Good morning, everyone, and welcome to Valero Energy Corporation's third quarter 2026 earnings conference call. Today, I'm joined 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; and several other members of Valero's senior management team.

If you have not yet received a copy of our earnings release, it can be found 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. During the third quarter, our business teams executed well in all reporting segments.

The market volatility and tight product inventories we saw in the prior quarter continued through the third quarter. Our teams remained focused on execution, running our refineries at near-record levels of utilization, and helping keep the markets supplied with critical transportation fuels.

Our ethanol segment also achieved a quarterly record for production during the third quarter, supplying fuel and contributing to our overall performance. Financially, we remain in a strong position.

During the quarter, we continued to honor our long-standing shareholder commitments, while also strengthening our cash position. As we look ahead, we remain constructive on the long-term outlook for our business.

Refining fundamentals remain favorable, supported by low product inventories, limited excess refining capacity, and continued demand for transportation fuels. Compared to other regions around the world, the United States is well positioned in the current market environment, and the U.S.

Gulf Coast continues to be one of the most advantaged regions globally, supported by abundant domestic crude production and access to cost-competitive feedstocks. Combined with our strategically located refining system and the flexibility of our commercial team, these advantages support our ability to respond to changing market conditions and resilient customer demand.

Turning to strategic capital projects, we completed the FCC unit optimization project at St. Charles Refinery during the third quarter on schedule and within budget.

This $230 million investment has already increased production of higher-valued products, including alkylate and gasoline. We continue to evaluate additional strategic opportunities to further strengthen the competitiveness and long-term value of our refining system.

However, as we assess these opportunities, we remain committed to our disciplined investment process that has served us well for more than a decade. In closing, our third quarter performance underscores the quality of our assets and our consistent operational, commercial, and financial performance.

This is a result of a long-term strategy that we've been committed to for well over a decade. With that, I'll turn the call over to Homer.

Thank you, Lane. For the third quarter of 2026, net income attributable to Valero stockholders was $6.8 billion or $23.89 per share, compared to $1.1 billion or $3.53 per share for the third quarter of 2025.

Excluding the adjustments shown in the earnings release tables, adjusted net income attributable to Valero stockholders for the third quarter of 2026 was $6.8 billion or $23.90 per share, compared to $1.1 billion or $3.66 per share for the third quarter of 2025. The refining segment reported operating income of $8.8 billion for the third quarter of 2026, compared to $1.6 billion for the third quarter of 2025.

Refining throughput volumes in the third quarter of 2026 averaged 3 million barrels per day. Refining cash operating expenses were $5.03 per barrel in the third quarter of 2026.

The renewable diesel segment reported operating income of $353 million for the third quarter of 2026, compared to an operating loss of $28 million for the third quarter of 2025. Renewable diesel segment sales volumes averaged 3.4 million gallons per day in the third quarter of 2026.

The ethanol segment reported operating income of $272 million for the third quarter of 2026, compared to $183 million for the third quarter of 2025. Ethanol production volumes averaged 4.8 million gallons per day in the third quarter of 2026.

G&A expenses were $308 million for the third quarter of 2026. Depreciation and amortization expense was $684 million for the third quarter of 2026.

Net interest expense was $144 million, and income tax expense was $2.1 billion for the third quarter of 2026. The effective tax rate was 23%.

Net cash provided by operating activities was $6.9 billion for the third quarter of 2026. Included in this amount was a $526 million unfavorable impact from working capital and $205 million of adjusted net cash provided by operating activities associated with the other joint venture member share of DGD.

Excluding these items, adjusted net cash provided by operating activities was $7.3 billion in the third quarter of 2026. Regarding investing activities, we made $432 million of capital investments in the third quarter of 2026, 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 member share of DGD and other variable interest entities, capital investments attributable to Valero were $429 million in the third quarter of 2026. Moving to financing activities, we remain committed to our disciplined capital allocation framework.

Shareholder cash returns resulted in a payout ratio of 52% for the quarter. Also in the third quarter, we repaid the outstanding principal balances of our $100 million note that matured in July and our $426 million note that matured in September.

