Q2 2025 Earnings Call Transcript

Greetings, and welcome to Valero Energy Corp.'s Second Quarter 2025 Earnings Conference Call. [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.

Good morning, everyone, and welcome to Valero Energy Corporation's Second Quarter 2025 Earnings Conference Call. With me today are Lane Riggs, our Chairman, CEO and President; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and COO; Rich Walsh, our Executive Vice President and General Counsel; and several other members of Valero's senior management team. If you've not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted financial metrics mentioned on this call.

If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our earnings release and filings with the SEC.

Now I'll turn the call over to Lane for opening remarks.

Thank you, Homer, and good morning, everyone. We are pleased to report solid financial results for the second quarter, driven by our strong operational and commercial execution. In fact, we set a record for refining throughput rate in our U.S. Gulf Coast region in the second quarter, demonstrating the benefits of our investments in growth and optimization projects.

Refining margins were supported by strong product demand against the backdrop of low product inventory globally. In particular, early July U.S. diesel inventories and days of supply are at the lowest level for the month in almost 30 years. We continue to see strong demand with our quarterly diesel sales volumes up approximately 10% over the same period last year and gasoline sales about the same as last year. On the financial side, we continue to honor our commitment to shareholder returns with a payout ratio of 52% in the second quarter.

And last week, we announced a quarterly cash dividend on our common stock of $1.13 per share. On the strategic front, we continue to progress the FCC unit optimization project at St. Charles that will enable the refinery to increase the yield of high-value products, including high-octane alkylate. The project is expected to cost $230 million in startup in 2026. Looking ahead, we remain optimistic on refining fundamentals with several planned refinery closures this year and limited announced capacity additions beyond 2025. Additionally, we expect our sour crude oil differentials to widen as OPEC+ and Canada continue to increase production during the third and fourth quarters.

In closing, we remain committed to maintain our track record of commercial and operational excellence, which has been the hallmark of our strategy for over a decade. And our commitment remains underpinned by a strong balance sheet that also provides us plenty of financial flexibility. So with that, Homer, I'll hand the call back to you.

Thanks, Lane. For the second quarter of 2025, net income attributable to Valero stockholders was $714 million or $2.28 per share compared to $880 million or $2.71 per share for the second quarter of 2024. The Refining segment reported $1.3 billion of operating income for the second quarter of 2025 compared to $1.2 billion for the second quarter of 2024. Refining throughput volumes in the second quarter of 2025 averaged 2.9 million barrels per day or 92% throughput capacity utilization. Refining cash operating expenses were $4.91 per barrel in the second quarter of 2025. The Renewable Diesel segment reported an operating loss of $79 million for the second quarter of 2025 compared to operating income of $112 million for the second quarter of 2024. Renewable diesel sales volumes averaged 2.7 million gallons per day in the second quarter of 2025. The Ethanol segment reported $54 million of operating income for the second quarter of 2025 compared to $105 million for the second quarter of 2024. Ethanol production volumes averaged 4.6 million gallons per day in the second quarter of 2025. For the second quarter of 2025, G&A expenses were $220 million, net interest expense was $141 million and income tax expense was $279 million.

Depreciation and amortization expense was $814 million, which includes approximately $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia Refinery by the end of April 2026. Net cash provided by operating activities was $936 million in the second quarter of 2025. Included in this amount was a $325 million unfavorable impact from working capital and $86 million of adjusted net cash used in operating activities associated with the other joint venture member's share of DGD. Excluding these items, adjusted net cash provided by operating activities was $1.3 billion in the second quarter of 2025. Regarding investing activities, we made $407 million of capital investments in the second quarter of 2025, of which $371 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 members' share of DGD and other variable interest entities, capital investments attributable to Valero were $399 million in the second quarter of 2025. Moving to financing activities. We returned $695 million to our stockholders in the second quarter of 2025, of which $354 million was paid as dividends and $341 million was for the purchase of approximately 2.6 million shares of common stock, resulting in a payout ratio of 52% for the quarter. Year-to-date, we have returned over $1.3 billion through dividends and stock buybacks for a payout ratio of 60%.

And as Lane mentioned, on July 17, we announced a quarterly cash dividend on common stock of $1.13 per share. With respect to our balance sheet, we repaid the outstanding principal balance of $251 million of 2.85% senior notes that matured in April. We ended the quarter with $8.4 billion of total debt, $2.3 billion of total finance lease obligations and $4.5 billion of cash and cash equivalents. The debt-to-capitalization ratio net of cash and cash equivalents was 19% as of June 30, 2025. 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 2025 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. For modeling our third quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.76 million to 1.81 million barrels per day; Mid-Continent at 430,000 to 450,000 barrels per day; West Coast at 240,000 to 260,000 barrels per day; and North Atlantic at 465,000 to 485,000 barrels per day.

