Greetings, and welcome to the Valero Energy Corp. Second Quarter 2023 Earnings Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. 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 second quarter 2023 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. Before we discuss quarterly results, I want to thank Joe Gorder for everything he's done to build upon Valero's 43-year history. Joe steered a repositioning of our strategy and the commitment to shareholder returns through capital discipline, innovation and strong execution. I'm grateful for his leadership and proud of what Valero has accomplished, and I'm honored to build on that foundation as we continue to advance our position as a leading manufacturer of liquid transportation fuels. Moving on to quarterly results. We are pleased to report solid financial results in the second quarter, underpinned by our strong execution across all of our business segments. Our refineries ran well with throughput capacity utilization of 94% as refinery margins were supported by continued tight product supply and demand balances. Product demand was strong with our US wholesale system setting a sales record of over one million barrels per day in May and June. We also had a positive contribution from the Port Arthur Coker project, which was started up in early April and is operating well and at full capacity. The new coker has increased the refinery's throughput capacity and enhances its ability to process incremental volumes of heavy crude and residual feedstocks. Our Renewable Diesel segment set records for operating income and sales volumes in the second quarter, driven by incremental production volumes from Diamond Green Diesel, Port Arthur. The Diamond Green Diesel sustainable aviation fuel project at Port Arthur is progressing on schedule. Plan is expected to have the ability to upgrade 50% of the current 470 million gallon annual renewable diesel production capacity through Sustainable Aviation Fuel or SAF, is expected to be complete in 2025 and have estimated a cost of $315 million, with half of that attributable to Valero. With the completion of this project, DGD is expected to become one of the largest manufacturers of SAF in the world. These projects expand our long-term competitive advantage, and I want to commend our projects and operations team for their dedication and execution. We also continue to evaluate other opportunities while maintaining capital discipline and honoring our commitment that all projects meet a minimum return threshold. On the financial side, we returned 53% of the adjusted net cash provided by operating activities to shareholders through dividends and share repurchases in the second quarter. And we ended the second quarter with a net debt to capitalization ratio of 18%. Looking ahead, we expect low global light product inventories and tight product supply-and-demand balances to continue to support refining fundamentals. Global demand for transportation fuels has recovered substantially with gasoline and diesel demand now comparable to pre-pandemic levels and jet fuel demand continues to increase steadily. In closing, we remain committed to the core strategy that has been in place under Joe's leadership for nearly a decade. Our focus on operational excellence, capital discipline and honoring our commitment to shareholder returns have served us well and will continue to anchor our strategy going forward. So Homer, with that, I'll hand the call back to you.

