Greetings, and welcome to the Valero First Quarter 2023 Earnings Conference Call. It is now my pleasure to introduce your host, Homer Bhullar, Vice President of Investor Relations. Thank you. You may begin.

Good morning, everyone, and welcome to Valero Energy Corporation's First Quarter 2023 Earnings Conference Call. With me today are Joe Gorder, our Chairman and CEO; Lane Riggs, our President and COO; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and Chief Commercial Officer; and several other members of Valero's senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by 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 Joe for opening remarks.

Thanks, Homer, and good morning, everyone. We had another strong quarter with all of our segments performing well. Our refineries operated at a 93% capacity utilization rate despite planned maintenance at several facilities. Our ability to optimize and maximize system throughput while undertaking maintenance activities illustrates the benefits from our long-standing commitment to operational excellence. Refining margins were supported by lower industry refining capacity in a backdrop of strong product demand. I'm also proud to report that the Port Arthur coker project was completed in March and successfully started up in early April, which is a testament to the strength of our engineering and operations teams. The project is expected to increase the refinery's throughput capacity and ability to process incremental volumes of sour crude oils and residual feedstocks while also improving turnaround efficiency. Our Renewable Diesel segment set another sales volume record in the first quarter, with the continued ramp-up of DGD Port Arthur, which was started up in November 2022. In January, we announced that DGD approved a sustainable aviation project at Port Arthur, Texas. The DGD Port Arthur plant will have the capability to upgrade approximately 50% of its current 470 million-gallon annual renewable diesel production capacity to sustainable aviation fuel or SAF. The project is expected to be completed in 2025 and is estimated to cost approximately $315 million, with half of that attributable to Valero. With the completion of this project, DGD is expected to be one of the largest manufacturers of SAF in the world. In the Ethanol segment, BlackRock and Navigator's carbon sequestration project is progressing, and they expect to begin start-up activities in late 2024. We expect to be the anchor shipper with 8 of our ethanol plants connected to this system which will allow us to produce a lower carbon-intensity ethanol product and significantly improve the margin profile and competitive positioning of our Ethanol business. And we continue to advance other low-carbon opportunities, such as renewable hydrogen, alcohol to jet and additional renewable naphtha and carbon sequestration projects. All of our projects must meet a minimum return threshold to continue to progress through our gated review process. On the financial side, we continue to strengthen our balance sheet, reducing debt by $199 million in the first quarter and ending the quarter with a net debt to capitalization ratio of 18%. In January, we announced an increase in our quarterly dividend on our common stock from $0.98 per share to $1.02 per share, demonstrating our long-standing commitment to stockholder returns. Looking ahead, we expect refining fundamentals to remain supported by low global light product inventories, tight product supply and demand balances, and continued increase in product demand as we approach peak air travel and summer driving season. In closing, our team continues to successfully execute a strategy that enables us to meet the challenge of supplying the world's need for reliable and affordable energy in an environmentally responsible manner. The tenets of our strategy, underpinned by operational excellence, deploying capital with an uncompromising focus on returns, and honoring our commitment to stockholders have been in place for nearly a decade and continue to position us well for the future. So with that, Homer, I'll hand the call back to you.