An additional $146 million of debt maturing later this year will be repaid using proceeds from the debt we proactively issued in the first quarter during a lower rate environment. Turning to the balance sheet, we ended the quarter with $8.6 billion of total debt, $2.4 billion of total finance lease obligations, and $9.8 billion of cash and cash equivalents.

The debt-to-capitalization ratio net of cash and cash equivalents was 4% as of September 30th, 2026, reflecting the cash build this year. While our long-term $4 to $5 billion cash target remains unchanged, we continue to maintain cash above the high end of that range to preserve optionality in a volatile market environment, consistent with our messaging throughout this year, while also honoring our payout commitment.

Overall, we ended the quarter well capitalized with $5.3 billion of additional liquidity, excluding cash. Turning to guidance, we still 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 cost to repair the DHT unit at our Port Arthur Refinery. Approximately $1.7 billion is allocated to sustaining the business, with the remainder directed toward growth projects.

Repairs to the Port Arthur DHT unit remain on track for completion by year-end. Total repair costs are still estimated to be approximately $250 million, which are included in our sustaining capital guidance.

As previously guided, 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.

Our growth projects continue to be focused on shorter-cycle opportunities that improve crude and product flexibility, optimize the value of our product mix, and maximize utilization of existing conversion capacity across our refining operations. We've also been pursuing efficiency and capacity expansion projects at our ethanol plants.

These investments should enhance the earnings power of our assets. For modeling our fourth quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.855 to 1.905 million barrels per day, Mid-Continent at 440 to 460 thousand barrels per day, West Coast at 100 to 110 thousand barrels per day, and North Atlantic at 480 to 500 thousand barrels per day.

We expect refining cash operating expenses in the fourth quarter to be approximately $4.85 per barrel. For the renewable diesel segment, we expect sales volumes of approximately 325 million gallons in the fourth quarter.

Operating expenses should be 53 cents per gallon, including 23 cents per gallon for noncash costs such as depreciation and amortization. Our ethanol segment is expected to produce 4.9 million gallons per day in the fourth quarter.

Operating expenses should average 38 cents per gallon, which includes 4 cents per gallon for noncash costs such as depreciation and amortization. For the fourth quarter, net interest expense should be about $135 million, and total depreciation and amortization expense should be approximately $700 million.

Lastly, G&A expenses for 2026 are expected to be approximately $1.1 billion.

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.

Hi, thanks for taking the question. Yep.

It's a question on industry fundamentals, if we could start out, and on crude differentials, which have been pretty topical and also outsized recently. I think some of the crude differential move has been attributed to freight, but if you could just talk about it for a minute and give your views on whether it is structural what's happening with crude differentials because there's more heavy supply coming, or if you think this is more of a cyclical condition related to some constraints and external factors.

All right, Sam. Good morning, this is Randy.

Obviously, the market remains extremely volatile. We get headlines every day, every night around events in the Middle East, and we're obviously keeping a close eye on global trade flows.

Over the last several weeks, it does look like we are seeing sustained higher flows moving through the straits. We've seen media sources over the last couple days indicating that the volume over the last week has been actually higher than pre-war levels.

In addition to that, we've had some recent SPR releases. Overall, our indications from what we see in the market both on spreads and trade flows looks like the market is pretty well supplied with oil.

As you mentioned, the main story right now in the market is freight rates. As the flows through the straits increased, the inefficient process of the ship-to-ship transferring that they're doing of crude oil in the Gulf of Oman is really tying up global shipping, and to require more tankers to move the same amount of oil.

This is in addition to insurance risk premiums, transshipment delays, higher bunker costs, they're all kind of driving freight higher. As an example, the cost to move a VLCC from the Gulf Coast to Asia is now averaging around $30 to $35 per barrel, that compared with a 2025 average of around five bucks a barrel.

We're seeing this freight increase kind of play out in all markets around the globe and across all shipping classes, mainly on the dirty freight side. This is causing severe dislocations in our global crude pricing as refiners seek to find barrels that are closer to home, and sellers are forced to discount barrels to account for the freight costs.