Thanks, Lane. For the second quarter of 2023, net income attributable to Valero stockholders was $1.9 billion or $5.40 per share compared to $4.7 billion or $11.57 per share for the second quarter of 2022. Second quarter 2022 adjusted net income attributable to Valero stockholders was $4.6 billion or $11.36 per share. The Refining segment reported $2.4 billion of operating income for the second quarter of 2023 compared to $6.2 billion for the second quarter of 2022. Adjusted operating income was $6.1 billion for the second quarter of 2022. Refining throughput volumes in the second quarter of 2023 averaged 3 million barrels per day, implying a throughput capacity utilization of 94%. Refining cash operating expenses were $4.46 per barrel in the second quarter of 2023, lower than guidance of $4.60, primarily attributed to lower-than-expected natural gas prices. Renewable Diesel segment operating income was $440 million for the second quarter of 2023 compared to $152 million for the second quarter of 2022. Renewable Diesel sales volumes averaged 4.4 million gallons per day in the second quarter of 2023, which was 2.2 million gallons per day higher than the second quarter of 2022. The higher sales volumes in the second quarter of 2023 were due to the impact of additional volumes from the start-up of the DGD Port Arthur plant in the fourth quarter of 2022. The Ethanol segment reported $127 million of operating income for the second quarter of 2023 compared to $101 million for the second quarter of 2022. Adjusted operating income for the second quarter of 2022 was $79 million. Ethanol production volumes averaged 4.4 million gallons per day in the second quarter of 2023 which was 582,000 gallons per day higher than the second quarter of 2022. For the second quarter of 2023, G&A expenses were $209 million and net interest expense was $148 million. Depreciation and amortization expense was $669 million and income tax expense was $595 million for the second quarter of 2023. The effective tax rate was 22%. Net cash provided by operating activities was $1.5 billion in the second quarter of 2023. Excluding the unfavorable change in working capital of $1.2 billion in the second quarter, and the other joint venture member share of DGD's net cash provided by operating activities, excluding changes in its working capital, adjusted net cash provided by operating activities was $2.5 billion. Regarding investing activities, we made $458 million of capital investments in the second quarter of 2023, of which $382 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance; and $76 million was for growing the business. Excluding capital investments attributable to the other joint venture member share of DGD, capital investments attributable to Valero were $433 million in the second quarter of 2023. Moving to financing activities. We returned over $1.3 billion to our stockholders in the second quarter of 2023, of which $367 million was paid as dividends and $951 million was for the purchase of approximately 8.4 million shares of common stock resulting in a payout ratio of 53% of adjusted net cash provided by operating activities. Last week, we announced a quarterly cash dividend on common stock of $1.02 per share payable on September 5, 2023, to holders of record at the close of business on August 3, 2023. With respect to our balance sheet, we ended the quarter with $9 billion of total debt, $2.3 billion of finance lease obligations and $5.1 billion of cash and cash equivalents. The debt-to-capitalization ratio net of cash and cash equivalents was 18% as of June 30, 2023. And we ended the quarter well capitalized with $5.4 billion of available liquidity, excluding cash. Turning to guidance. We expect capital investments attributable to Valero for 2023 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts and joint venture investments. About $1.5 billion of that is allocated to sustaining the business and the balance to growth. For modeling our third quarter operations, we expect Refining throughput volumes to fall within the following ranges: Gulf Coast at 1.77 million to 1.82 million barrels per day; Mid Continent at 450,000 to 470,000 barrels per day; West Coast at 240,000 to 260,000 barrels per day; and North Atlantic at 435,000 to 455,000 barrels per day. We expect Refining cash operating expenses in the third quarter to be approximately $4.70 per barrel. With respect to the Renewable Diesel segment, we expect sales volumes to be approximately 1.2 billion gallons in 2023. Operating expenses in 2023 should be $0.49 per gallon, which includes $0.19 per gallon for noncash costs such as depreciation and amortization. Our Ethanol segment is expected to produce 4.4 million gallons per day in the third quarter. Operating expenses should average $0.39 per gallon, which includes $0.05 per gallon for noncash costs such as depreciation and amortization. For the third quarter, net interest expense should be about $145 million, and total depreciation and amortization expense should be approximately $690 million. For 2023, we expect G&A expenses, excluding corporate depreciation, to be approximately $925 million. That concludes our opening remarks. Before we open the call.

Today's first question is coming from Manav Gupta of UBS.

Guys, I just want to quickly start with and congratulate Gary for the promotion and the new role, and all our best wishes are with you. The first question I have for you is that when we look at DGD, you guys have a track record of bringing projects online before time. So is there a possibility a year down the line, you could take a look at it and say, we would like to have similar upgrades possible at DGD 1 and 2 to make more sustainable aviation fuel on a go-forward basis?

Yes. Manav, this is Eric. Obviously, that is a possibility because those are cookie-cutter units, and we could do the exact same project at St. Charles that we are currently underway at Port Arthur. It's too early to talk about any numbers or commitment, but yes, that's definitely something we're looking at and something that we could do.

The second question is regarding the DOE data, which indicates that there are some concerns about demand. However, the cracks suggest that the demand for products is exceptionally strong. Could you share your insights on the demand in different regions?