We expect refining cash operating expenses in the third quarter to be approximately $4.80 per barrel. With respect to the Renewable Diesel segment, we still expect sales volumes to be approximately 1.1 billion gallons in 2025, reflecting lower production volumes due to economics. Operating expenses in 2025 should be $0.53 per gallon, which includes $0.24 per gallon for noncash costs such as depreciation and amortization. Our Ethanol segment is expected to produce 4.6 million gallons per day in the third quarter.

Operating expenses should average $0.40 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 $135 million. Total depreciation and amortization expense in the third quarter should be approximately $810 million, which includes approximately $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia Refinery by the end of April 2026. We expect this incremental depreciation related to the Benicia Refinery to be included in D&A for the next 3 quarters, resulting in a quarterly earnings impact of approximately $0.25 per share based on current shares outstanding.

For 2025, we still expect G&A expenses to be approximately $985 million. That concludes our opening remarks. [Operator Instructions].

[Operator Instructions] Our first question is coming from Theresa Chen of Barclays.

Now that we are halfway through the summer driving season, how is refined product demand trending across your footprint? Maybe just unpack some of Lane's opening remarks about sales across your system. Are there any noticeable patterns or shifts? And additionally, what kind of signals are you observing in the export market?

Theresa, it's Gary. Overall, I'd tell you the fundamentals around refining continue to look very supportive. Total light product inventory remains below the 5-year average range, below where we were last year at this time. And demand for transportation fuels remains robust, not only here in the U.S., but also in our typical export markets.

Our view is gasoline demand relatively flat to last year. It looks like vehicle miles traveled are up slightly year-over-year, but probably only up enough to offset efficiency gains in the automotive fleet, not up enough to really create incremental demand. If you look at our wholesale volumes, they would also indicate flat year-over-year gasoline demand. In addition to relatively strong gasoline demand domestically, we've also seen good export demand to Latin America.

And then on the supply side, the transatlantic arb to ship gasoline from Europe to the United States has been closed for much of the year. So when you combine relatively good demand with less supply coming from Europe, you would kind of expect inventory to be a little lower than last year, and that's what we saw in the second quarter. So those factors ultimately resulted in a little stronger gasoline margin environment this year compared to last. Going forward, the transatlantic arb is marginally open.

So supply seems adequate to meet demand. We're kind of getting to the end of driving season. We'll start RVP transition in some regions soon. So it's hard to see a lot of support for gasoline cracks moving forward.

Absent some type of supply disruption, we'd kind of expect gasoline cracks to follow typical season patterns, remain around mid-cycle levels through the end of the year. Distillate, the story is much different, though, where gasoline demand is expected to fall off some, we expect distillate demand to pick up. First, we'll start to get into harvest season, see agricultural demand pick up, and then we'll transition to heating oil season. Overall, diesel demand has continued to trend above last year's level, really strong demand in the first quarter due to colder weather and then increased demand for refinery-produced diesel with less imports of bio and renewable diesel.

In our system, diesel sales are currently trending about 3% above last year's level. Again, while domestic demand has been good, we see a strong pull of U.S. Gulf Coast distillate into the export markets. The export really have kept inventory down near historical lows during a time where restocking typically occurs.

We have seen diesel inventory gain in the last couple of weeks, but really, that's just a result of an incredibly strong export market in early June. As exports got really strong, freight rates spiked, and so it closed some of those export arbs. Freight rates have come back off, so the arbs are open to export both to Latin America and Europe. With those arbs open, it's difficult to see how we get the normal build in diesel inventory that occurs in the third quarter.

So diesel cracks have been strong with low inventory. We expect diesel cracks to remain strong heading into hurricane season, if we have some type of supply disruption, I think you'll see a pretty significant market reaction with inventories as low as they are.

And what is your near to medium-term outlook for light-heavy differentials, taking into account the tailwind from incremental OPEC+ barrels coming to market, but also considering potential headwinds from AMEX production volatility, the unavailability of Venezuelan barrels, GOM crude quality issues and so on. How do you think these factors play out?

Yes. Thus far, year-to-date, I think the quality differentials have certainly been a headwind for us. We thought coming into the year, you'd see less demand with Lyondell going down, but that was kind of offset. The Venezuelan sanctions pulled about 200,000 barrels a day out of the U.S.

Gulf Coast market. You had the wildfires that took about 5 million barrels of June supply off the market. But going forward, we do think things will get better. It will probably be the fourth quarter before you really see that.