Thanks, Joe. In the first quarter of 2023, net income for Valero stockholders was $3.1 billion, or $8.29 per share, compared to $905 million, or $2.21 per share, in the first quarter of 2022. The adjusted net income for the first quarter of 2023 was $3.1 billion, or $8.27 per share, compared to $944 million, or $2.31 per share, for the same period last year. For more detailed reconciliations to adjusted amounts, please consult the earnings release and the accompanying tables. The Refining segment reported operating income of $4.1 billion for the first quarter of 2023, up from $1.5 billion in the first quarter of 2022. Refining throughput volumes averaged 2.9 million barrels per day in the first quarter of 2023, an increase of 130,000 barrels per day compared to the first quarter of 2022. The throughput capacity utilization was 93% in the first quarter of 2023, compared to 89% in the first quarter of 2022. Refining cash operating expenses were $4.78 per barrel in the first quarter of 2023, below the guidance of $4.95, mainly due to higher throughput and lower natural gas prices. The Renewable Diesel segment had operating income of $205 million in the first quarter of 2023, compared to $149 million the previous year. Renewable diesel sales volumes averaged 3 million gallons per day during the first quarter of 2023, which is an increase of 1.3 million gallons per day compared to the first quarter of 2022. This increase in sales volume was driven by additional output from the start-up of the DGD Port Arthur plant in the fourth quarter of 2022. The Ethanol segment reported operating income of $39 million in the first quarter of 2023, up from $1 million in the first quarter of 2022. Ethanol production volumes averaged 4.2 million gallons per day in the first quarter of 2023, an increase of 138,000 gallons per day compared to the first quarter of 2022. In the first quarter of 2023, G&A expenses were $244 million, and net interest expense was $146 million. Depreciation and amortization expenses totaled $660 million, and the income tax expense was $880 million for the first quarter of 2023, with an effective tax rate of 22%. Net cash provided by operating activities was $3.2 billion in the first quarter of 2023. After excluding the unfavorable change in working capital of $534 million and the other joint venture member's share of DGD's net cash from operating activities, adjusted net cash provided by operating activities amounted to $3.6 billion. In terms of investing activities, Valero made $524 million in capital investments during the first quarter of 2023, with $341 million allocated for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, while $183 million went towards growth. When excluding capital investments due to other joint venture members' share of DGD, capital investments attributable to Valero were $467 million in the first quarter of 2023. In financing activities, we returned over $1.8 billion to our stockholders in the first quarter of 2023, which included $379 million in dividends and $1.5 billion for the repurchase of approximately 11 million shares of common stock, leading to a payout ratio of 52% of net cash provided by operating activities. Regarding our balance sheet, as Joe mentioned, we reduced Valero's debt by $199 million through strategic open market repurchases in the first quarter. We concluded the quarter with $9 billion in total debt, $2.4 billion in finance lease obligations, and $5.5 billion in cash and cash equivalents. The debt-to-capitalization ratio, factoring in cash and cash equivalents, stood at 18% as of March 31, 2023. We ended the quarter in a robust position with $5.4 billion of available liquidity, excluding cash. Looking ahead, we anticipate capital investments for Valero in 2023 to be around $2 billion, which will cover expenses for turnarounds, catalysts, and joint venture investments, with approximately $1.5 billion allocated to sustaining the business and the remainder for growth. For our second quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.73 million to 1.78 million barrels per day, Mid-Continent at 405,000 to 425,000 barrels per day, West Coast at 250,000 to 270,000 barrels per day, and North Atlantic at 450,000 to 470,000 barrels per day. We project refining cash operating expenses in the second quarter to be around $4.60 per barrel. In the Renewable Diesel segment, we expect sales volumes to reach approximately 1.2 billion gallons in 2023, with operating expenses averaging per gallon, including $0.19 for non-cash costs like depreciation and amortization. Our Ethanol segment is expected to produce 4.2 million gallons per day in the second quarter, with operating expenses averaging $0.40 per gallon, encompassing $0.05 per gallon for non-cash costs such as depreciation and amortization. For the second quarter, we anticipate net interest expense to be about $145 million, and total depreciation and amortization expense to be around $670 million. For the year 2023, we expect G&A expenses, excluding corporate depreciation, to be approximately $925 million. That concludes our opening remarks.

Our first question is from Manav Gupta with UBS.

Congrats on a very good result. I'm not sure if there are many other refiners out there who can show this kind of capture with such heavy turnaround. So congrats on that. I have two quick questions and I'll ask them upfront. We keep seeing DOE data, which is prone to revisions, but sometimes doesn't actually make too much sense. So Joe, in your system across various products, what are you seeing in terms of demand for various products in your system? And the second and related question is, help us understand a little bit what's going on in the diesel market. Are we suddenly oversupplied? Is the demand weak? If you could just talk through those diesel dynamics.

No, Manav, we're happy to do that, and thanks for your comments. Gary, do you want to give them some insight?