Yes, Manav, this is Gary. We do believe that the DOE is understating gasoline demand. But even their data is showing on a 4-week average basis gasoline demand up about 3%. But if you look at our numbers, of course, Lane mentioned we had record volumes in both May and June of over 1 million barrels a day. We're seeing gasoline sales in our system up 14% year-over-year, up 22% from pre-pandemic levels. Gasoline inventory year-over-year is down 7.5 million barrels. So it's trending at the low end of the 5-year average range. Typically, this time of year, you have an open arb to ship barrels from Europe into the United States. But with inventory low in Europe, that arb is closed, which is hindering imports, and we see strong export demand from the U.S. Gulf Coast into South America. So the fundamentals around gasoline look very good. Diesel inventory is up 6 million barrels, but continues to trend below the 5-year average range. Diesel inventory is flat, where historically, this time of year, we start to see diesel building. Again, while the DOE reflects weaker diesel demand year-over-year, it looks like the weekly data is continually being revised up. So although we certainly know that we had a weaker heating oil season, diesel demand looks fairly similar to last year. So we moved forward with a lot of encouraging signs around diesel where we saw a weaker tonnage index in the second quarter, the June data reflects that the tonnage index is picking back up. We'll start to see more agricultural demand as we get into harvest season and more heating oil demand as we get into colder weather. Continue to see very good export demand from the US Gulf Coast into South America. Some of that has fallen off as we've replaced some supply with Russian barrels, but largely been replaced with more export demand from the US Gulf Coast into Europe. Jet demand is also picking up, and had a positive impact on overall distillate supply-demand balances, so the distillate demand looks up 10% year-over-year. It looks pretty strong. All the airlines are reporting very strong demand. Jet trading at a $0.10 per gallon premium in the US Gulf Coast on a rent-adjusted basis today. So, yes, the fundamentals look very, very good.

Thank you so much for the detailed response. Thank you.

Thank you. The next question is coming from John Royall of JPMorgan. Please go ahead.

Hi. Good morning. Thanks for taking my question. So my first one was just on the coker. It sounds like you're running full now in the startup went as planned. But maybe you can just go through any puts and takes around profitability? I know heavy diffs have come in, for example, the diesel cracks are improving recently. Should we think about there being a structurally higher Gulf Coast capture now? And any way to think about quantifying that?

Hey John, this is Greg Bram. So as Lane mentioned, the Coker started up in April. And I think it's probably worth noting that the project and operating teams did a great job bringing that unit online safely without incident. And that's after we accelerated the schedule last year to be in a position to capture value from that project here in 2023. We've ramped it up to full capacity over the course of the quarter, and it's running well and meeting expectations. And I think with that, you can take kind of the guidance we've given in the past and think about where the market is today and adjust accordingly. I don't think we have really a new or different view, because the project is really doing what we expected it to do.

Great. And then maybe along the same lines, it would be great to get your thoughts on heavy and medium sour diffs from here with OPEC+ cutting and the second round of the STR release is now over. What are your thoughts on whether we'll see a widening from here on mediums and heavies or will we likely stay in the current environment from a sour diffs perspective?

Yes, this is Gary. I think we have seen the discounts widen back out some as we've moved throughout the third quarter. I think there's some reason for optimism as we head into fall turnaround season, had two and three, you'll see some decreased demand for heavy sour crude, which will help the differential some. I think we'll see some more production growth out of Western Canada as they come out of maintenance season, which would put more barrels back on the market, should continue to see a ramp-up in Chevron production from Venezuela heading into the US Gulf Coast. And then finally, there's some seasonal factors which should help the discounts as well. High sulfur fuel oil for power burn will begin to wind down seasonally, which will put more high sulfur fuel on the market, help the discounts there. And then as we transition into winter weather, you would expect to see higher natural gas prices, which changes the economics for some refineries around the world that have been processing medium and heavy sour crude, which have helped the discounts as well.

Thank you.

Thank you. The next question is coming from Theresa Chen of Barclays. Please go ahead.

Good morning. On the SAF front, would you mind giving an update on the Navigator BlackRock CCS project? And how is the permitting and right-of-way procurement process going?

Hi Theresa, it's Rich. I'll start by saying that the Navigator project is making progress. They have parallel processes in front of each state's utility boards and counties, and the regulatory proceedings in Iowa are taking longer than expected. As a result, Navigator does not anticipate receiving regulatory approval until the latter half of 2024, which will naturally delay their timeline. They have not provided any updates on a revised start-up schedule.

Thank you. And in terms of additional SAF opportunities in the DGD facilities, Eric, can you just opine a bit more on how would you think about like the key hurdles it would take to cross to commercialize additional FID?

