Good morning, everyone, and welcome to Valero Energy Corporation's second quarter 2026 earnings conference call. I'm joined today by Lane Riggs, Chairman, CEO, and President; Gary Simmons, Executive Vice President and COO; Rich Walsh, Executive Vice President and General Counsel; Homer Bhullar, Senior Vice President and CFO; as well as several other members of Valero's senior management team.

If you have not yet received a copy of our earnings release, it is available on our website at investorvalero.com. Included with the release are supplemental tables providing detailed financial information for each of our business segments, along with reconciliations and disclosures for any adjusted financial metrics referenced during today's call.

If you have any questions after reviewing these materials, please feel free to reach out to our Investor Relations team. Before we begin, I would like to draw your attention to the forward-looking statement disclaimer included in the press release.

In summary, it says that statements made in the press release and during this conference call that express the company's or management's expectations or forecasts of future events are forward-looking statements and are intended to be covered by the safe harbor provisions under federal securities laws. Actual results may differ from those expressed or implied due to various factors, which are outlined in our earnings release and filings with the SEC.

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

Thank you, Brian, and good morning, everyone. We're pleased to report a strong second quarter, driven by exceptional operational and commercial performance across all three of our business segments.

While geopolitical and macroeconomic factors continue to drive volatility, our team executed extremely well, adapting to changing market conditions and capturing opportunities across our refining, renewable diesel, and ethanol segments. Our refineries operated safely and reliably, helping meet resilient demand for transportation fuels.

Our renewable diesel and ethanol segments also performed well, supplying additional liquid fuels to the market. On the financial side, our strong balance sheet remains the hallmark of our capital allocation framework.

In addition to building cash during the quarter, we continued to demonstrate our long-standing commitment to shareholders, and earlier this month, we announced a dividend of $1.20 per share. Strategically, we still expect to complete our FCC unit optimization project at our St.

Charles Refinery during the third quarter. This $230 million investment is well-timed and will allow us to increase our production of high-value products, including alkylate and finished gasoline.

Looking ahead, we continue to see a constructive environment for our business. Refining fundamentals remain supported by low global product inventories, limited excess refining capacity, and resilient demand for transportation fuels.

The US Gulf Coast continues to be one of the most advantaged crude sourcing regions in the world, supported by abundant domestic production and access to a diverse range of other feedstocks, including Canadian and Venezuelan crudes. Our strategically positioned and highly competitive asset base is also well-suited to supply constrained global product markets.

In closing, our strong results reflect the discipline and consistency of our operational and commercial execution. Coupled with our differentiated balance sheet, these strengths position us well and provide plenty of financial flexibility.

With that, I'll turn the call over to Homer.

Thank you, Lane. For the second quarter of 2026, net income attributable to Valero stockholders was $3.7 billion, or $12.62 per share, compared to $714 million, or $2.28 per share, for the second quarter of 2025.

Excluding the adjustments shown in the earnings release tables, adjusted net income attributable to Valero stockholders for the second quarter of 2026 was $3.7 billion, or $12.54 per share. The refining segment reported $4.5 billion of operating income for the second quarter of 2026, compared to $1.3 billion for the second quarter of 2025.

Adjusted operating income for the second quarter of 2026 was $4.4 billion. Refining throughput volumes in the second quarter of 2026 averaged 3 million barrels per day.

Refining cash operating expenses were $4.70 per barrel in the second quarter of 2026. The renewable diesel segment reported operating income of $717 million for the second quarter of 2026, compared to an operating loss of $79 million for the second quarter of 2025.

Renewable diesel segment sales volumes averaged 3.8 million gallons per day for the second quarter of 2026. The ethanol segment reported $318 million of operating income for the second quarter of 2026, compared to $54 million for the second quarter of 2025.

Ethanol production volumes averaged 4.7 million gallons per day in the second quarter of 2026. G&A expenses were $233 million for the second quarter of 2026.

Depreciation and amortization expense was $737 million for the second quarter of 2026, which includes approximately $33 million of incremental depreciation expense related to ceasing refining operations at our Benicia Refinery. Net interest expense was $145 million, and income tax expense was $1.1 billion for the second quarter of 2026.

The effective tax rate was 21%. Net cash provided by operating activities was $5.6 billion in the second quarter of 2026.

Included in this amount was a $706 million favorable impact from working capital and $389 million of adjusted net cash provided by operating activities associated with the other joint venture member's share of DGD. Excluding these items, adjusted net cash provided by operating activities was $4.5 billion in the second quarter of 2026.