Yes, sure. So far, our 7-day average in our wholesale system, our gasoline sales are up 16% year-over-year. Our diesel volumes are up 25% year-over-year. So our wholesale team continues to do a great job. In March, we set a record at 998,000 barrels a day. In April, the volumes are trending right along those levels. So demand seems very, very strong in our system. And even the DTN data for the wholesale racks across the industry is very strong as well. In terms of your question on diesel weakness, we're just not seeing it. I can tell you, in addition to the wholesale volumes, today, there's domestic arbitrage opportunities that are open from PADD 3 into PADD 2 as we're seeing a surge in agricultural demand that's going along with planting season. You also have a domestic arb open to ship from PADD 3 to PADD 1. We see strong waterborne premiums to go to Latin America. The transatlantic arbitrage is open to Europe. And so for us, distillate fundamentals look pretty good.

Our next question is coming from the line of Theresa Chen with Barclays.

Can you comment on your outlook for Gulf Coast capture from here? Clearly, the start-up of the Port Arthur coker should be a tailwind, but we've also seen differentials come in. Net-net, how do you view the profitability of your Gulf Coast system, both near term and longer term?

Yes, this is Lane. I can provide some general comments about capture rates, sort of compare our first quarter capture rate to our second quarter capture rate. Holding all things equal, we'll blend less butane. So holding everything equal, our capture rate will actually fall just due to butane. And then as you alluded to, you look at feedstocks, what's the trajectory of feedstocks, they're lower. On the other side of it, we're seeing big RBOB premiums versus CBOB. So to the extent that, that's not captured in our capture rate, that's actually a positive. So there are several things you've got to look at. And what you've got to focus on are the drivers that may not be in our formula for our crack attainment and how those change relative to things tied to it. An example would be Maya versus WCS or, like I said, RBOB versus CBOB. Those are the things you've kind of got to key on trying to predict maybe how our crack attainment looks.

On a related note, how do you see the BGO situation developing in terms of your Gulf Coast consumption and the global supply following the EU embargo on Russian products and the reduction in Saudi exports after the conversion unit issues?

I will begin with an update on our system, then Gary will discuss the supply. The startup of our Port Arthur Coker significantly strengthens our VGO position. Essentially, it converts resid and heavier crudes into distillates and VGO boiling range material. Consequently, our need for importing VGO has decreased following the new coker's startup.

Yes. In terms of supply, I think we were concerned that the ramp-up in sanctions against Russia would limit VGO exports and cause VGO tightness. So far, it looks like the Russian barrels are continuing to flow. And so we're not nearly as concerned about VGO supply as we were earlier in the year.

Our next question is coming from the line of Doug Leggate with Bank of America.

This is Kalei on for Doug. I've got a follow-up to Theresa's question, and it really goes to the availability of heavy sours that are in the market. There is a perception that, that length is getting shorter with OPEC cuts and then increased demand from new projects such as your coker and perhaps MPC's resid hydrocracker are squeezing the market for those kinds of supplies. Can you talk about what you guys are seeing and if the phased start-ups of the new refineries, where not all the units are online, could help alleviate that situation.

Yes. I'll go through our observations. In the first quarter, we noticed that the supply-demand balance for heavy sour oil tightened. This was partly due to supply issues, and also because Chinese refinery utilization increased, adding more demand to the system. Looking ahead, there are some positive indicators. Platts reports a deficit of 500,000 barrels a day. Canadian crude production is offline for maintenance, but we expect that production to resume. Venezuelan production is projected to rise, and we anticipate more Chevron output from that area will reach the Gulf as the year progresses. Eventually, the Lyondell refinery is expected to come offline, which will increase the supply of heavy sour oil back to the market. If the forecasts for supply and demand hold true, we will likely need OPEC production reinstated, which would be favorable for differentials.

Got it. And a quick follow-up to that. Can you talk about what you're seeing for new refining capacity that's supposed to come online, like Dangote and Dos Bocas in Mexico?

Yes, I really can't make a comment. We don't have a lot of insight into either one of those refineries.