Fortunately for us, the bulk of our systems in the Gulf Coast, which has access to a wide range of crude and crude qualities, is now a large exporter of crude. Since this crude must price to export, the sharp run-up in freight costs have forced the discounts to widen in all grades, giving the U.S.

Gulf Coast some of the cheapest crude costs in the world, especially on the heavy sour. The Gulf Coast is also freight-advantaged for heavy barrels out of Latin America compared with the Asian alternative, and discounts for these foreign barrels are also having to compensate for the large freight increase.

As Lane mentioned before, the Gulf Coast remains one of the most advantaged crude markets globally, and this freight run-up only further supports that. Looking ahead, our long-term outlook on crude differentials remains very constructive, as incremental supply looks to be dominated by heavier and more sour barrels, especially out of Canada, Venezuela, and the Middle East, which further supports the value of our complex Gulf Coast system.

Thanks. I was going to ask a follow-up on freight, but it sounds like you characterized your position fairly completely there.

Maybe this follow-up is just for Homer and on the cash balance. You're carrying a lot of cash.

It's an interesting position because you have a lot of optionality. Even if you're just earning a treasury rate on the cash, it's a massive number at this point.

Just your thoughts on how the balance sheet is structured today, whether it's a point in time that isn't necessarily meaningful over the long term, or if you kind of like having this optionality with an outsized cash position structurally. Thanks.

Hey, Sam. I guess let me just start by kind of reiterating what we've said throughout this year, that our initial decision to start building cash earlier this year was really around prudently managing volatility in commodity prices, right?

The risk that we've talked about is when you have a rapid pullback in commodity prices, it's generally accompanied by a draw on working capital and a draw on cash. In that event, we wanted to make sure that we're not constrained on our ability to return cash to shareholders, even if there is a significant draw on cash.

In fact, I'd say we want to make sure we're in a great position to lean into shareholder returns in that event. In an environment that's remains pretty constructive, we're comfortable where we are with respect to a payout.

We continue to pay out above 50% and continue to build cash. You touched on it, but we don't have a lot of other kind of commitments to cash.

We don't have a lot of maturities over the next year-plus. We have a little under $150 million that matures later this year, and a little over $500 million next year.

We have plenty of flexibility, as you highlighted. Obviously, we've talked about this before, but we're not going to change our approach to capital investments just because we have a lot of cash.

In short, we don't have a lot of other uses of cash. While the volatility is probably not behind us at this point, we're in a good position to be even more aggressive with shareholder returns, especially if volatility returns.

As we ultimately move back towards our long-term cash target balance of $4 to $5 billion, in any event, I think whether margins and cash flows profile of our business remains strong or not, our long-term targets on cash have really not changed. Over time, all excess cash we're accumulating will ultimately be directed towards our owners.

Thank you.

Good morning. I actually just wanted to follow up a little.

U.S. margins look very good, but what we are hearing is when you take into account some of this freight cost, backwardation, some of your Asian or European peers, they are not doing as well.

Again, you are also the low-cost refiner in the world. I'm just trying to understand, are we seeing a bifurcated scenario where one region of the world is at a good margin and can run much harder versus other parts of the world which are struggling to source crude and even when it gets there, it's very expensive?

Can you talk a little about those dynamics, please?

Manav, this is Gary. I think we see the exact same thing you're staring at, which gives us high confidence that this current crack spread environment is very sustainable.

When you look at some of the low-complexity refining capacity in the Far East, freight cost to get crude to that refiner and freight cost to get back into the export markets, it looks like their margins are in the $2 to $3 a barrel range. In addition to the margin squeeze they're currently facing, we're also seeing natural gas prices begin to take off in those regions, which puts even a higher floor on where crack spreads need to go in order to force those refiners to continue to run at high utilization rates.

I think the world needs that capacity to be running today.