Regarding investing activities, we made $350 million of capital investments in the second quarter of 2026, of which $290 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, and the balance was for growing the business. Excluding capital investments attributable to the other joint venture member's share of DGD and other variable interest entities, capital investments attributable to Valero were $346 million in the second quarter of 2026.

Moving to financing activities, we remained committed to our disciplined capital allocation framework. Shareholder cash returns totaled $2.6 billion in the second quarter of 2026, resulting in a payout ratio of 59% for the quarter.

As Lane mentioned earlier, we announced a quarterly cash dividend on common stock of $1.20 per share on July 16. Turning to the balance sheet, we ended the quarter with $9.1 billion of total debt, $2.2 billion of total finance lease obligations, and $7.9 billion of cash and cash equivalents.

The debt-to-capitalization ratio net of cash and cash equivalents was 11% as of June 30, 2026, reflecting a cash build of $2.1 billion during the quarter. Consistent with our prior messaging, we built cash above the high end of our long-term $4 to $5 billion cash target to preserve optionality in a volatile market environment, while also exceeding our minimum payout commitment.

Earlier this month, we repaid the $100 million outstanding principal balance of our 7.65% notes that matured on July 1. An additional $572 million of maturities due later this year will be repaid using cash held from debt we proactively issued in the first quarter.

Overall, we ended the quarter well capitalized, with $5.3 billion of available liquidity, excluding cash. Turning to guidance, we expect capital investments attributable to Valero for 2026 to be approximately $2 billion.

This includes expenditures for turnarounds, catalysts, regulatory compliance, joint venture investments, and the estimated costs to repair the DHT unit at our Port Arthur Refinery. Approximately $1.7 billion is allocated to sustaining the business, with the remainder directed towards growth projects.

Repairs to the Port Arthur DHT unit are expected to be completed and the unit returned to service by year-end. Total repair costs are estimated to be $250 million, included in our updated guidance for sustaining CapEx.

We expect a substantial portion of the cost to be covered by insurance. In the meantime, the refinery continues to operate at normal throughput rates.

On the growth side, our projects are focused primarily on shorter-cycle optimization investments that enhance crude and product optionality across our refining system, as well as efficiency and rate expansion projects within our ethanol plants. Collectively, these projects should strengthen the earnings capacity of our existing asset base.

For modeling our third quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.78 to 1.83 million barrels per day; Mid-Continent at 460 to 480 thousand barrels per day; West Coast at 110 to 120 thousand barrels per day; North Atlantic at 450 to 470 thousand barrels per day. We expect refining cash operating expenses in the third quarter to be approximately $4.75 per barrel.

For the renewable diesel segment, we expect sales volumes of approximately 335 million gallons in the third quarter. Operating expenses should be 49 cents per gallon, including 21 cents per gallon for non-cash costs such as depreciation and amortization.

Our ethanol segment is expected to produce 4.8 million gallons per day in the third quarter. Operating expenses should average 39 cents per gallon, which includes 4 cents per gallon for non-cash costs such as depreciation and amortization.

For the third quarter, net interest expense should be about $140 million. Total depreciation and amortization expense in the third quarter should be approximately $700 million.

Lastly, we expect G&A expenses this year to be approximately $960 million.

Thanks, Homer. That concludes our opening remarks.

Before we open the call to questions, I would ask that you limit each turn in the Q&A to two questions. If you have more than two questions, please rejoin the queue as time permits to ensure other callers have time to ask their questions.

Good morning, Lane, Homer, Gary, team. Obviously, an extraordinary quarter.

I think a lot of us remember when $4 was your mid-cycle EPS, and doing $12 in a quarter is pretty extraordinary. We're not quarter-to-quarter folks here, but as we think about bridging 2Q to 3Q, we'd just love your guys' perspective.

We just look at Gulf Coast indicators, they're up from 30 bucks to 41 bucks on your database. The shape of the oil curve is probably more favorable, with dated Brent versus your month one Brent no longer being in such deep backwardation.

Can you just talk about some of the moving pieces as we bridge from 2Q to 3Q, and give us any color you can provide knowing that there's a lot of quarter left?

Good morning, Neil. This is Gary.

I'll try to go through it. Still early in the quarter, but to us, both margins and capture rates look constructive relative to the second quarter.

As you mentioned, really the biggest tailwind in the quarter is really around feedstocks. The market structure thus far is resulting in an improvement in delivered crude costs relative to the benchmarks.

Thus far, Randy's team has done a really good job of purchasing several grades of crude at discounts to the benchmarks, where in the second quarter, a lot of the physical grades were being traded at significant premiums to the screen. Naphtha is at a premium to Brent, which in the second quarter was flat to Brent.