Thank you. Our next question is coming from the line of John Royall with JPMorgan.

Just wanted to start on the return of capital side. You guys returned above your 40% to 50% range again this quarter, I think second quarter in a row. What's your latest thinking on where you want to be in that range of returns to shareholders given your balance sheet is very strong, but fundamentals appear to be ticking down and you can see that in your indicators.

Yes. No, that's right. This is Jason. And you're right, our balance sheet is in good shape right now. We've got over $5.5 billion of cash, and we feel pretty strong there. We got our net debt to cap ratio down into a good spot around 18%, which is well at the lower end of our range. So we feel like we're in a pretty good spot with regard to any potential recessionary conditions. And as far as our target for where we want to be in our range, we'll continue to target the 40% to 50% when we have strong results. Of course, we'll be looking at the upper end of that. We ended at 45% last year, paid out 52% this quarter. Actually, with the extra cash we had, we did kind of an all-of-the-above strategy; we were able to build our cash by $600 million, payout at 52%, and also paid back a little more debt. So it will just depend on how the year plays out, where we fall in the range, right, in the payout range.

Great. And then I was hoping you could also touch on the regulatory changes out in California and how you expect those to play out and the potential impact on both your business and maybe just the broad refining market in California.

This is Rich. I can start out with just sort of the regulatory climate. California has always been a tough regulatory climate for operations. And so I'm assuming you're talking about the California 2 rulemaking that's out there. And what we would just say is that the bill does have some burden, some reporting requirements in it. And then obviously, it kicks a profit tax over to this California Energy Commission to implement it. And so we'll stay active and engaged in that rulemaking process and watch what develops out of the agency there. It's unclear what price cap, if any, they'll ultimately put in place. I would point out that the rulemaking on that, the standard that the agency is supposed to use is they're supposed to determine that the benefits to consumers are outweighed by the potential cost to consumers. It goes without saying that attempts by governments to artificially limit commodity prices has never been really good for the economy, and it ultimately ends up hurting consumers. So we'll just have to see how that all plays out.

And John, this is Joe. Just let me bolt on something to what Rich said. So we have a great team operating both of our refineries on the West Coast. Great teams are running those plants. And we have been very consistent and clear in our approach to the California business. That is we aggressively manage the capital, we invest to maintain safe and reliable operations out there, but we haven't invested capital in growing that business for many years now. Now historically, California, in a normal operating environment, isn't a strong contributor to our earnings. We've always viewed it as an option on periodically strong margins. And if the margin caps are set at levels that remove the upside, the opportunity to earn a return isn't there the way it's been in the past, and we'll have to evaluate our options. Right now, Rich and his team are communicating to the California Energy Commission and others the concerns that we have, and we're just going to have to wait and see what happens out there. So it is an environment that is a difficult operating environment. I would not even take a shot at stating what might happen to the overall refining environment out there, but I can just tell you that from our perspective, we're just going to have to watch it and see and then we'll evaluate our options.

The next question is coming from the line of Paul Sankey with Sankey Research.

Could you repeat the wholesale sales demand number that you just gave and explain how come, if I heard you right, that's growing so massively.

Yes. So our wholesale gasoline sales are up 16% year-over-year. Our distillate sales are up 25% year-over-year. In March, we set a sales volume record at 998,000 barrels a day. And then April, the volumes are trending about like they did in March. So certainly, when you look at the broader DTN wholesale volume data, it's not as significant growth as what we're seeing, and so it indicates we're doing a good job of capturing market share.

So there's no structural change. It's just better wholesale performance?

Yes. Okay. I'm not counting that as a question, Joe.

Paul, we could talk all day.

I'm in D.C. right now. Regarding the IRA, what are your thoughts on how that might affect your business concerning the regulatory environment? We've already discussed the situation in California, but I'm interested if you have any new insights on the changes happening in Washington. Additionally, carbon capture is a significant topic here, and I'd like to know your perspective on that.