Canadian production has not only recovered from the wildfires, but it continues to grow. Then as you mentioned, OPEC unwinding their 1.9 million barrels a day of cuts by August. Really, it appears that much of the ramp-up in the OPEC production we haven't seen on the market yet so far because there was crude oil burn in the region for seasonal power demand. As we move out of summer, more of those barrels will make their way to the market.

And then early summer tensions in the Middle East also caused some countries to front-end load fuel oil purchases that they use for power demand also. Again, that will unwind fuel oil coming back off to the market. As fuel oil comes back, that will support wider differentials as well. Additionally, in the fourth quarter with turnaround activity, you should see less demand for those barrels.

So all of those should really contribute to wider differentials in the fourth quarter. I think the only unknown here is really what happens with the Russian sanctions. Thus far, we haven't really seen much of an impact. But if the sanctions are effective and cut some of the Russian barrels, that would obviously be bearish the differentials.

The next question is coming from Manav Gupta of UBS.

Team, just wanted to understand what's your outlook for the net capacity additions for the remaining part of this year and for 2026. Are you still seeing major capacity additions globally? Or do you think those things are slowing down and given the demand growth, we should be better positioned going ahead, if you could talk about that?

Yes, Manav, this is Gary. I think definitely, when we look out on the horizon, there's not a lot of new capacity coming online and a lot of what new capacity there is, is really more geared towards petrochemical production rather than making transportation fuels. If we look at next year, it looks like just over 400,000 barrels a day of new refining capacity coming online. Initially, most consultants were forecasting around 800,000 barrels a day of total light product demand growth, which would have indicated significant tightening starting next year.

With some of the economic uncertainty, especially around tariffs, forecasts have fallen off to where a lot of people are only forecasting around 400,000 barrels a day total light product demand growth. And then a lot of consultants are showing a lot of that demand growth being filled by a step change in renewable production. I'm confident we'll see tighter supply-demand balances. The question really is when does this occur?

Is it next year? Or do we actually see some type of economic activity slowdown, and it isn't until 2027 that things really start to get tight. Thus far, our view is the economy has been fairly resilient. Demand for transportation fuels has remained strong.

So I guess I'm a little more optimistic about the economy, and we'll have to see with all the uncertainty on renewables, whether we see a ramp-up in renewable production or not. The other big factor in all this is will we see additional refinery rationalization. Although some refinery closures have been announced, certainly, the recent announcement around the Lindsey Refinery in the U.K. was fairly unexpected. Hard to believe there aren't others facing a similar situation with other refinery closures, too, things could really tighten up a lot faster.

But the big driver here is really what happens to the economy, and you're probably in a better position to assess that than I am.

A quick follow-up is I was looking at your Gulf Coast capture. Now that's where heavy light narrowness should hit the capture the hardest, but the capture actually was over 92%. And I'm trying to understand a few dynamics, what allow you to deliver such a strong capture. And then coming back to the first question, if heavy lights do widen out, should we expect a tailwind to the Gulf Coast capture because the way your benchmark is constructed, those do not get reflected in the benchmark.

So if you could talk about that.

Yes, Manav, this is Greg. So I think you hit on some of the points related to heavy light and capture because we do include heavy grades in our reference for the Gulf Coast. So as those move out and contract, that's picked up in the reference crack that we use. So not as big of an impact on the capture rate because it's built into the indicator margin that we use.

On our performance in the second quarter, a lot of the improvement was driven by really strong operating performance coming out of the heavy maintenance we had in the first quarter. And that was really highlighted, if you remember, by Lane's comment about record quarterly throughput in that region. So good operating performance. We had strong commercial performance as well in that region, particularly on the product side, good exports, great wholesale performance in that part of our business as well.

So those were the primary drivers for the Gulf Coast in the second quarter. And again, as those crude differentials widen out, to the extent that they're in the indicator that we use, probably not as much of a factor when you think about the capture rate relative to our indicator.

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

I want to spend some time on the return of capital. You returned $633 million in the first quarter -- or second quarter with a payout of north of 70%. So just your perspective on the sustainability of capital returns and how we should be thinking about the buyback in the back half of the year?

Yes, Neil, it's Homer. I mean maybe I'll just start with just the framework around buybacks, right? It's guided by a number of things. Obviously, first and foremost, we've got our stated minimum commitment to an annual payout of 40% to 50% of adjusted cash flow, right?

And so you should continue to consider that as nondiscretionary. We'll honor that in any sort of environment. Then we've got our target minimum cash position of $4 billion to $5 billion, and we're right at the midpoint there. So we're not looking to build more cash, right?