Propylene is strengthened. Sulfur remains strong.

In the second quarter, we did get a nice tailwind from jet, which we haven't seen in the third quarter. We do now have an open arb to export jet to Europe, and as we transition to winter grade diesel specs, I suspect we'll start to see jet strengthen as we move throughout the quarter.

Really, the margin environment thus far is stronger than what we saw in the second quarter, and based on what we know today, we should see an improvement in capture rates as well.

Hey, Gary. Follow-up.

Homer, this one's probably for you. Just you're sitting above what I would characterize as your mid-cycle cash balance of $4 to $5 billion right now.

How are you thinking about deploying it, whether to hold back excess cash or to continue to shrink the share count? Any perspective would be great.

Neil. Maybe I'll just start reiterating what we've said around our decision to build cash this year was really driven around prudently managing our volatility in commodity prices, right?

The risk that we're trying to address is when you have a rapid pull back in commodity prices, particularly crude, that tends to be accompanied by a draw on working capital and cash, and in that event, if there's a significant draw on cash, we just want to make sure we're not constrained on our ability to return cash to shareholders. With that said, because of the current environment we're in, coupled with a balance sheet where we don't really have any need or pressure to further lower leverage, we can pay out well above our target of 50% and build cash at the same time.

Gary obviously talked about things on the refining side going to the third quarter. I'm sure Eric will also speak to a constructive backdrop for our other two businesses, ethanol and renewable diesel.

In this environment, I think building cash and shareholder returns don't have to be mutually exclusive. I'll reiterate that our long-term target on cash and leverage remains unchanged.

While the volatility is likely not behind us at this point, we'll continue to hold a little bit more cash, but if we see a pullback in commodity prices or lower volatility, we're in a great position to accelerate shareholder returns as we move back towards our long-term cash target of $4 to $5 billion. Long answer, but hopefully helpful context for you.

That's great. Thank you, Homer.

Good morning. Over the last several years, repeated geopolitical disruptions have highlighted just how tight global refining capacity remains post-pandemic, even with meaningful capacity additions in emerging markets.

Each successive disruption appears to have produced a larger-than-expected margin response, most recently following events in the Middle East. Do you believe that the industry has, structurally shifted to a higher mid-cycle refining margin environment, and if so, what are your assumptions that would underpin such an outlook?

Theresa, this is Gary, and we do have a much more bullish view of a future mid-cycle than what you would calculate using historic margins. The primary basis for that view is that when we look at the mid-cycle that you would get calculating historic margins, product crack spreads were largely set by cracking margins in Northwest Europe.

As supply and demand balances have tightened, it appears that refinery crack spreads are now really being set by hydroskimming margins in Northwest Europe. Based on future demand projections as well as planned capacity additions, we believe hydroskimming margins will continue to set product crack spreads moving forward, which will result in higher crack spreads.

Additionally, that hydroskimming capacity is subject to rising costs of carbon credits, which drives those cracks higher, as well as inflationary pressures on both OpEx and CapEx that will result in a higher floor on refinery cracks. Finally, we also see a much more bullish outlook on crude quality discounts going forward compared to history, especially for heavy sour crude, which also is very positive impact on our future mid-cycle view as well.

Thank you. Also appreciate the really impressive results in the renewable fuel segments.

If we could get an update on your outlook for unit margins and profitability on a go-forward basis here, both near and long term, that would be great.

Theresa, this is Eric. I think if we start with DGD and renewable diesel, you see it benefited from the same volatility that benefited liquid fuels in general, but the underlying benefit that you saw in 2Q is the fact that the RVO and the D4 RIN increased at a rate far quicker than fat prices.

As we look at that going forward, we still see D4 values higher than fat prices, and so you have that tailwind certainly through '26 and '27 with the RVO as it has been set. Even with the recent drop in the last few days, it's still very positive versus historical.

We see RD looks more positive for the rest of this year and into '27. Then with ethanol, same benefit with the general increase in gasoline and octane values, but on top of that, the production tax credit that we are now capturing, it's 14 cents year to date, probably 17 cents for the full year, and if you look into '27 through '29, it's probably 19 cents a gallon.

You put that in perspective with a historical mid-cycle of 25 cents, that says that you're almost doubling the value of ethanol through 2029. You've got some significant structural tailwinds in both RD and ethanol on top of the benefit that we're seeing today with just the whole world being short liquid fuels and seeing a lot of volatility.

Very helpful. Thank you.