Thank you. My quick follow-up here is, have you seen any signs of any kind of demand destruction, or can you generally talk about what you're seeing in both U.S.

demand as well as export demand as Valero sees is out there? Thank you.

Manav, I'll go through some of what we're seeing on the wholesale side. For the most part, I would say we're not seeing any signs of demand destruction at all.

On the gasoline side, our U.S. wholesale network 7-day average sales are actually up 4% year-over-year.

In Canada, they're flat year-over-year, and the U.K., flat year-over-year. Second quarter call, I mentioned that we were seeing some demand destruction in the U.K., but actually in the third quarter, demand recovered nicely there.

Gasoline demand has been very resilient to the higher prices, and then the export demand also very, very strong. You could see in all of our export markets, we're seeing a good pull from the U.S.

Gulf Coast. Certainly, we've seen gasoline cracks come off a little bit.

Some of that is just seasonal as you've transitioned out of driving season, and also get the swell from higher butane blending with the winter-grade gasoline specs. The underlying gasoline fundamentals look very, very strong.

We don't have a transatlantic arb to ship gasoline from Northwest Europe into PADD 1. We really don't have storage economics to begin to make summer-grade gasoline and store it, which is very constructive to the spring.

I think the biggest thing, when I look at the gasoline market, here we are in October out of driving season into high-RVP gasoline season, and you still have backwardation in the gasoline market, which is really telling you that the prompt market is very tight gasoline supply, and I think all of that's very constructive to gasoline longer term. On the distillate side, similar trends.

Our wholesale network would indicate about 2% year-over-year growth in sales, 7-day average sales. Both the U.K.

system and Canadian system are showing flat year-over-year sales. The only area where we're actually seeing lower sales is home heating oil in the U.K.

It is off about 10%. When you visit with our commercial teams over there, they think that's a combination of a couple of reasons: one, you've had unseasonably warm weather, and two, you've also had customers that are really trying to delay filling their tanks as long as they can.

What that actually could tell you is you could see a surge in demand into the U.K. when you actually have cold weather hit.

Export demand for diesel also very, very strong, both to Latin America and Europe. For us, no indication of demand destruction.

In fact, some of the leading indicators, both GDP remaining flat and also a lot of the trucking surveys actually ticking up, which would tell you the diesel demand is hanging in there very nicely.

Thank you so much.

Thanks, guys. Maybe the first question is just on volumes.

The volume guide you provided for 4Q, probably a little bit higher than what we thought, and so just maybe you talk about you're running the system hard in the fourth quarter. I guess the DHT is back up, too, so that should be a help as you go into the fourth quarter.

Then maybe stepping back for the industry broadly, because we did run so hard in 2026, you think '27 is going to be a decent-sized turnaround year for the industry? Any thoughts around that?

Neil, I'll start with the DHT. We really don't expect to have mechanical completion of the DHT till the end of the quarter, the DHT really isn't in the guidance.

It is a light maintenance quarter for us, and so we'll run the assets hard with margins where they are. In terms of the rest of the industry and deferring of turnarounds, we've been public, we don't really defer any of our maintenance.

We'll continue on our schedule for turnarounds. What you do hear from consultants is that there was about a million and a half barrels a day of refinery turnarounds globally that was deferred, which means turnaround activity is currently a little lighter than normal, and you would expect a heavier turnaround season next year.

All right,

that's helpful. Then just in terms of Q4 considerations, maybe this is for you, Homer, or Gary, but just we have average to start the quarter.

The Gulf Coast indicator is up, the Mid-Con indicator is up as well. Just any thoughts as we think about the fourth quarter.

Seasonally, typically, things tick down, but we started off the quarter pretty strong. Any advice for us as we model out the fourth quarter?

I think the big tailwinds for the fourth quarter, typically, you get the uplift of blending butane into gasoline. In our North Atlantic system, you generally have a nice uplift as we start to make Arctic diesel that carries some premium there.

Seeing some good tailwinds on the feedstock side with the heavy sours discounted and a lot of feedstock optimization opportunities. Then we're starting to see jet regrades turn positive again, which is also a tailwind.