I believe that airlines are currently in an educational phase regarding sustainable aviation fuel (SAF). They have a solid understanding that it will come from renewable sources and are becoming more familiar with how credit markets operate. However, many SAF mandates are voluntary, which gives airlines options about accepting allocations and choosing models to implement. The challenge is that conventional jet fuel is fungible, so SAF will enter similar markets, just like jet fuel. Nonetheless, airlines may want specific types of SAF at particular locations, which complicates matters. This leads to discussions on how to manage logistics and establish commercial agreements. A lot of details are still being worked out regarding how SAF will enter the market and its pricing. Despite this, interest and demand from airlines remain strong, with expectations for continued growth through 2030. There is significant potential in this area, but it requires resolving various commercial and logistical issues.

Thank you.

Thank you. The next question is coming from Doug Leggate of Bank of America. Please go ahead.

Thanks. Good morning everybody. Gary, perhaps I could pick on you a little bit given your recent good news. Congrats from me as well. But diesel, a couple of months ago, the world was coming to an end in terms of consensus expectations. And today, we're back at winter-type premiums for distillate cracks. So, I know you touched on it already in some of your comments. But can you maybe speak to what you're seeing that's driving that strength? And I want to address specifically what you're seeing in Asia as it relates to trading. Our understanding is Chinese exports are down and maybe that's creating some globally. So, I'm just wondering if you can offer any perspective as to why the split is as strong as it is today?

Yes, as China increased production without domestic demand keeping pace initially, we observed a significant rise in Chinese exports, some of which were directed to Europe. Additionally, there were trade adjustments that needed to occur due to Russian sanctions. Initially, we experienced a drop in demand from Latin America, leading to a surplus of diesel in the U.S. However, as trade dynamics rebalanced, Russian barrels started to flow into Latin America, and this gap was largely filled by a rise in demand from Europe. Comparing our export volumes, in the second quarter of last year, 95% of our exports went to Latin America and 5% to Europe. In contrast, this year, 60% of our exports went to Latin America while 40% went to Europe. We are witnessing a strong demand for diesel from the U.S. Gulf Coast into Europe, which we expect to continue through the second and third quarters. This shift is a significant change.

I hope this isn't a second question, but rather a clarification. Are you indicating that Russian exports are beginning to slow, which I understand was the expectation? Am I interpreting your comments correctly?

We have seen Russian exports slow, I don't know, if that's just maintenance activity occurring in Russia, what's driving it. But we have seen some of the South American demand that we feel like we lost the Russian barrels that those countries are back inquiring for supply from us again.

Thank you. My follow-up is on capture rates. It appears that Refining was consistent with consensus for this quarter, but there was notably weak capture in the Mid-Con and North Atlantic regions. Could you explain whether this is a temporary issue, if there were any specific factors affecting the quarter, and how you anticipate it will trend in the third quarter? Thank you.

Yeah, Doug, this is Greg. So as you mentioned, overall capture rates were pretty consistent with what we'd expect from a 1Q to 2Q move. I should mention from the earlier question. In the Gulf Coast, the Coker was a positive impact, the new Coker on capture rates in the Gulf. As you mentioned in the Mid-Con, lower there primarily due to turnaround activity and you can see that in our lower throughput rates in the second quarter versus the first quarter. And then in the North Atlantic, we tend to always see a seasonal shift in the value of Canadian distillates up in that market strong in the winter and then coming off in the spring and summer time. So that was one of the effects we saw there. Then the one that was a bit more unique to this particular period was just higher cost for sweet crude coming out of Canada, primarily impacted by some maintenance and also the wildfires they had up there.

And how is that trending in Q3?

Yeah, we're starting to see it moderate a bit, but it will take some time. That usually is not just a very short-term effect, but we expect that it will start to improve.

All right. Thank you, guys.

Thanks.

Thank you. The next question is coming from Paul Sankey of Sankey Research. Please go ahead.

Good morning, everyone.

Good morning, Paul.