This is Rich Walsh again. I will address that. I believe you are referring to some ongoing negotiations. This morning, the Republican bill has been revised to reinstate some of the credits that were previously proposed to be removed. We are now looking at the clean energy tax credits being reintroduced, which support our renewable energy initiatives and some of our sequestration projects. Additionally, investments already made in carbon capture have been grandfathered in, while projects related to sustainable aviation fuel have been reinstated. This means our projects will still qualify for the appropriate treatments.

Yes, I understand. I think that SAF is definitely a very interesting topic. Generally speaking, we've noticed that market margins have decreased significantly, which seems unusual for this time of year. Is there anything you've noticed, especially in relation to your wholesale margins and deliveries? The substantial decline we've observed doesn't seem to be fully justified by the underlying fundamentals. For instance, there was a strong gasoline demand number reported this week. Do you have any insights on how Q2 is likely to unfold? I'll stop there.

Yes, Paul, our view is whenever inventory is as low as it is today, it just puts you way out on the margin curve where the slope is really steep and any type of market news can have a significant impact on prices and margins. So early in the year, the market headlines were all about losing Russian supply with the ramp-up in sanctions and it drove the market up. Today, I think people are generally comfortable that the Russian barrels will continue to flow and then a lot of concern on the economy and what happens with demand in the future. As I've said, we're not seeing any indication of demand weakness today, but I think that's a concern is what happens in the future.

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

Yes, I'd like to follow up on the comments regarding how you're viewing the diesel and gasoline markets. There are many ways to monitor demand and supply shortfalls, but one metric we focus on is the situation at both ends of the Colonial pipeline, which indicates notable pressure in the gasoline market. I would like to explore what you observe in the Atlantic Basin, especially between New York and Northwest Europe, regarding the overall gasoline supply. Is it a matter of components, or what exactly is happening there?

Yes. So I think there are several factors that come into play there, Roger. Historically, we see an incentive to store summer-grade gasoline or components in New York Harbor. This winter, the market structure really made it where it wasn't economic to do that. And so we did build inventory for that. And then, again, typically in the first quarter, you see a lot of volume going across the Atlantic from Europe into New York Harbor early in the year, and the strikes that occurred in France minimized those volumes as well. So we've come into driving season with 10 million barrels below where we were last year on gasoline inventory. So especially summer-grade gasoline is very tight, and it is going to stress the Colonial system as we move into driving season.

Yes. I mean it's early in the quarter, but really haven't seen the gap quite this large at this time of the year before. So it definitely shows stress. Follow-up question, if I could, on the SAF. Obviously, you mentioned there are some opportunities in terms of what's moving forward legislatively. If you weren't to see, let's call it, fundamental support for SAF margins, do you want to make SAF? I mean, what's the driver to do that versus renewable diesel which obviously already enjoys support as well as LCFS programs.

Roger, this is Eric. I think we still see a big demand for SAF in the future. The EU just talked about mandating it beginning in 2025 and at increasing percentages as you get to 2030 and 2050. So the IRA isn't the only driver for SAF. I think, between what we see in different jurisdictions starting to obligate jet and make it a mandatory requirement as well as just the internal commitments that a lot of the airlines and cargo carriers have made from a corporate standpoint, we still see that SAF is going to be a strategic growth area for renewables.

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

Maybe I'll stick for one follow-up on the low carbon fuel side. Can you talk a little bit about a couple of the carbon possibilities that you mentioned earlier in the call, you mentioned renewable alcohol to jet. What would either of those projects look like in your current operations? And are there further changes in product prices or regulatory support that would be required to make either of those businesses make sense?

I think this is Eric again. We'll start with ethanol to jet. If the Navigator project proceeds, it will reduce the carbon intensity of our ethanol enough to qualify as a feedstock for sustainable aviation fuel. Looking at that as a precursor project, it could enable an ethanol-to-jet SAF project, which we are considering. However, that’s still several years away from any detailed discussion. Conceptually, this aligns with our project plans. Additionally, renewable hydrogen presents another future opportunity. As you explore low-carbon platforms, producing blue or green hydrogen offers another method to decrease carbon intensity in our low-carbon operations.