Outside of that, when you look at secondary products, it's kind of a bit of a mix. Propylene and naphtha are off a little bit, but aromatics are up.

Overall, I would say mainly tailwinds when it comes to capture rates for the fourth quarter.

Thanks, Gary.

Morning. Gary, as we look at the fairly recent volatility in cracks, keeping in mind your comments about demand resiliency across your footprint plus the floor being incrementally higher for international refiners given high freight costs, natural gas, and so on, how would you explain the recent downside volatility?

Is that a result of incremental crude and products finding its way through the strait? What explains this, and how do you expect these factors to evolve over the near and medium term?

It looks like some of the downward pressure on cracks is really related to more headlines, people announcing releases from strategic reserves, lifting of Russian sanctions. Some of those types of things is what is actually driving some of the downward pressure on cracks.

I think when you digest the data and you look at how much volume is actually coming out, and then lifting of sanctions is more just a change in trade flows, I think we'll see a recovery in cracks moving forward.

Got it. We've seen various headlines about the Trump administration potentially working with operators to reopen U.S.

refining capacity that's been idled in the last 10 years. How seriously should we take these efforts?

More broadly, how do you think the supply shortage in the market would be most effectively addressed?

This Rich Walsh. I'll try to answer that one.

I really think you're focusing in here on Benicia. I'd just remind you that the status of that refinery is it's safely idled and has been since April, and we have no plans to restart it.

When we first announced and even just before we announced the shutdown of that facility, we had lots of discussions with both the state and the federal government and private parties, and none of those efforts actually materialized into anything. It's a tough environment to operate in the West Coast, and we just don't see the potential for that.

The last thing I would just remind you is that to restart that refinery, you would have to reinventory it, you'd have to restaff it, you'd have to undertake a rather extensive turnaround. It's not a simple process to restart it.

Hey, Theresa, this is Lane. I'll add to that.

I think, more broadly speaking, almost any refinery that's been shut down will take a while to start up, it'd be very difficult for them to help the prompt situation. We haven't had a lot of inbounds from the administration with respect to starting up other refineries, but we've heard the same things you guys have, I'm not saying that that's not occurring.

I think the idea that there's these refineries that you can just sort of walk in and flip the lights and they're going to start running is not exactly the case. We'll just see what's happening and with respect to on a longer-term basis with how this all plays out.

Thank you.

Thanks. Good morning.

Intra-quarter, we saw a lot of Venezuela upstream investment plans announced and some pretty ambitious production growth targets set. Just wondering where you are now on Venezuela throughput versus capacity, and just what would it take to have enough confidence to invest in increasing the ability to run more heavy crude?

Phillip, this is Randy. We continue to see pretty good availability of Ven crude in the Gulf Coast system.

As you mentioned, we're pretty encouraged by some of the new investments that's going on in the country to grow production moving forward. We've been for a long time, and we continue to be the largest consumer of Venezuelan crude.

In the U.S. Gulf Coast, we're the largest by far.

In fact, in the third quarter, we saw the Venezuelan crude compete very favorably compared to other heavy sour alternatives. As a result, we set a new processing record for Venezuelan barrels in the Valero system during the quarter.

As we moved into the fourth quarter, we've seen the economics shift some. The higher freight market has especially impacted the heavy crude market.

We've seen discounts for Canadian crude in the Gulf Coast widen to as high as $27 to $30 under Brent, making the Canadian barrel much more competitive versus the Latin barrel. As we kind of touched on before, our system's very flexible, our ability to flex between different grades is a big competitive advantage.

As we move forward, we're going to continue to look at opportunities where we can further increase consumption of those barrels.

This is Lane, I'll add to that. Definitely, one of the buckets that we look at in terms of our projects or even acquisitions with respect to this sort of heavy sour position, we feel like this is an area to help us with our feedstock optimization, and we're looking for debottlenecking opportunities and other opportunities in that space to increase our exposure to be able to run heavy sour.