Congrats, guys. I think this was your highest ever quarterly earnings.

Let me know if I'm wrong, but I think it was the highest. I just had a quick questions, both kind of relating to refining macro, I'll ask them together.

First, the number that is floating around is that there's 5 million barrels of global capacity, or 10% of the global capacity, which is offline between Middle East as well as Russia. I'm just trying to understand what would that do to the global product inventories, and even if we open up magically in the next 1 month, how long do you think it would actually take to replenish some of this global product inventory which has been depleted in a major way because of the extended shut down that we are having?

My second question here is when we look at the Russia-Ukraine conflict, when it started, diesel moved up, gasoline really did not participate. This time it's a little different.

Gasoline is actually very actively participating, and it's closing the gap to diesel, and assuming you're still in max diesel mode, but gasoline cracks are much stronger. If you could talk a little bit about what's driving the relative strength in gasoline and are the gasoline markets really that tight?

If you could address those things, thank you.

Hey, Manav. I'll try to go through those.

I think we agree, about 5 million barrels a day of refining capacity is offline. When we look at the consultant data that we subscribe to, it would show that globally total light product inventories are down about 150 million barrels from where they were to start the year.

We're about 130 million barrels below where they would normally be at this time of year. Their data would suggest that if the conflict were to end today, global inventories remain below the 5-year average range through 2027, gasoline recovering fastest, followed by diesel and then jet.

These projections do assume that you see suppressed global demand for clean products this year as a result of higher prices, and that we'll see normalized operations in the Middle East and Asia following a reopening of the straits. What I would tell you is what I see today, I think it takes longer to recover than those projections.

I think some of the refining capacity, especially in the Middle East, sustained damage, and it'll take a longer time to come back on. Then as you mentioned, the Ukrainian drone attacks on Russian refining capacity are beginning to have a significant impact on the market, and I don't see those slowing down.

In terms of the relative strength of gasoline relative to diesel, I think a lot of what we've seen on gasoline is that normally you see a flow of gasoline from Europe to the United States, and with the strength in Europe, the transatlantic arb to ship gasoline from Europe to the US is closed. In addition to that, we see good export demand for gasoline into Latin America.

The combination of the closed arb to import barrels from Europe, open arb to export barrels to Latin America has net gasoline imports down about 400,000 barrels a day from where it historically is. That, combined with good domestic demand, is really what's leading to the relative strength in gasoline.

Thank you.

Good morning. Thanks for taking the question.

This question is sort of along the same capital allocation lines, but it's about growth. I do think the market has accepted the fact that refineries represent a bottleneck in the energy complex right now, and that seems pretty clear.

The question is just how are you thinking about growth opportunities within that? I guess there's some questions about kind of inflation that flow into that, too.

Thank you.

Sam, it's Lane. What I would say is post-COVID, we had been at about $1 billion pre-COVID on strategic spending, and that was really capped by, I would say, our project execution efficiency.

Post-COVID, we've been about a half a billion on average, maybe it creeped up to 0.7, a lot of which, if you look back at it, was renewables spend. We sort of paired renewable spend down because the sort of policy just isn't super supportive, and we're trying to let the renewables business sort of catch up with policy and some of the other things that are happening.

Really, our spend's largely in refining and ethanol. We still look for projects.

We're attentive, and we're very disciplined in terms of how we look at our projects, meet our gating system. We do have, as Gary alluded to, and I think most of the industry accepts, higher mid-cycles going forward.

The projects we like in refining obviously are more around two things, I would say: one is yield improvement; the other one is, I would call it commercial leverage, feedstock leverage, how can we get in a better position on things that were potentially long and trying to get rid of those, and then where we have a chronic short. I think one of the examples I used in the past was that the whole United States is short VGO, and so we'll look through and find the projects that make sense for us to sort of improve our overall commercial leverage in that space.

Like I said, we have a higher mid-cycle look going forward for that. We're not going to lose our discipline with respect to our capital, how we're going to spend money.

With that said, Gary kind of touched it, the higher cost of these projects also it supports a higher mid-cycle as well. There's a lot of things here supporting a higher mid-cycle in refining.

Okay. Then this is just a follow-up.

I think one of the limiting factors on maybe crude throughput capacity growth in the past decade is that crude availability wasn't necessarily improving. E&Ps wanted to send their incremental barrel into export markets.

Now that may be a little different because you have Venezuela that's growing volumes into the US, and then Canada, a lot of Canadian producers seem to want to be in growth mode, too, and that's kind of a captive barrel. Is there anything changing on the feedstock side that affects your view of crude throughput optionality?