And -- as a result of that, consistent with what we've been saying for quite some time, we'll continue to use all excess free cash flow to buy back shares. And as you highlighted, the second quarter resulted in a payout of 52%. Keep in mind, though, that we also used $251 million towards the notes that matured in April in addition to $325 million that was consumed by working capital, right? So looking forward, with the balance sheet where it is and discipline around capital investments, I think you can continue to expect us to maintain this posture where all excess free cash is aimed at share buybacks.

Longer term, I mean, I don't know if you have the investor deck handy, but we've got a slide in there. I think it's Slide 11 that puts all of this into context, actually reflecting our actual results. So if you look at the last 10-year period through 2024, total cash flow from operations was around $61 billion, and that includes changes in working capital, which is roughly $6 billion a year. If you think about run rate CapEx, right, $2 billion to $2.5 billion, so $2.25 billion at the midpoint with $1.5 billion sustaining and then $500 million to $1 billion of growth.

And layer on top, you've got $1.4 billion or so to fund the dividend, right? So $6 billion of annual cash flow from operations, $2.5 billion CapEx, $1.4 billion to dividend, that leaves over $2.3 billion for buybacks based on our actual results over the past 10 years. Hopefully, that gives you some context.

Really helpful, Homer. Just the follow-up is around DGD. Obviously, a lot of moving pieces and appears to be pretty tough, if not trough conditions. What's the path back to mid-cycle here? How do you think about the evolution of this business? And can you talk about your commitment to it?

Neil, this is Eric. I think you've already said that it's in a lot of policy clarity, vagueness right now. I think you can see really the linchpin in all of this is going to be what the EPA says post their comment period, that are due by August 8. And so what they do in terms of setting the RVO and what they do in terms of SREs and if and any reallocations will set the D4 RIN market and then consequently, hopefully set how the rest of the other markets will react versus the D4 RIN. So I mean, we see the LCFS market in California is slowly moving up after they passed their 9% obligation increase effective July 1. We see that a lot -- Europe continues to support its mandate for the 2% SAF requirement.

We see the CFR in Canada is going to continue to go forward. So long-term, there's still enough tailwind out there that says this segment will continue to be in demand. It's really just a question of when we see these credit prices start to move. You're starting to see the D4 RIN move up.

You're starting to see it separate from the D6. The big question is going to be when you see fat prices adjust to these policies once these policies are clarified. And so once those fat prices start to disconnect, then I think you'll see the margins open up for DGD. And you'll see more demand for DGD and renewables with the ongoing policy years.

The next question is coming from Doug Leggate of Wolfe Research.

So guys, I think I've got to go back to Refining school because you guys are embarrassing us here with your distillate yields versus your light sweet crude throughput. I'm wondering if you could help us reconcile what's going on there. Obviously, margins are -- heat margins were better than gas for most of Q2, I guess. But when we look at the -- basically since 2024, I think your light crude input is about 10% higher, but your distillate yield is up materially as well.

So great result, but can you help us understand what's going on there is my first question. I've got a quick follow-up for Eric.

Yes, Doug, this is Greg. So I would tell you, it's pretty simple. We've been, for the most part, in that period in max distillate production mode. So when you think about how we're adjusting the operation, we're maximizing the yield of jet fuel and diesel fuel.

So even though you've got a crude slate that might be a bit lighter, we can do some adjusting within the downstream operation to try to make sure we get all the distillate molecules into that pool that we can. And we've been pretty successful and effective at doing that in that time frame.

Sorry for the Part B here, but would I assume that that's part of the reason why your capture is doing so well?

Certainly helps it. Certainly, it helped when you've got that strong distillate crack and then you're maximizing that yield, that certainly will have a positive impact on capture.

So Eric, I wanted to follow up on the earlier question, if you don't mind, just on renewable diesel. I see if you can dumb it down for us, when you roll everything together, and you guys are obviously the lowest cost producer with the best feedstock setup. Do you see DGD net to Valero as free cash flow positive on a sustainable basis?

I think the answer to that is yes. Like I said, but it's going to take a little bit of clarity on what the EPA is going to do with RINs because the numbers they're talking about doing will put a positive tailwind into DGD's production. And so to your point, we still have the best market access, both from a feedstock standpoint, a certification of products and access to all the different markets. And it's still a low CI game.

I think one of the things that everyone needs to keep in front of them is that Europe and the U.K. really only accept waste oil, low CI feedstocks, certified feedstocks. So as much as there's been a lot of talk about the support of domestic production and soybean oil and Canada's canola oil, those are not acceptable feedstocks to most of the customers that are really interested in lowering their carbon footprint. And so we're still the most advantaged from a feedstock standpoint. I think once you start to see these credit prices move, and like I said, we have seen LCFS and RIN prices moving higher, those factors and credit prices will continue to make DGD an advantaged platform.