Great. Then can you hit on the outlook for DGD margins and some of just the noise in 3Q, 2Q around capture, anything one-off to keep in mind there, and how you see that metric trending into the fourth quarter?

Philip, this is Eric. I think, just as a quick refresher, 2Q had a lot of one-off, one-time benefits like AIPA recovery, as well as a lot of modeling updates and year-to-date true-ups.

You had kind of an unusually high second quarter because of some of the one-time benefits. You also had the benefit, and we've talked about this on previous calls, there's a lag on how feedstocks price when they come into DGD, and you combine that with the volatility that we're all seeing, it creates a lot of noise in margin capture.

If you look at 2Q, you had feedstocks that we had bought in 1Q that were still much cheaper than the margin indicator, you had that advantage. Then you had, if you recall, a lot of the comments about the conflict were kind of waning, and so as ULSD fell, even though that's the base commodity price for DGD, it did help with some of the volatility in the positions of how cargoes were specifically pricing in that quarter.

3Q, you had the exact opposite. We had the impact that obviously we had the outage, we had the storm in DGD 3, which forced us to run a higher percentage of foreign feedstocks that were on the water, foreign feedstocks don't capture PTC, we had a lower PTC capture than the margin indicator.

Then you also had a lot of noise around the D4, and so with the conversation about SREs and whether or not they're going to be reallocated, we saw a pretty significant drop in the D4, and as those product cargoes were pricing, we saw a lot of volatility impact hit that lag as well. It's really all tied up in lag and the volatility of both ULSD and the D4.

If I think about 4Q, you still have a structurally high D4 RIN, we continue to see DGD very positive from a margin standpoint. We see positive cash flow.

I think the real strength of kind of like the refining segment where Gulf Coast is the most advantaged from a feedstock availability standpoint, combined with Darling being the largest producer of domestic feedstock, PTC benefits domestic feedstock, we are pivoting into, as always, maximizing the feedstock from Darling, now maximizing vegetable oil runs, really going into this D4 short that is going to continue into '27. Capture is a very difficult thing to predict.

good morning. Thanks for taking my question.

My first question is a follow-up on the demand side, and I think you've mentioned that it's been relatively stable despite significantly higher prices on both gasoline and diesel. I was wondering if you guys are in this market every day, are you surprised that we haven't seen more demand response?

Maybe do you have a view on if there is a price level where maybe we'd start to see a little more elasticity?

I would say especially with all the headlines about pricing, we have been surprised that you don't really see any demand response so far. In terms of a price level where you would expect some kind of demand destruction, I don't really know where that is because most people would have predicted we would have already seen it.

Fair enough. Thank you.

Then I guess Homer mentioned in his opener that you might be looking at some capacity growth in ethanol. I was hoping you could dig in a little on that in terms of timing and magnitude and any other color you could give there.

Sure, this is Eric. With the new PTC or benefits with the 45Z, it's encouraging really all ethanol producers to take a look at higher volumes.

We are looking at mostly capacity creep, on a refinery scale, this is not significant capital, and it's very quick-hitting capital. It's small capacity creep.

We're continuing to pursue our carbon sequestration projects at a couple of our sites. We're hoping those are hitting somewhere between late '27 to mid '28.

All of that will grow both ethanol volume as well as lower ethanol CI, which makes it more attractive for exports. We continue to see pretty strong export demand for ethanol, and our capacity is all pointed at growing exports.

Thank you.

good morning. Thanks for the question.

On the freight rates, you mentioned the benefits on the crude side in your Gulf Coast system. We had two follow-ups here.

One, are these higher freight rates a headwind to your North Atlantic and West Coast refineries, or are you able to use substitute crudes? Then, two, what kind of impact are the freight rates having on your netbacks for your Gulf Coast product exports?

Is the rate just passed through or is it pulling down the economics for U.S. product exports?

This is Gary. For the most part, the higher freight rates actually give us an advantage into the typical export markets in Latin America.

You're largely competing with European barrels into those markets, and so we have a freight advantage there. The only place that it does tend to hurt us is the diesel exports going into Europe.