My congratulations to Gary. Can you just keep going a little bit with the outages? On the OPEC cuts, can you talk a little bit about the impact that you've been having on markets from your perspective? The Mexican explosion was another obvious one, just a commentary on how disruptive the crude market is from a buyer's point of view right now? And I got you on Russia you seem to more or less address that already through Doug. Thanks.

Yeah. So certainly, the big move in the crude market has been the OPEC+ production cuts, 4.5 million barrels a day off the market. And I think you're seeing that as global oil demand picks up, and those barrels are not yet back on the market, you're seeing flat price trend higher, and you've definitely seen it in the quality differentials as well. But in addition to the OPEC+ cuts, there were a number of other issues that you mentioned. We had maintenance in Canada on the wildfires in Canada, the platform fire in Mexico. You kind of went from a seller out of the SPR to a buyer into the SPR. So all of those things had a significant impact on the quality differentials in the second quarter, and we're seeing some of those things start to reverse as we move into the third quarter.

Got it. Can you discuss the outages in Refining? There were reports of various issues, particularly due to the heat in Texas. Could you share what happened during the quarter and how these factors may have affected the industry's throughput with several units being down?

Paul, this is Greg. I don't know that we can speak a whole lot to what was going on elsewhere. Our operations were very good for the quarter. Good mechanical availability in line with kind of our typical first quartile type of performance. So the weather has had just a very modest impact on any of our operations.

Got it. And finally, the 14% increase in wholesale indicates that you're gaining market share, which seems to be primarily driven by your renewable fuels. How do we account for the disparity between your strong sales and the overall market performance being significantly lower?

No. That wouldn't include really what we're talking about on renewables. That would be strictly our U.S. wholesale volumes. I think some of it was due to rationalization that occurred in the industry that allowed us to be more competitive, but we've gone through and in many locations, renegotiated terminal agreements that just allow us to be more competitive in some regions where we haven't been historically and capture additional market share.

Got it. Thanks very much.

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

Thanks. I have a question regarding the renewable diesel sector. Can you discuss the strong performance we saw this quarter? Sales exceeded our expectations, and the capture rate improved significantly. There seems to be some benefits from pricing as well. What are the key drivers behind the sales? As we approach the latter half of this year, what should we expect in terms of sales and margins for renewable diesel?

Yes, we definitely experienced some timing with shipments in our quarterly numbers, but we are also operating above our original design capacity. We're running at higher rates at DGD 3 and seeing strong sales globally as we expand production into Canada with its new CFR that launched in July, along with other states coming online beyond California. Overall, we did see increased sales due to the combination of shipment timing and our higher operational rates.

And on the margin cap just had. Any general comments on what you're seeing, I mean, headline indicators have been falling, but your capture was much improved.

Yes. We definitely saw lower prices in the second quarter, particularly on the margin capture side. Waste oils have become more advantageous, improving our capture rate. Regarding RINs and LCFS, those have met our expectations. The LCF market has been relatively stable, and the EPA’s new RIN outlook was mostly unchanged. Overall, that's primarily a product-related issue. Gary mentioned strong ULSD demand, which is the foundation of the formula, along with more attractive fat prices, as noted earlier.

And maybe on a different note, with the start-up of the Port Arthur Coker and the capital rolling off from that in terms of growth CapEx, you obviously have the SAF projects underway, but what types of projects might compete for growth capital going forward? Is it more likely to be incremental SAF capacity? Are there things on the refining side that you're looking at, whether it's something to increase octane production or anything like that on the margin side that can compete for capital as you think about the next couple of years?

Yes. This is Lane. So you can really expect us to continue to look to optimize and look at opportunities around our existing assets. We've been doing that. Some of them aren't big or flashy, but in cumulative, they'll have an effect on our overall performance, and we continue to gate those, just like we always have. And then in the other side of the business, our renewable side. We are looking at the potential to always gain and develop innovative projects that are sort of in the transportation fuel space that leverage our operations excellence and our project execution capabilities.

Okay. Thanks, Lane.

Thank you. The next question is coming from Joe Laetsch of Morgan Stanley. Please go ahead.

Great. Thanks everybody for taking my questions today. So I want to go back to capture rate here. So, we noticed just on the West Coast refining margins were really strong during the quarter. Could you just touch on some of the drivers here and how we should think about the setup for the third quarter?