And long-term, it will be a positive cash flow into Valero.

If you can't make money, nobody can in this business. I appreciate the time.

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

Eric, maybe one more follow-up on that side of the business. I mean it seems so far that your SAF operations, the SAF operations have been going well. Can you maybe -- you're 8 or 9 months into post-start-up of the conversion there or the expansion there. Can you maybe talk about what you've seen so far, either operationally, what you've seen in terms of what's maybe surprised or been as expected in terms of the geographic mix of demand, pricing, et cetera, and how that market is evolving?

Yes. Thanks. I think one thing we discovered operationally that I might say was a pleasant surprise was -- our unit made SAF very, very well, and it blended very, very well. Prior to our start-up, we've heard through others that had gone down this journey that it was very difficult to make.

It was very difficult to blend. It was very difficult to make the certifications and satisfy the logistics. We -- with the combination of DGD's gear, the quality of our project start-up team and our overall project design, we've got a lot of capability on SAF as well as everything between SAF and, call it, traditional RD. So operationally, this thing has been a positive.

The logistics and blendability has been a positive. The ability to move this product through the Valero jet fuel system has been very effective. I think if there is any sort of downward surprises, we thought there would be much more interest in this product, particularly from airlines. I think everyone is still feeling out this market -- we're seeing a lot of interest in sales.

Obviously, the mandate in the EU and the U.K. There's some potential that they have underbought for the first half of the year, and they may come back and try to make sure they're hitting their 2% blend in the back half of this year. So we may see some sales pick up in the second half of this year as they stare at their end-of-year compliance target. So I think this market continues to grow.

The demand continues to grow. The interest continues to grow. The interest in the voluntary credits associated with this continues to grow. That is very small volumes, but everyone is trying to explore that as a way to simplify their carbon offset plan by just going direct to DGD.

So I still see a lot of upside in that. The project is still returning -- the returns on our project are still meeting our threshold targets. So that's going very well. and the credit prices have supported the making of the product. And so if I add on to that because the next question, well, with the recent reconciliation bill narrowing the benefit of SAF to equal to RD, we still see premiums above that coming out of the market.

And so as everyone figures out how to readjust with the changes in the PTC, we still see premiums for SAF over RD from the customer standpoint.

Great. And then maybe a question for you, Lane. Sorry to ask, but I mean, there are reports that the California government envisions themselves kind of like brokering a sale of the Benicia Refinery. Any comments or any thoughts on anything that could potentially change that would change your mind to close that asset next year?

This is Rich Walsh. First, we don't respond to speculation in media reports along those lines. And nothing has changed in our plans regarding Benicia right now. But look, there's been a lot of public discussion about reforming the market and in particular, the regulatory environment in California to head off refinery closures.

And I think you guys all know the CEC has been tasked with evaluating refinery capacity on behalf of the state. And I think they're working very hard to see what, if anything, they can do. And for our part, we've been in discussions with the CEC and other elected officials and policy officials regarding Benicia's future. And I think there's a genuine desire for them to avoid the refinery closure, but there's no solutions that have materialized, at least not from our perspective.

The next question is coming from Paul Cheng of Scotiabank.

The question that as Saudi is putting more barrels in the market, I assume there's going to be more the medium sour grade like the ever medium. I'm wondering that how you think it's going to impact on the global distillate yield as more of the medium sour is available? That's the first question.

Paul, it's Greg. Yes. So obviously, right, those grades have more distillate typically in them than some of the lighter grades. So as we see those come into the market, you would expect that to have a positive impact on distillate yield overall.

And as a result, distillate production would work up a bit. I don't have a good feel for the exact numbers for that. But there's no doubt that those are grades that are more rich in distillate than most of the other crudes that we have run in their place over the last few years.

Greg, I know that typically -- to pinpoint an exact number, but any feel that you a 2% increase, 5% or anything that you can share?

Yes, Paul, I don't have those numbers off the top of my head. I'm sure you can contact Homer, and we can talk about that more offline. But I don't remember the numbers off the top of my head.

But this is Lane. I think the one thing to add to that is you got to think about the markets you're putting diesel into and the specs around it, whether they're high cetane or ultra-low sulfur diesel. So in a global sense, the incremental diesel does -- is there open capacity for the higher valued markets where the stuff is pointed versus does the incremental diesel is produced in the world as these grades get more sour and more heavy, they end up just sort of as heavy in the marine market, that's sort of one of the things you got to consider with your -- the way you're thinking about it.