We don't try to provide too much, I would say, strategic specific projects. I will say we see the same things.

We see a forward world where there's more Canadian heavy, there's more Venezuelan. That helps our current asset base.

If you think about what I said earlier with respect to how I would like to improve our position with respect to VGO and maybe not quite so much naphtha-rich crudes, I'd like to see projects that sort of in that, incrementing crude in that space, for sure.

Thank you.

Hi, good morning. Thanks for taking my question.

My first question is just a follow-up on DGD margins, and specifically looking at the July-to-date indicator, it's quite high, and it looks like in addition to the higher diesel price and RIN prices that were kind of known and expected, you've also seen a tick down in feedstock costs as well. Maybe you could talk about the dynamics kind of driving feedstock costs lower and how you expect that to trend for the rest of 3Q.

Just to confirm, when feedstock prices are coming down, we should expect a capture headwind there in 3Q, just wanted to confirm that.

That's absolutely right. What you're seeing on the feedstock side is the current policy favors domestic feedstocks first over foreign feedstocks.

Soybeans and ag in general continues to have above expectations in terms of crop yields, and that's globally, not just in the US. That you see a length in corn, you see length in soybeans, and the US policy with this high D4 is somewhat eliminating the benefits of what usually is the low-CI waste feedstocks being advantaged over veg oils.

The US is becoming largely indifferent, just looking for just volume to fill the D4 obligation. Externally in the world, the rest of the world is still driven on low-carbon pathways and feedstocks, and so you still see soybean oil is not the preferred feedstock for a lot of the compliance volume that goes into Canada and Europe.

In general, the world is well supplied feedstocks. I think one of the challenges we'll see will be a headwind going into the rest of the year is how the new tariffs are going to affect some of this.

In general, you see the demand for liquids and the values associated, whether it's LCFS or D4s, exceeds where feedstock prices have been.

Great. Thanks, Eric.

Then my next question is on the crude slate on the Gulf Coast, and just wondering if you could give us some color on how much Venezuela you were able to run in your system today, and if you could also talk about the availability of Mexican grades. I think there's been an effort there to curb exports of crude, just wondering what the market for Mexican crude looks like today.

We'll start with Venezuela. This is Randy, by the way.

We continue to see pretty good availability out of Venezuela on the heavy crude supply, and we're pretty encouraged by the growth that we're seeing both in supply and exports out of the country. I think if you look kind of over history, we've been the largest US consumer of Venezuelan crude over the last several years, and we expect that to continue going forward.

Our ability to process very high volumes of this heavy, high-acid crude is a key competitive advantage for our system. As always, we always compare this against other alternatives, including Canadian heavy.

If you kind of look at June, we saw Canadian crude prices rise quite a bit due to weather and flooding issues up in Canada. That caused us to kind of pivot to more Venezuela, and we'd expect to see processing rates of Venezuelan heavy crude in the coming months that exceed our historical maximum.

Down in Mexico, right now they are down compared to last year, mainly due to higher refinery runs with the startup of Dos Bocas. We do see this pretty volatile month-to-month, so as their refinery system runs higher, their exports are obviously lower.

We see that trend likely continuing going forward.

Thank you.

Great. Thanks.

Good morning, and thanks for taking my questions. I wanted to dig in on some of the regions, and starting with the West Coast, can you just talk about what you're seeing from a local crude pricing and availability standpoint?

It looked like a good quarter for the West Coast and Wilmington, maybe you could just talk about how that asset's performing and competitiveness of it currently relative to the rest of the portfolio. Then on the Gulf Coast, that was also stronger than we had modeled despite some of the downtime at Port Arthur.

Just your perspective on both the West Coast and the Gulf Coast would be helpful.

Joe, this is Randy. I'll touch on the crude side.

Obviously, the combination of the refinery closures and recent production rate increases on some of the California domestic crude has left the market pretty well supplied. This has been exacerbated by the idling of the San Pablo Pipeline that moves crude into the Bay Area, forcing more of these domestic barrels to clear to refineries in LA.

With these logistic bottlenecks, we have seen prices for California crude weaken considerably, and we've been working with our Wilmington Refinery to increase processing rates of these barrels and anticipate hitting record levels of these crudes in the coming months.

On the Gulf Coast, I would say really the tailwinds in the quarter that improved our capture rates, really the first one was jet fuel. If you look in the second quarter of last year, our jet yield was 9%.

Second quarter this year, we ramped that up to 12%, almost increased our jet yield by close to 100,000 barrels a day, which was really supportive of capture rates. In addition to that, as I've talked about, we see a real strong export market.