Yes, this is Greg. So on the West Coast, we had great operations out there. But really, the thing to note there is Benicia has a very, very high gasoline yield in terms of its product mix. So, when gasoline is very strong relative to distillate products out in the West Coast, we see strong capture rates out there driven by Benicia's yield. That's the primary factor you saw in the second quarter.

Thanks, that's helpful. My second question is about operating expenses and what caused the increase in the third quarter compared to the second quarter. Is that related to the gas side? How should we understand that?

Let me clarify, this is Lane. The increase is primarily due to a slightly improved outlook for natural gas in the third quarter compared to the second quarter.

Perfect. Thank you.

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

Good morning and congrats to everybody on their new roles here. I'd like to hit the diesel question a slightly different way. Last winter, we saw pretty unusually warm weather throughout Northern Hemisphere. So going back, I think you addressed this on the last call, but what do you think the missing demand was last year from a weather standpoint. And so when we think about the upcoming winter and we always just model normal weather. So, what will we potentially be looking at from a demand step up?

Roger, we have modeled that, but I don't have the number in front of me, and I don't want to give you a bad number, but we can follow up with you with Homer and get you the number we had on heating oil demand.

Okay. That's helpful. The other is, we have, I think somebody mentioned earlier, seeing diesel move back up over gasoline. Can you give us an idea of how you've run in terms of being max diesel or I should say, max distillate or max gasoline as we've been coming through this summer?

Roger, we've been mostly in max gasoline mode, but we've been watching that movement between those two products. And we'll make that shift when we start to see that kind of swing cut drive us back the other way. One of the things maybe just to keep in mind is on that swing cut, as you keep that heavier part of the gasoline and the gasoline pool, it pulls in more butane into the blend pool. And when you look at where butane prices are currently that's really attractive to get as much butane in the blend as you can.

Yes, NGLs are definitely help in or hurt depending on which side of the argument you're on there. Okay. Thanks, guys.

Thanks.

Thank you. The next question is coming from Paul Cheng of Scotiabank. Please go ahead.

Hi. Good morning.

Good morning, Paul.

Congratulations to everyone on the new role. I apologize for joining late, so if my question has already been addressed, please let me know and I can refer to the transcript. I have two questions. First, with the heavy oil discount and the decrease in medium sour, it doesn’t seem particularly attractive right now. Is it a challenge for you to process those barrels? If not, is there a way for you to further reduce the volume, and what is the minimum you need to run? My second question is regarding the law of Avantec. Is there a specific reason why margins dropped significantly in the second quarter? I am not just comparing it to the first quarter but also to the past couple of years where you were running at around 100%, 95%, to maybe 120%. Is there a particular cause for this, or are there any unique circumstances we should be aware of? Thank you.

Hey, Paul, Mr. Bram is going to answer that.

Hey, Paul, I'll start with the first one on the different crudes. If I understood your question, we see incentive to run both heavy grades and light grades now. The advantage for heavy crudes has narrowed quite a bit as we progressed into the quarter. As Gary mentioned, if those differentials start to widen again, it will increase the incentive to continue processing heavy grades. The medium sours have probably been the least attractive, and we would need to see them have a wider discount to the light sweet grade before we consider making a shift there. Regarding your question about the capture rate.

Actually, before we go into the capture, can I ask how much that you can maybe further minimize on the medium sour?

Yes, we can minimize quite a bit. Paul, one thing to keep in mind is there's different parts of the country, different parts of even the Gulf Coast region, where the medium sours, particular grades, will still be attractive to run. And we'll process those in the places where that medium grade is not as attractive. The easiest way to think about it is, in a lot of cases, we can run a combination of heavy and light to essentially kind of mirror what a medium grade looks like, but do that at a lower cost than buying the medium sour crude itself.

Okay. Understood.

Okay. The your capture rate – was around north Atlantic,

Around North Atlantic. Yes.

Yes, Paul, primarily the one thing that was unique about the second quarter was the higher crude cost and again, driven by higher prices for Syncrude out of Canada, both maintenance and wildfire-related. That was probably the thing that caused kind of that region to look different this quarter than it would typically for a second-quarter period.