Okay. Great. The second question, I think, is for Eric. Eric, I mean, with the PTC and everything that is more in favor of domestic production and also keeping in the local market, I assume.

So is that still economic for us that to export RD from DGD. I know that previously you guys export quite a lot to Europe. So are those still economic or that the economic now saying that it's going to be majority of the RD production will be staying local?

Yes. I think -- so we do see the markets in Canada, EU, U.K. and California are still attractive for foreign feedstocks. The challenge that we have is we haven't -- most of this is still trading on news. So you've seen as the EPA will talk about what they're doing with the RIN, you'll see most of the fat prices are tracking the D4 RIN.

So even though fat prices have moved up, credit prices are slowly moving up, they haven't separated yet to reflect the impacts of some of the other policy comments on lower PTC, half RIN in the RVO and really a lot of the tariffs that have been placed on foreign feedstocks. So at some point, those markets will have to adjust. I think as the policies get papered -- get finalized and papered, and you'll see there will have to be some reflection in foreign feedstock prices versus domestic feedstock prices to continue meeting the demand of all those other markets. And so like I said before, it's still a low CI game and a lot of the customers do not want vegetable oil as their feedstock base.

So there will be an increase in the RIN. There will be support of vegetable feedstocks feeding into the RIN. But when you go into LCFS markets or markets that are based on LCFS and CI, it's still going to want to pull low CI feedstocks. And so you'll have to see the market adjust for that.

And I think we're starting to see some of those prices move, but it's probably going to take some time for these credit prices to increase based on the length in the credit banks for both RINs and LCFS. So I think as those banks slowly start to get consumed, the credit prices will move up, you'll start to see foreign feedstocks disconnect from domestic feedstocks. Both of them need to disconnect from the D4 RIN in order for anyone to increase production, particularly if you look at the -- a lot of the veg oil BD players, if soybean oil and the D4 RIN just track, there is no margin to run yet. And so I think once you see whatever the EPA comes out with RVO and SREs, that will determine when you start seeing BD and RD start to increase in production.

Eric, can we confirm that what percentage of your DGD, RD is currently exported to Europe and Canada?

Yes. We're not going to share that level of detail, Paul, but we are the largest exporter and really one of the largest producers of SAF. And so we're definitely maxing out what we can sell into those markets. But yes, that will always shift around based on feedstock prices and credit prices.

The next question is coming from Paul Sankey of Sankey Research.

Can you hear me?

We can hear you, yes.

We've had good high levels of throughput in U.S. refining this year despite the shutdowns. Can you just talk a little bit about that? It's been fairly steady and very high. And I just wondered what the components of that were as well as the outlook for the second half in your view, perhaps ignoring hurricane risk and stuff, but just the general turnaround outlook for the second half.

And the follow-up is a very interesting moment in history with the U.S. becoming a net exporter to Nigeria. Could you just talk a little bit about the impact of Nigerian refining on Atlantic Basin markets? Interesting stuff.

Paul, it's Greg. I think -- I'll talk about the first one. Just repeat that for me again. What part of -- are you looking at?

Well, the system is going to shut down -- would be shut down of Lyondell and stuff, we've just seen, what is it, $17.5 million of throughputs in U.S. refining seems like a high number. That's been very steady, actually. I just -- it's a good thing. I just wondered how come with so high and holding so high from your perspective and from an industry perspective.

And the follow-through is the second half turnarounds and whether or not we'll really sustain this kind of throughput.

Right. Okay. Yes, I think throughput has been real strong, particularly in the Gulf Coast, probably a good indication of people coming out of turnaround and running well. One of the things we look at a lot of times is it's been a relatively mild summer weather-wise, which a lot of times, as you get hotter and hotter, you start to hit some limitations operationally at lower rates.

And so we haven't seen that. I think you've been able to see the industry hold at pretty strong performance. Obviously, not a lot of things have been breaking. So that keeps utilization up.

And as we get to later parts of the summer, we'll see if warmer weather starts to creep in and we start to see some of those rates tail off. As far as turnarounds in the third quarter, it's always hard to see where the industry goes. I don't think we have any unique insight into that relative to what you can read elsewhere. But it looks like today, turnarounds are probably pegged to be a little bit below average.

What we typically see, though, as we get closer, more work starts to get known and identified in the plant. So we'll see where that ultimately lands. And I think probably you want to take the other half, Gary?

Yes. Nigeria, I think it's been -- there's a lot in the press that obviously, the Dangote Refinery had a lot of trouble bringing up their resid FCC. So they're running WTI. We see them continue to be in the market marketing atmospheric tower bottoms, which is an indication that, that resid FCC is not running right.