I would tell you what it causes is just a lot of volatility with the arbs going open and closed. Basically, Europe is short diesel and needs it, and so when the freight rates spike, their prices have to adjust to keep those arbs open and keep the barrels flowing.

On the crude side, this is Randy. We do have some exposure to higher freight at our Pembroke Refinery and to the West Coast, and to a smaller extent into Quebec City, even though that refinery is mostly supplied via pipeline.

However, the benefit of the Gulf Coast impact far outweighs that. In addition, we do have a large fleet of time charter vessels, which tends to buffer some of the impact of the higher spot freight rates.

Great. Thank you.

Then, do you have any insights on the refining situation in Russia? Do you have any estimates on how much capacity is down and how long it might take to bring that capacity up?

Then, what are you thinking on potentially Russia diesel exports picking up here? Thank you.

This is Gary. I think that the data we see shows that on a 3-month average basis compared to a 2024 equivalent period of time, there was about 1.4 million barrels a day of refining capacity offline in Russia, still significant.

Most consultants estimate that it will take quite a long time to get that capacity back. I can't really give you a duration.

On the diesel exports, I think if you look at the volume that was announced, it kind of puts it at July levels of where Russian diesel exports would be, which is still 600 to 700 thousand barrels a day below where Russia was last year at this time. It's not a significant volume.

As we've always stated, really, sanctions or lifting of sanctions just results in change in trade flows, not really incremental supply coming onto or off of the market.

Thank you.

Thanks. Morning, team, and thanks for taking my questions.

I wanted to just ask on St. Charles.

Following the completion of the FCC work during the third quarter, could you just talk about how that unit is performing relative to expectations? Then maybe what kind of improvement should we expect in product yields or capture rates as we move into the fourth quarter and beyond?

Then maybe more broadly beyond St. Charles, can you talk about where you're seeing the greatest signals and opportunities to deploy future growth CapEx?

Sure, I'll start with the St. Charles project.

The project came online, and despite the fact that it wasn't fully operational during the third quarter, the EBITDA generated in the third quarter actually exceeded our FID for the project, it's performing very well. As Lane mentioned, a lot of the project is really to fully utilize the alkylation capacity that we have there.

Typically, you would see the greatest benefits from that during gasoline season, we would expect more of a benefit in the second and third quarter than what you would see in the fourth quarter and first quarter.

I'll add to it, this is Lane. In terms of projects that we like, it really is feedstock flexibility.

If you think pre I'm going to say Ukraine invasion, a lot of the to shore up the barrels that were required to fill out U.S. refining capacity was VGO and other intermediates coming from that part of the world.

Consequently, as we went through the summer, even though we had wide margins, there were times when you had to go out and buy spot in VGO, actually your FCC margins were low. One of the buckets that we see opportunity in to make our system a little more resilient is to not be quite so dependent on the VGO out there, find ways to increase VGO production.

As I said earlier, we're optimistic about Venezuela and the Canadian sort of build-out for heavy sour, we'll look at ways to debottleneck our sort of heavy sour capability.

Great. Thank you.

That's helpful. Then just given the significant cash generation that we've seen and then excess cash building on the balance sheet, can you just talk about how you're thinking about potential M&A opportunities here across refining, renewable fuels, and ethanol?

I'll start. We always look at, we've like every earnings call, we look at everything that comes on the market.

We we in particular like our Gulf Coast system. We've we've we've been unapologetic about that.

We think it has the most flexibility and we add the most value when we can actually optimize in our system. We continue to look for opportunities in that in that in terms of on that, and we also like the ethanol business.

We'll continue to look at the ethanol business. Again, we're going to be very, very we're going to adhere to our disciplined approach to capital.

You're not going to see us even though we're sitting on a lot of cash, we're not going to change our approach in terms of our hurdle rates and our return metrics and how we think about, the capital allocation framework that we use that we've been using for the last 10 years.

Yep, that all makes sense. Thank you very much.

good morning, guys. Hopefully, you can hear me okay.

Morning, Doug.

Yep. Hey, guys.