Those premiums into the export market also helped our capture rates as well.

Great. Thanks, Randy.

Thanks, Gary. Then could you just talk a bit about the impact of policy changes that we've seen recently?

In the past, you've talked about using the Jones Act to move some product from the Gulf Coast to the West Coast and other areas of the US. Would you expect this to continue to be extended?

Whether it's extended or not, I don't have a lot of insight. We will tell you that I think that's been critical to keeping PADD 1 and PADD 5 supplied.

PADD 5, we saw the barrels coming from the Far East disappear, and so we certainly were moving barrels from our Corpus Christi Refinery to PADD 5 to keep that market supplied. Also with the transatlantic arb closed to send gasoline from Europe to PADD 1, the Jones Act waiver has been very critical keeping PADD 1 supplied as well.

Great. Thank you.

good morning, guys. Thanks for having me on.

I seem to recall having a discussion with Homer about net debt zero not so long ago, and it seemed unrealistic, extraordinary times indeed. My question, I've got two things I wanted to bring up, if you don't mind.

We're just sitting here watching extraordinary margins, we don't know what the duration is. You've got practically no net debt.

I think you're kind of signaling a preparedness to be patient with building cash. Why is a rebalancing of dividends and buybacks not an appropriate thing to consider if you believe mid-cycle should be higher going forward?

Hey, Doug, it's Homer. I think ultimately this comes down to a discretionary use of cash, right?

Or really it's discretionary use of excess cash. There's always going to be an underlying element of share repurchases and dividend to meet our minimum commitment of the 50% that we've laid out for our owners, right?

Beyond that, you're looking at basically alternative uses of capital when you're looking at our broader capital allocation framework. Lane obviously talked about the discipline we're going to have around growth investments, right, with a minimum return threshold, acquisitions we've talked about, they have to have good strategic value, right?

Let me rule out that part of our capital allocation framework where we're not going to all of a sudden do growth or acquisitions just because we're flush in cash. That's obviously worked really well for us, and it's evident by if you look at our long-term return on invested capital or return on equity, it's well north of 15%, right?

Keep in mind, that includes all sustaining capital, not just growth capital, so that tells you our growth projects have actually returned well in excess of that. Absent those uses, we're clearly not just going to have cash sit on our balance sheet, given, as you highlighted, our already low net leverage.

Now we've talked about this, and I recognize that at a higher share price, accretion from buybacks is lower, but as we've demonstrated over the last decade, our disciplined approach has worked well, and we've had a return on share repurchases that's in excess of 20%. Even at a higher share price, buybacks are a better use of cash than the alternatives I talked about, especially given the fact that we're talking about excess cash here.

On the dividend, obviously we want to make sure that it's sustainable through cycle. We also look at our dividend yield relative to our closest peers, and I think we're competitive there.

Then we do want to show some level of annual growth, but we're going to be prudent around that annual growth, again, because we want to make sure that it's sustainable through cycle. I think you can expect our actions to be consistent with all of that.

Very fair, and I appreciate the answer, Homer. My follow-up real quick, I hope maybe Gary could opine on this, but look, a month ago, diesel prices, gas oil prices mid-June were about 35, 40% below where they are today.

There obviously, we all know what's been going on in the Middle East. Then we got a Russia export ban, and then I'm not actually quite sure where things stand right now, but we also then got a cessation of the restart of Chinese exports on products.

One of your peers the other day talked about the black swan or the wild card of China came back into the market. Gary, I wonder if you could just walk us through what your intelligence is telling us on those two dynamics, because they seem to be pretty impactful to this near-term margin strength that we've seen just in the last couple weeks.

Doug, I'll start with China. We don't have a lot of insight into what's going on in China, but what we can tell you is despite the fact that they've raised their export quotas, our traders aren't really seeing any Chinese barrels leave the region.

We're not seeing a surge in Chinese exports. In terms of diesel prices, I think you alluded to Ukraine and its impact on Russian exports, and that's certainly had an impact as certainly some locations in South America that were pulling Russian diesel have come to the US Gulf Coast to pull the diesel, which has caused prices to escalate.

I think the other thing that's happened is earlier in the year, you just saw such deep backwardation in the diesel market that it made export arbs difficult. You had high freight, steep backwardation, which made exports more challenging, and you had buyers who were wanting to sit on the market with the hopes they were going to be able to buy their resupply cheaper in the future.

As we get closer to heating oil season again, I think you see the buyers that are starting to come back into the market realizing they need to buy in order to get inventories back in place before heating oil season hits. Combination of that with the further disruption in Russia is really what's caused the strength in diesel prices.