So whenever that's the case, they're probably going to push themselves to the lightest diet they can because they don't have that resid destruction capability. Ultimately, when they get the resid FCC fixed, you would expect them to start to transition to a little heavier diet and run more Nigerian grades.

So they're still sucking in gasoline then?

Yes.

Doug Leggate got me thinking about the school of refining. I think it's the school of refining hard knocks, right?

The next question is coming from Phillip Jungwirth of BMO Capital Markets.

You mentioned in the earlier commentary, gasoline demand being flat despite vehicle mileage being up. Not a new story here, but wondering if there's been any shift in your medium-term outlook for efficiency gains in light vehicle fleet, given consumer preference or government policy incentives. And any reason we could see a slowdown in gains here?

I think it's definitely a potential. You should see less EV penetration than what we have been seeing. Overall, though, the bigger impact in our models has always been kind of the impact of the CAFE standards and vehicles becoming more efficient. And we don't see that changing drastically going forward.

Okay. Great. And then we're all familiar with the affordability conversation in California and the state's tone towards shifting to ensure supply. I know you just have Pembroke in the U.K., but wondering what does the affordability or supply conversation looks like here or in broader Europe, given we continue to see closures here, too.

And you mentioned the Lindsey bankruptcy earlier. Really just trying to think about it in terms of the competitive dynamic, given I know you don't have a huge footprint here.

Yes. So I would tell you, the U.K. is a net importer of diesel. So the Lindsey Refinery closure probably doesn't impact that much because the diesel price is largely set by import parity. But at least it looks to us like Lindsey made about 50,000 barrels a day of gasoline.

About 60% of that remained in the U.K. Certainly, for our Pembroke asset, some of our netback -- best netback barrels are those that we sell into the local market. And so as Lindsey exit, we'll be trying to fill that void, which will make less available for exports to markets like California.

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

So Eric, I want to go back to RD and results in the first -- in the second quarter, while they were still challenged, they improved quarter-over-quarter. I was hoping you could unpack some of the drivers here. I know the indicator was lower, but I think that was offset by a greater recognition of the PTC and continued ramp in SAF sales. I was just hoping you could unpack that.

Yes. So I think one thing in the first quarter, we had a couple of outages on DGD 1 and DGD 2 for catalyst changes. So there was a -- we had better volume in the second quarter as part of that. But I think we also had a full quarter of PTC capture on eligible feedstocks versus the first quarter, we adjusted our operations to capture the -- begin capturing the PTC about mid-Feb.

So you only got about half a quarter in the first quarter, but the second quarter had full PTC capture for the eligible feedstocks and for our SAF. So we had a lot more income related to those factors in the second quarter. And so I think the offset there is we're still adjusting to all the different tariffs that will be -- that are constantly moving around. And so we do see that the quarter-on-quarter is continuing to improve.

And like I said, as we continue to see these credit prices creeping up, I'm hoping you'll see in the third quarter that we'll continue this trend for the rest of the year.

Great. And then with the passage of the tax bill a couple of weeks ago, can you talk to any benefits to Valero that we should be mindful of, anything around bonus depreciation?

Yes. Joe, it's Homer. So the reinstatement of full expensing should lower our overall cash tax liability in earlier years versus the typical makers depreciation schedule. So growth CapEx should definitely be eligible for bonus depreciation.

A lot of our sustaining CapEx should also be eligible with the exception of turnaround capital, which we already expensed. The magnitude of the benefit obviously depends on our CapEx going forward, but that would be one, at least from a tax standpoint benefit. Rich can talk about some of the other stuff.

Yes. I mean the other things that are out there that are just kind of directionally helpful is the federal EV tax credits go away. And so -- and then I think you also see limitations on the CAFE penalty for the autos, which I think kind of opens the door for them to really just try to meet consumer demands, which is generally for bigger vehicles and puts ICE engines on a more comparable footing to EVs. And so you don't have that same level of pressure to lower fuel economy, and that should also directionally be a collateral benefit that comes out of this bill that we'd expect to see manifest over the following years.

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

We saw the results in the North Atlantic were pretty strong and definitely better than our expectations. I think capture moved up quarter-over-quarter despite tighter Syncrude dips and the Pembroke turnaround. So could you talk about what helped you out in the North Atlantic in Q2?

Yes, this is Greg. So we did have a fair amount of maintenance in the second quarter. Most of that maintenance impacted throughput, and you could see that in the lower throughput that we had for the quarter, not so much on capture. And then we had -- like we talked about in the Gulf Coast, we had really strong commercial margins and contributions in that region as well that created the kind of consistent results versus what we had seen in the prior quarter.