I got a couple of questions on reliability and the elevated refining runs you guys have been able to deliver, not just for Valero, but I guess for the industry. Clearly, maximizing exposure to the current environment, I guess you're showing the market leading by example.

What does this mean for the maintenance cycle, the reliability of your system, and more importantly, the reliability of the industry's capacity to run at these elevated levels? Do you see any risk of unplanned downtime, I guess, as we think about 2027 going forward?

I know it's a generic question, but I'm just curious on your views.

As I mentioned, we haven't really changed anything in terms of our philosophy on maintenance and taking our turnarounds. They're going as planned, and so I don't think you would expect to see anything different in terms of our reliability.

If you do believe the consultant data that says a million and a half barrels of refinery turnarounds were deferred, it does lead you to believe that there could be some unreliability there in a heavier maintenance season next year.

I guess we're hearing a couple of worries emerging from Europe in particular, which is why I asked the question, but I appreciate your perspective. I guess my follow-up is we've obviously got a massive reset in market expectations of mid-cycle.

I'm curious if you can offer any thoughts on how this might impact your view on how you'd return cash to investors, and thinking specifically about if we really are in a higher mid-cycle environment, how would your dividend policy shift relative to, let's say, your share buyback policy? I'll leave it there.

Thanks.

Hey, Doug, it's Homer. I think we look at both the dividend and share repurchases as a component of our total shareholder return.

We do have a higher mid-cycle view for all the reasons that Gary, Randy, and Lane mentioned, but we still operate in a cyclical industry. You're asking about dividend, I think I'll add in theory, a higher mid-cycle increases your debt capacity too, but we're not obviously levering up.

Much like our balance sheet, we want to make sure our dividend is durable, both in good times and bad, and the dividend's obviously a permanent commitment we've made, which we will use and have used the balance sheet to defend, as we did during the pandemic. That wasn't too long ago where our ability and willingness to pay the dividend was challenged.

The dividend is a one-way ratchet. We want to make sure we have some rateable element to dividend growth through cycle.

Then also, we look at dividend yield in the context of our closest peers, and we're kind of right in between both. With all this in mind, we're going to be more rateable on dividend growth, but obviously, ensuring a predictable and attractive total return is a key aspect of our value proposition to our owners, and we'll continue to round out that total payout with share repurchases as a more efficient and flexible means on delivering on that promise over the long term.

Very clear, Homer. Thanks, guys.

Appreciate it.

Yeah.

Hey. I just wanted to go back and revisit the demand destruction discussion for a second, cuz we have seen diesel prices in New York Harbor having a tough time really sustained over $5 a gallon or around $200 a barrel as crude continues to trend higher.

It does seem like maybe at that level, there is some destruction or for whatever reason, it's difficult for diesel prices to move higher. As crude moves higher, there's potential for some compression in the diesel margin.

Is that a risk you see going forward relative to where cracks are right now on the diesel side?

I think that's a fair characterization. We've always felt like one of the things that's benefited refiners during this conflict is the fact that crude really hasn't gotten as expensive as what it could have gone.

If for some reason crude runs up, I do think that it could cause some compression of refinery cracks.

Thanks. My follow-up is just quickly on the M&A comment.

You obviously mentioned you'd want to grow in the Gulf Coast if an asset became available, which makes sense. The North Atlantic, that Quebec market, there's a couple of private assets up there.

Those refining margins have been strong. There's probably some synergies within the business.

Is that another region you would look to consolidate if there were assets that became available and made sense to you?

This is Lane. It's another region that we like.

If something became available and again it met our investment criteria, which again, we want to be disciplined and we want to make sure the thing makes sense for the entire economic cycle and not just sort of get romanced by the prompt situation. It's a region that we feel like we have a really good position in, and if we could add to it and increase our flexibility and our ability to trade around it and create shareholder value, we'd certainly be interested in it.

Great. Thanks for the answers, guys.

We appreciate everyone joining us today. As always, feel free to contact investor relations team if you have any additional questions.

Have a great day.