Great color, Gary. Thanks so much.

Thanks. Good morning.

First half turnaround CapEx ran $374 million, which is pretty low relative to the billion per year you've been averaging over '25 and '24. It also looks like 3Q throughput guidance is going to be a bit higher than historical utilization.

I know you don't talk about future turnarounds, but is there ability to push some of these out? Then just what's driving the lower first half spend to help frame a go-forward run rate?

I'll start, really no thought on us in terms of delaying our maintenance. We have a fairly steady spend on turnaround activity, and that will continue.

We found that it really is important to execution to keeping those dates kind of set, nothing different there. In terms of the timing of spend, I think our guidance in terms of our CapEx will hold, and it may be a little lighter or heavier from one quarter to the next.

Great. Then there's been a lot of focus on mid-cycle cracks, historical averages.

I wanted to ask about it more from the standpoint of just how much above a 10-year average crack do you see industry really needing to invest in meaningful capacity growth? Being a bit facetious here, but roughly how much above historical mid-cycle do you think is needed to support investment in a new refinery?

In terms of a new refinery, that number I don't have in front of me. You look at what the cost of some of this new capacity has been, it's very, very high.

In terms of what we think it needs to be, I go back to this: I think we feel like hydroskimming capacity in Northwest Europe is needed to run in order to balance demand in the market, and so mid-cycle margins will have to be sufficient to incentivize hydroskimming capacity in Europe to run.

Thanks.

Good morning, all. Homer, I appreciate that you're a CFO with a major problem of too much cash.

If I could just ask a couple of questions which are maybe more industry-oriented. The first, you mentioned that feedstocks have been really a big driver, between high product price and feedstocks, I guess.

I was just wondering, one major impact has obviously been the SPR drawdown, which has fallen now from nearly 1.4 million barrels a day to more like half a million. I just wondered, and I know this is not a Valero-specific issue, more of an industry observation, what your understanding about how the SPR will continue to draw down from here?

Secondly, again, on the kind of industry observation note, and I know you won't comment on this either for Valero specifically, the refineries in the US obviously have been running exceptionally well, also with a surprisingly high jet fuel yield. I was just wondering what your expectations are for turnaround season for the industry, if we're going to have to start shutting stuff down more aggressively as we head into winter with a tight diesel market.

Thanks.

Paul, this is Randy. I'll start on the SPR question.

I think back in March when Trump announced the release of 172 million barrels from the US SPR, we believe what's been committed and contracted so far is more like 130 million. Of that volume, we think there's around 40 million that's left under that allocation.

I know there's been a lot of discussion on what actually constitutes minimum. There's been some numbers thrown around if it's 300 million or if it's 70 million.

300 sounds a bit high, 70 million sounds a little low to us, but right now it's difficult for us to say kind of what the minimum volume may be that they can draw this thing down to.

Not a lot of insight on the turnaround activity. What we do see from the consultant data we have, it would show a little bit lighter turnaround season as we head into fall than is typical this year, and a little heavier turnaround season next year.

Got it. Thanks, guys.

Thanks, and good morning. Do you see the RIN market in shortage this year, and if so, could you talk about the implications to your various businesses?

If that was the case, it seems like RD profitability could be quite robust in the back half of the year. Then from the refining side, is there any concern that you would not be able to procure enough RINs to meet compliance in 2026?

Hey, this is Eric, I'll answer the first part. We do see the RIN market short, the bank being hit somewhere between the end of this year and sometime middle of next year given the pace we're at.

Everyone's looking at the June numbers thinking, wow, those are exceptionally high, we should have no problem meeting it. Maybe.

What we see is you still had a lot of players that did not produce D4s in 1Q waiting on the RVO release, which came out in April. So 2026 in particular is going to be a low production year versus the obligation, which means you will draw the bank.

We see that as structurally keeping the D4 RIN high. Hey,

this is Lane. I think the only thing I'd add is we have our eye on if and when the bank runs out, and, obviously, the RINs inside the crack, I don't think anybody knows what happens if it goes infeasible.

It could. At some point here with the way the RVO is and the amount of production, that is a concern.

The

only thing I would add on is this is going to be driven, at least on a policy side, by impact to consumers, right? If you think about the way we think about it, the RIN is in the crack, and that ultimately gets pushed on to consumers.

It really becomes an affordability issue, right? When and if EPA takes action will really probably be driven on how much this actually impacts consumers, otherwise, we're well positioned.