The Syncrude was probably at 100% or at most 20% for your entire input, correct?

No, it's much higher than that, Paul.

Okay. Great. Thanks a lot.

Thank you. The next question is coming from Nitin Kumar of Mizuho Securities. Please go ahead.

Hi. Good morning all and thanks for taking my question. I just want to start with, can you comment on the recent EPA decision to deny RFS favors for small refiners? And how does that look for your ethanol business? I think you mentioned volumes were flat, but can you talk a little bit about pricing for ethanol?

This is Rich Walsh. I can talk of, I guess, a little bit about the EPA decision. And then when it comes to pricing, I'll hand it back off to Eric. I mean, we don't have any small refinery exemptions in play. And so it's a bit of a non-factor for us. I mean really not a lot more to share on it in that regard.

We see a similar situation regarding the commercial impact, but it doesn't seem to be significant. We are uncertain about the compliance status of the small refiners, so we do not anticipate any major effect on our businesses related to the small refinery issue.

Sorry, what I was actually referring to is on your commercial side, whether you were seeing any improved demand for ethanol because those that don't have the exemption. I guess I'll ask a different question as well. Just on the sustaining CapEx, you mentioned $1.5 billion for this year. Are you seeing anything on the regulatory front that could increase that or increase the intensity of your sustaining CapEx in the future thinking of things like stringent particle emission standards or anything like that?

This is Lane. When you look at our history on our sustaining capital and some of these things, we were actually ahead of our competitors looking at elective gas recovery and some of these other things. So with respect to regulatory capital, we're in good shape, and we're still willing to stick with our $1.5 billion of sustaining. On average, that doesn't mean it can ebb and flow really with turnaround timing.

Thank you.

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

Yeah. Good morning, team, and Lane, Gary, and Joe, if you're on the line. Congratulations to each of you. And that's kind of where I want to start. I mean, Lane, that over the last couple of years, the strategic vision has been very clear and consistent. We would just love your perspective as you step into this new role. What are the two or three things that you're most focused on to take Valero to the next level?

Thank you, Neil. Joe and I have collaborated on our strategy for the past nine years, and I have a long-standing relationship with Jill as well. I have been part of the successful current strategy, and I don’t expect us to make significant changes to our strategic focus. My primary concern is ensuring everyone is aligned on this. We have been very effective in executing our operations and maintaining excellence, and I want to ensure that continues. We need to remain disciplined and predictable, which are crucial factors for our future. I'll let Joe continue to explore innovative projects and identify opportunities to invest our strategic capital in areas related to our assets, like Diamond Green or SAF, where we have already outpaced competitors and believe we can maintain that advantage.

Thanks, Lane. And then the follow-up is just around return of capital. And just maybe you could provide an update. It was another quarter where you were able to return cash in excess of sort of the brackets that you talked about historically. And how are you thinking about with the stock having done well here recently, continuing to lean into the buyback versus reinvest back in the business and talking about the dividend as well.

Yes, I believe we will maintain our strong approach to capital and continue with our buybacks and dividends strategy. Historically, prior to the pandemic, we often reached or exceeded our long-term target of returning 40% to 50% to shareholders. Last year, we returned to the 45% midpoint of our range, while also reducing our debt to prepayment levels and increasing our cash reserves. We feel we've positioned ourselves well and plan to operate at this midpoint or higher going forward. In the second quarter, we exceeded our 50% target, achieving a payout of 53%. So far this year, we've averaged a 52% payout, showing a clear trend above 50%. Moving ahead, we won't hesitate to exceed the upper end of our range if we believe it's the best use of excess cash. Regarding dividends, we want them to remain competitive against our peers, focusing on growth and sustainability throughout the business cycle. This will be our approach moving forward, with buybacks complementing our strategy to meet our targets.

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

Yeah. Hey, thanks for taking my questions. First, I want to ask on the renewable fuel standard as well and the outlook for RIN prices and the impact of the business, there's a decent amount of concern that there's going to be an oversupply of RINs next year, and that has implications both for Diamond Green Diesel as well as on refining and the ability to capture some of the pass-through of the RIN cost in the crack. So I was wondering, if you have any comments around your RIN outlook as it relates to impacts to both of those segments given some risk to RIN prices moving lower next year? And I have a follow-up. Thanks.