Great. I have a quick follow-up regarding the Port Arthur coker. Congratulations on getting that started up. Is there a ramp-up associated with operations there? How should we expect contributions from that in the second quarter? Additionally, do you have any updates or thoughts on what the annualized EBITDA contribution might be in the current environment?

Yes, this is Lane. So we started it up on April 5. I would say actually, this week, we've sort of ramped up most of the refinery up to where we're running. We're close to full. From now through the rest of the quarter, you will see the benefits of the coker. Clean start-up, as Joe alluded to earlier in his comments. It was done really well by our team. It's working just as we had indicated. In terms of the contribution on EBITDA, when you take sort of the current volumetrics and use forward pricing on it, it's normally about $0.5 billion a year is the benefit.

Our next question is coming from the line of Jason Gabelman with TD Cowen.

I wanted to ask one on market structure. I think there's some concern because there's headlines around Asia cutting refining runs because margins are low there and there's some concern that, that could permeate into the U.S. And so the question is, how should the market kind of take that indicator? Should they think that while Asia margins are falling and so U.S. will follow because there's global weakness? Or conversely, because Asia margins are falling, U.S. cracks are around the level they are, probably closer to a floor, because of the structural kind of tailwinds that are out there and Asia is kind of absorbing all of the throughput declines related to global demand issues? I know it's a bit of a complex question, but I guess, give it a shot.

Yes. So I think the way we would view it is much like you said, we would view it as it's kind of telling us where the floor on margins. It's not just Asia, but in Europe margins are negative. And so a lot of that is the distillate weakness. We still see diesel inventory very, very low. And we view that some of that capacity should actually be running. And so it's telling you where the floor on margins are.

Okay. That's helpful. And then a follow-up on DGD. Where are we in terms of the DGD distribution? Have you received one yet? Is that coming soon? And how are you thinking about that cash being moved up to the partners moving forward?

Yes. We've looked at the DGD cash flow, and we would still say we see a distribution in the back half of this year becoming an opportunity for the partners.

Okay. Any idea around the quantity?

No, we're not going to give a number like that out, but it does look positive through the end of the year.

Our next question is coming from the line of Matthew Blair with Tudor, Pickering, Holt.

Joe, could you help us understand the Q1 refining capture, a strong figure, a little bit more. I think Lane mentioned butane blending was a tailwind. What else drove it up? And I guess, specifically, were product exports more of a supporting factor than normal? And then also, was there any impact from turning in the 2021 RINs, like any sort of mark-to-market as you submitted the 2021 RINs in March of 23?

So Matt, this is Lane. I'll start out with the first part of it. So the factors contributing were we had backwardation sort of flattened out in the market on feedstock; that's always one you get. So market structure plays into capture rates in a big way. So it's tightened out some. You had wider differentials in the first quarter versus the fourth quarter on all the crudes that we run. And then finally, there were pretty good jet premiums versus distillate in the first quarter. Those are the other things driving our capture rate. With respect to the other mentioned points, I don't think the RIN had anything to do with it. And I wouldn't say exports had any kind of material impact on capture rates either.

Great. Regarding the Q2 Refining guidance, it suggests about 90% to 93% utilization. You achieved 93% in Q1, so I would be surprised if it decreases. Should we consider this a conservative estimate, or are there significant turnarounds we need to be aware of that could affect your expected run rate for Q2?

Yes, this is Lane. We have a policy of not really commenting directly on our turnaround activity, but I would just take the guidance to be kind of where we think it's going to be.

Yes. Matthew, you're familiar with our history and approach. We won't oversell anything. We'll assess the market conditions and, as Lane mentioned, we'll operate accordingly.

We have no additional questions at this time. So I'll pass the floor over to management for any additional closing remarks.

Thanks, Jesse. We appreciate everyone joining us today. Obviously, feel free to contact the IR team if you have any questions. Have a great week. Thank you, everyone.

Ladies and gentlemen, this does conclude our call and webcast. You may disconnect your lines at this time. We thank you for your participation.