. I think it probably still stays long in the D4s, net-net. So, it might continue to be sort of a tough year. We think the second quarter from a margin standpoint looks a little better from price lag standpoint. But the back-half is still hard to tell with all the moving pieces. But long-term, I think you still see a positive outlook sort of ’25 and beyond.

Ryan Todd: Okay. Thank you.

Operator: Thank you. The next question is coming from John Royall of J.P. Morgan. Please go ahead.

John Royall: Hi. Good morning. Thanks for taking my question. So, my first question is on turnaround, 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 just lower turnaround than usual?

Greg Bram: Hey, 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 the Gulf Coast throughput being much lower. It’s just reflective of the work that we had going on. Looking forward, as 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. And that’s just kind of driven by what we see from a margin standpoint, is there’s certain times of the year, like the holiday season, where you’re tending not to try to go into that kind of work that’s very intensive.

As far as different periods of time, yes, it 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 kind of more in the typical range of outages, but it’s early to tell. A lot of things will change between now and when we get to the fall season. And so, we’ll see where that lands, but people at least are indicating something that looks like the more typical turnaround level of activity.

John Royall: Great. Thanks, Greg. 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 comment 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 kind of peeling back to the old way of looking at things.

Jason Fraser: 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 in the majority of 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 sometimes that’s a target, and it is, but we don’t see any problem with being above it over a consistent period of time. And you should expect us to kind of behave, as you said, the last couple of quarters are probably the best indication of the future is how we’re going to behave with regard to cash.

John Royall: Okay. Fair enough. Thank you.

Operator: Thank you. The next question is coming from —

Joe Laetsch: Hey, Donna, are you still there?

Operator: I’m sorry. Yes, I’m sorry. The next question is coming from Joe Laetsch of Morgan Stanley. Please go ahead.

Joe Laetsch: Hey, all. Good morning, and thanks for taking my questions, and congrats on a strong quarter. So, I wanted to go back to SAF. Are you seeing enough demand from customers to potentially support an additional project? And then, if so, would any potential announcement come after the first facility is online? Just trying to think about timing overall?

Gary Simmons: Yes. I think what we’re seeing in terms of the commercial interest 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 that until we’ve decided internally on committing to that. But what I’d say from a macro view, you can clearly — the units are cookie cutters of each other. The project is nearly identical. The execution time 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 developed and when we decide to commit internally is when we would say something externally.

Joe Laetsch: 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?

Gary Simmons: Yes. So, I think my comment there, when you have cracking margins in Singapore negative and you have hydro skimming 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.

Joe Laetsch: Great. Thank you all.

Operator: Thank you. The next question is coming from Paul Cheng of Scotia. Please go ahead.

Paul Cheng: Hey, guys. Good morning.

Gary Simmons: Good morning, Paul.

Paul Cheng: The first question, good morning, the first question, I think, is either for Gary or for Lane. TMX stopped up. And so, that’s going to bring the WCS, which is mostly the man-made synthetic heavy oil with really heavy bottom and a lot of light barrels and no middle. So, when that happens, will your system be able to convert all your — if the price is right, can your system convert all your heavy intake and the medium intake into using some form of combination of WCS plus some light barrel or that is not as simple? And also, whether the industry will be able to, say, eliminate all their imports from the heavy barrel from, say, [indiscernible] from the Middle East replacing the WCS? That’s the first question.

Gary Simmons: Yes, Paul, this is Gary. I think what we anticipate, 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 ANS. And we think with the barrels that are 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 ANS. And we would expect most West Coast refiners will be doing something similar to that.

Paul Cheng: Okay. And second question that, Gary, can you give us some, maybe, your cut list that what you see in the Mexican market for both gasoline and diesel?

Gary Simmons: Yes. So, 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’ll make us more competitive in the North and allow us to continue to grow volumes in Mexico.

Paul Cheng: Hey, Gary, do you have an export number you can share?

Gary Simmons: Export?

Paul Cheng: in the first quarter? Yes. So, how much did you export?

Gary Simmons: Yes. So, 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. And I wouldn’t read that as lack of demand. That was really a result of the heavy turnaround activity and just we didn’t have barrels available for export.

Paul Cheng: Thank you.

Operator: Thank you. The next question is coming from Matthew Blair of Tudor, Pickering, Holt. Please go ahead.

Matthew Blair: Hey, good morning. 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? It’s been about a decade since you did a major deal. Has anything changed regarding your overall outlook on M&A?

Lane Riggs: This is Lane, not really. I mean, we always look at everything. I mean, if you look at the most prompt sort of big deal that’s out there at CITGO, we’ve sort of, as a corporation, decided not to engage in that. For whatever reason, whoever the successful buyer taken, if they can sort everything out, wants to liquidate some of the assets, we’ll certainly look at them at that time. In terms of philosophy, we look at everything, but we also, as a company, because we have done so much buying refineries and merging and acquiring, we understand the full cost to make a refinery run, it’s certainly at the level that we expect. And so, ultimately that goes into our valuation models.

Matthew Blair: Sounds good, I’ll leave it there. Thanks.

Operator: Thank you. The next question is coming from Jason Gabelman of TD Cowen. Please go ahead.

Jason Gabelman: Hey, good morning. 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 see ratable exports coming from overseas product-wise into that market or do you expect kind of heightened volatility and elevator prices there?

Gary Simmons: Yes, so this is Gary. I would tell you in the first quarter, we saw a little lower demand, at least in our system, California for gasoline, which I think was related to weather. We’ve seen demand kind of return to normal patterns. And it’s very difficult to just speculate and put barrels on the water to import the California market. So, 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. So, we think there will be a lot of volatility, and it really is all dependent on how refineries on the West Coast run throughout the driving season.

Jason Gabelman: Got it. And then, my second question, just going back to the commentary around the global lightning crude slate, and you had previously made a comment that crude gravity over the past few years has gone up three to four points, and that’s maybe reduced global capacity available by three to four percentage points. Can you just comment on that dynamic?

Gary Simmons: 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 de-rate crude units, but quantifying it, I don’t know that I can do that. I don’t know, Greg, if you have —

Greg Bram: I don’t have any rules with me either.

Jason Gabelman: Okay. I’ll leave it there. Thanks.

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

Homer Bhullar: Thank you, Donna. I 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.

Operator: 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.