Sounds good. Then I think you mentioned that you're working on some ethanol expansions.

Can you share any sort of numbers around that, either percent capacity growth or the million-gallon expansion number? Then on the RD side, are you also looking at small debottlenecking projects or any sort of RD expansions?

Thank you.

Ethanol, we are looking at small debottleneck projects to the extent of 100 to 200 million gallons a year. That should all hit within the next year or two.

RD is a different outlook. I think, given this constant conversation about where policy is going to be and how predictable policy is or isn't right now, there's not a lot of intent on expanding anything in RD.

Great. Thank you.

Hey, everybody. Thanks for taking my question.

Mentioned earlier on the call, the RINs market is pretty short. It's somewhat hard to get to balancing it on paper just from domestic capacity.

There might be some additional utilization to come from biodiesel or renewable diesel facilities, but probably the biggest swing source of supply from here is from exports and imports into the US. I was just wondering what do you think is the biggest source of change for supply going forward?

In the event that we do balance the market soon, where do you think that incremental gallons will come from? Thanks.

This is Eric. I think one of the challenges that's different than previously, before you would have seen foreign imports pick up more quickly when you had the $1 blenders tax credit.

Foreign imports came in to capture that dollar, and that was the tax benefit that was in place prior to last year. What's different now with this RVO and RIN driver is you have to be registered to generate RINs.

A lot of these foreign importers are not registered to generate RINs, and so that will take an administrative step to do that. You also have the elimination of all tax credit benefits to foreign imports.

The production tax credit does not give any benefit to imports, and with the recent announcements of additional tariffs, it just makes that hurdle more difficult. You have no tax benefit on foreign imports plus this issue of it's RIN-driven now, not tax-driven, and so it's a different, think of it as a pathway, in order for foreign imports to get in.

They eventually will because that will be needed to satisfy this RVO, but that is I think the main reason why we have not seen foreign imports pick up as rapidly as everyone expected.

Thanks. That's helpful.

Hey. Thanks for taking my questions.

I wanted to start on Russia and obviously the disruptions there are benefiting the global product prices that we're seeing. If I recall the last time this happened in 2022, 2023, the Russian refineries came back, I think, a bit more quickly than what the market had anticipated.

Do you have any sense on the extent of damage from these Russian plants and if they're going to be able to come back relatively quickly once the bombing stops or if they'll be down for an extended period of time?

Jason, this is Gary. The only thing I can tell you is currently about 1.7 to 1.9 million barrels a day of Russian capacity offline.

If you look at the trend, it's from May to June to July, it's gotten progressively worse, not better. Then what you hear is that Ukraine is now targeting critical pieces of equipment where before they were shooting tanks.

You can understand that you have a tank fire and you can recover quickly. However, if they're taking out pieces of critical equipment, it could take a lot longer.

At least what we read, we don't have any direct insight into this, but it would seem like it takes longer rather than shorter for them to recover.

Got it. My follow-up is on US policy, and the administration has done a number of things to try and reduce the costs that consumers are paying at the pump, Jones Act, RVP waivers.

Are there other kind of levers that the administration has and anything incrementally you're hearing from them on a potential product export quota or ban? Thanks.

Oh,

this is Rich. I'll make an effort at answering that.

We share the administration's goal of trying to keep fuel affordable for Americans. As you guys know, there's a lot of issues impacting the fuel prices right now.

We work with the administration closely to ensure that they understand the market dynamics and the impacts of all the various policy options they might be considering, and make sure they're well understood. We believe they're looking through for the ones that are really viable and work.

The Jones Act, that you highlighted, is actually a really critical one. That's pretty strong Jones Act waiver commitment here from the administration, and it's kept the West Coast and the East Coast wet.

I think it's really maximized the US's refining capacities out of the Gulf and allowed it to be shared to the other regions. I think that's probably been one of the most critical ones.

There are other things that we're concerned about, there are the issues with the RVO and where will EPA settle in on that. There's a number of tax and tariff issues that have been kind of in place, particularly taxes on renewable feedstocks that would certainly help to get more and quicker feedstocks in.

The RVO is going to drive a lot of the price of gasoline, it already has, and then these uplifts and cracks that are caused by these SREs and the misallocation and misalignment that comes out of that is a problem. We're trying to make sure that they understand that those are not helping lower the price of fuel, that they're increasing the price of fuel.

We work with them closely, and I think they have a good, strong understanding, and they do want energy dominance.

All right, thanks for that.

Just want to thank everyone for joining us today, and as always, feel free to contact our IR team if you have any questions. Have a wonderful day.