Yeah, this is Eric. On the RIN prices, the EPA held the ethanol requirement of 15 billion gallons, which as we've seen over the last several years, it's beyond the blend wall, which means the D4 RIN will be used to fulfill that obligation. Given our outlook, we don't see a big change in RINs. RIN prices or RIN supply you see that as relatively business as usual.

I mean, I guess if I could just push back a little bit. There is a lot of new renewable diesel capacity coming online next year. So it does seem like there's going to be a lot more RIN supply. I don't know if that enters into your thought process as you look out next year?

Yes. We won't comment on other companies' projects, but we have observed that many of the R&D initiatives are taking longer to develop and are experiencing delays. Therefore, we anticipate that the growth trajectory of R&D will not be as pronounced as many forecasts suggest.

I appreciate that. My follow-up is regarding the outlook on cracks, as many investors seem surprised by their strength. Firstly, do you think the hotter-than-normal weather globally has had any impact on diesel demand? I know you mentioned you wouldn't comment on your peers' refining operations in warm weather, but I'm curious if there has been any demand effect from high temperatures. Secondly, can you discuss the rebuilding of low product inventories? Given that global capacity is running at full tilt, how does the world go about restocking gasoline and diesel, which are currently at or below historical levels? Thank you.

Yes, Jason, this is Gary. I don't think we've seen a significant change in diesel demand due to warmer weather. Where inventories are low in the United States, we're experiencing the same trend globally. The low diesel inventories and demand from the United States, particularly towards Europe, are quite high due to low inventory levels worldwide. Looking ahead, it's unclear how we will manage to restock the inventory. Currently, we are 35 million barrels below the five-year average, just like we were at this time last year. So we haven't made much progress in addressing this issue. Although there's no new refined capacity being introduced, when we examine the stated nameplate capacity of new refinings and the estimates for global oil demand growth, it appears that there won't be a significant impact on the supply-demand balance moving forward.

Great. Thanks for the color.

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

Hi, good morning. Thanks for taking my questions. Do you have any thoughts on the expected impact on RD margins in 2025 when the BTC converts to a PTC? As we look at it, it appears the dollar per gallon subsidy would go down with the PTC, but then, it seems like you might be helped out by just less competition from foreign RD imports. Does that make sense on your end? And is there anything else you would add there?

Yes, I think you've got that surrounded. The one thing I would add is when you go to a carbon intensity basis for the PTC, that will advantage Diamond Green Diesel because we run the lowest CI feedstocks. So whatever the PTC becomes, we will still have the highest capture of PTC versus our peers. So there's no doubt that it becomes a fraction of $1 based on CI but we'll still have the most advantaged platform.

Thank you. Regarding the ethanol side, is the alcohol-to-jet SAF project still a long-term option? If it is, could you compare it to what you're currently doing at DGD? How do the two production methods compare in terms of capital costs, operational costs, and scale? Do airlines differentiate between these two types of fuel?

Yes, I think there are a lot of questions there. What I can say is that there is indeed a pathway for converting ethanol into jet fuel, particularly after sequestration, which makes ethanol a viable feedstock for that market. However, it's too early to discuss specific numbers or capital from a project perspective. From the airline's viewpoint, they expect that the first barrel of sustainable aviation fuel (SAF) they receive will be predominantly renewable diesel (RD) based. As the conversion process progresses in the RD markets, the subsequent barrel could potentially come from an ethanol source. However, this is further out on the timeline. Additionally, while the technology exists and airlines may differentiate between the two types of fuel, it is probably too soon to determine that. From a fuel perspective, there's no difference between an ethanol-based barrel and an RD-based barrel from the SAF standpoint. Nonetheless, significant work remains on how RD will affect SAF pricing in the market, and these developments are much further down the timeline.

Understood. Thanks for your comments.

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

Thanks, Donna. I appreciate everyone joining us today, and please feel free to contact the IR team if you have any follow-up questions. Have a great day. Thanks, everyone.

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