Turnaround in Quebec, right?

Turnaround was in Quebec. Yes, Pembroke ran well, actually, kind of it's a theme for our system. Our operations really was strong across the system, including North Atlantic.

Sounds good. And then the RVO proposal, it has this potential SRE reallocation where the larger refineries would have to essentially pay for the SREs granted to the smaller refineries. It seems like it could be an extra hundreds of millions for Valero if that goes through. So I guess, one, how likely do you think that proposal would be to actually be in the final proposal?

And then two, it's generally accepted that the RVO is passed along in the crack. Do you think that the extra reallocation costs would also be passed along in the crack as well?

Yes. This is Rich Walsh. Let me take an effort to respond to that. I think without getting too deep into this, I think you need to understand the SREs were originally coming out of an exemption that was expired in 2011. And following that expiration, the Department of Energy was obligated to look at whether or not these SREs were necessary because the RFS was creating disproportionate harm or impact to the small refiners and the DOE concluded that it was not impacting small refiners.

So today, what we're talking about is extensions from a 2011 exemption, and it requires that these small refiners show a unique and disproportionate economic harm caused by the RFS itself. And like what you're alluding to here, in today's market, the RIN obligation is equally applied across the whole sector, and it's embedded in all the refinery margins. So I think EPA and DOE have repeatedly confirmed this with their own analysis. So while the EPA can't categorically deny all SREs, I believe it's going to be really challenging for these small refiners to make their legal case for the is uniquely harming them.

So my thought process is that you're not going to see a lot of SREs be granted by EPA or at least if you do, you're going to see a lot of legal challenges to that. And in terms of the RVO, I mean, remember that the RVO came out and right after it came out, there were a whole bunch of changes that happened. We had tariffs. We had restrictions on foreign feedstocks, RINs for foreign imports having to be cut in half.

So I think you're going to see a lot of comments coming in, in the proposed process. And I think EPA is going to have to look really hard at the RVO and have to think about what they got to do to revise it to make it realistic. And so I think those are the things that will kind of play out.

Our final question today is coming from Jason Gabelman of Cowen.

I wanted to go back to the commentary that you provided on the distillate outlook, and I appreciate all of the discussion around North American dynamics. But it seems like some of the output from other regions is a bit lower. And I wanted to get your thoughts on to the extent that that's transitory in nature, things like lower net exports out of Spain because of the power outages. It seems like Middle East diesel exports are down a lot.

Not sure if that is structural or not. So just wondering if you could provide your thoughts on things going on in other parts of the world.

Yes, Jason, this is Gary. I think, obviously, the strength in diesel is due to low inventories. July, we've been trending at historic low type inventories. And I would say a lot of that really started late last year.

Late last year, we had a relatively weak refinery margin environment. Based on where inventories were, I would say that the margin environment was too weak. And that led to lower refinery utilization, which limited diesel inventories from restocking as they typically do. Then we had a colder winter, which raised heating oil demand and further depleted inventory heading into the first quarter.

We have had some refinery shutdowns and then some of the new capacity that come online has really struggled to come up to full rate. So I think supply-demand balances are certainly tighter than expectations based on projected net capacity additions. A shift we've had in 2024, as jet demand increased, it's incentivized refiners to produce jet, which has come at the expense of diesel. In general, one of the things we've been talking about is refiners are running lighter crude diets.

That was exacerbated by the Venezuelan sanctions and Canadian wildfires. So with tight quality differentials, the incentive to run lighter crudes results in lower distillate yields. And then another factor here is with the poor renewable and biodiesel margins, they've resulted in lower production of those products, which has increased the demand for conventional diesel as well. So I think all those factors have come into play where we are on the low inventories today.

Okay. And then my other one, I'm going to ask something else that's already been asked, but a bit more specific on the crude quality differentials that you expect to widen out with OPEC adding barrels. And I guess there's been some reporting recently that China wants to stockpile crude inventories in the back half of the year and OPEC tends to price things more attractively to Asian markets than to U.S. markets. So how much of these Middle East barrels do you think will flow to North America and really influence crude quality dips in the back half of the year?

Well, Jason, I can't say we have a lot of insight into what's going on in China. So I don't know their plans in terms of restocking inventory. I can tell you that we really haven't been buying much crude from historic partners in the Middle East for quite some time, but we have reengaged with them. So the fact that they're reengaging with us tells me that they plan on some of the production making its way to the U.S.

So I'm confident we will see some of those barrels.

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

Thank you, Donna. Appreciate everyone joining us today. As always, please feel free to contact the IR team if you have any additional questions. Thanks again, and have a great day, everyone.

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