Valero Energy Stock

Greetings, and welcome to Valero Energy Corp. Third Quarter 2026 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Brian Donovan, VP of Investor Relations. Please go ahead.

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 seems to execute 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 remain focused on execution in running our refineries at near record levels of utilization and helping keep the markets apply with critical transportation fuels.

Our ethanol segment also achieved a quarterly record 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-value 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 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 30, 2026, reflecting the cash build this year. While our long-term $4 billion 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, catalyst, 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 towards 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 million to 1.905 million barrels per day; Mid-Continent at 440,000 to 460,000 barrels per day; West Coast at 100,000 to 110,000 barrels per day; and North Atlantic at 480,000 to 500,000 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 $0.53 per gallon, including $0.23 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 $0.38 per gallon, which includes $0.04 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 2 questions, please rejoin the queue as time permits to ensure other callers have time to ask their questions.

[Operator Instructions] Our first question is coming from Sam Margolin of Wells Fargo.

Question on industry fundamentals, if we could start out 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 in external factors?

Sam, this is Randy. Obviously, remains extremely volatile. We used to get headlines every day, every night about -- around events in the Middle East, and we're obviously keeping a close eye on that on global trade flows. Over the last several weeks, it does look like we are seeing sustained higher flows moving through the Strait. We've seen media sources over the last couple of 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.

So overall, our indications from what we see in the market, both on spreads and trade flows, it looks like the market is pretty well supplied with oil. And as you mentioned, I mean, the main story right now in the market is freight rates. And as the flow through the straight increase, 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 cost, they're all kind of driving the freight higher.

As an example, this extreme run-up in freight, I mean, 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 $5 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. And this is causing severe dislocations in our global crude pricing as refiners seek to keep -- find barrels that are closer to home and sellers are forced to discount barrels to account for the freight cost.

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. And since this crude must price to export, the sharp run-up in freight costs have forced the discounts to widen all grades. Given 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 advantage 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.

Okay. I was going to ask a follow-up on freight, but it sounds like you characterized your position fairly completely there. And so maybe just a follow-up 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. I mean, even if you're just earning a treasury rate on the cash, it's a massive number at this point. And so 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?

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. And so -- in that event, you want to make sure -- like 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.

So in an environment that 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 1 year-plus, we have a little under $150 million that matures later this year and a little over $500 million next year. So we have plenty of flexibility, as you highlighted. And 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.

So in short, we don't have a lot of other uses of cash. So 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 and as we ultimately move back towards our long-term cash target balance of $4 billion to $5 billion. In any event, I think whether margins and cash flow profile of our business remains strong or not, our long-term targets on cash have really not changed. So over time, all the excess cash we're accumulating will ultimately be directed towards our owners.

Our next question is coming from Manav Gupta of UBS.

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 the freight cost accusation, some of your Asian or European peers, they are not doing as well. And again, you are also the low-cost refiner in the world. So 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. So can you talk a little bit about those dynamics, please?

Yes. 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 costs 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 would put even a higher floor on where crack spreads need to go in order to force those refineries to continue to -- run at high utilization rates. And I think the world needs that capacity to be running today.

And 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 us out there?

Yes. 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. In 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. So 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 transitioned out of driving season. And also get the well from higher butane blending with the winter grade gasoline specs. But the underlying gasoline fundamental 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. But 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 pump market is very tight gasoline supply. And I think all of that is 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.

So what that actually could tell you is you could see a surge in demand in the U.K. when you actually have cold weather hit. Export demand for diesel also very, very strong, both for Latin America and Europe. So for us, no indication of demand destruction. And in fact, some of the leading indicators, both GDP remaining flat. And also a lot of the trucking survey is actually ticking up, which would tell you that diesel demand is hanging in there very nicely.

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

And 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 could talk about you're running the system hard in the fourth quarter, I guess, that DHT is back up, too. So that should be a help as you go into the fourth quarter. And 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.

Yes. Neil, so I'll start with the DHT. We really don't expect to have mechanical completion of the DHT until the end of the quarter. So it won't have a -- the DHT won't really isn't in the guidance. We are -- 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 1.5 million 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.

That's helpful. And then just in terms of Q4 considerations, maybe this is for you, Homer or Gary, but just -- we have averaged the start of 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. So any advice for us as we model out the fourth quarter.

Yes. So I think the big tailwinds for the fourth quarter, typically, you get the uplift of the lending butane into gasoline. In our North Atlantic system, you generally have a nice uplift that 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. And then we're starting to see jet rates 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. So overall, I would say, mainly tailwinds when it comes to capture rates in the fourth quarter.

The next question is coming from Theresa Chen of Barclays.

Gary, as we look at the very recent volatility in craft, 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 street? What explains this? And how do you expect these factors to evolve over the near medium term?

Yes. 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. And 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 and more broadly, how do you think the supply shortage of the market would be most effectively addressed?

This is Rich Walsh. I'll try to answer that one. I really think you're focusing in here on Benicia. And so I would just remind you that the status of that refinery is -- it's safely idle 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 materialize anything. It's just a -- it's a tough environment to operate in the West Coast. And we just don't see the potential for that. So -- and the last thing I would just remind you is that the restart that refinery, you would have to reinventory it, you'd have to restaff it, you'd have to undertake a rather extensive turnaround. So it's not a simple process to restart it. So...

Yes. Theresa, this is Lane. I'll add to that. I think as you're thinking broadly, more broadly speaking, almost any refinery has been shut down will take a while to start out. So it would 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. So I'm not saying that, that's not occurring. But I think the idea that it's going to -- there's the refineries that you can just sort of walk in and put the lights and they're going to start running is not exactly the case. But we'll just see what's happening with respect to on a longer-term basis with how this all plays out.

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

In third quarter, we saw a lot of Venezuela upstream investment plans announced in pretty ambitious production growth targets set. So -- 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?

Yes. Phil, this is Randy. We continue to see pretty good availability of then crude in the Gulf Coast system. And 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. And 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. And as a result, we set a new processing record for Venezuelan barrels in the Valero system during the quarter.

As we move into the fourth quarter, we've seen the economic shift some. The higher freight market has especially impacted the heavy crude market. We've seen discounts for Canadian crude in the Gulf Coast widened 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 is very flexible. So our ability to flex between different grades is a big competitive advantage. And 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. I mean, definitely, one of the buckets that we look at in terms of our projects or even acquisitions with respect to the sort of heavy sour position, we feel pretty -- 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 build to run heavy...

Okay. Great. And 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?

Yes. Phillip, this is Eric. I think just as a quick refresher, 2Q had a lot of one-off onetime benefits like IEEPA recovery as well as a lot of modeling updates and year-to-date true-ups. And so you had kind of an unusually high second quarter because some of the onetime 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 creates a lot of noise in margin capture.

So if you look at 2Q, you had feedstocks that we had bought in 1Q that were still much cheaper than the margin indicator. So you have that advantage. And 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 and the positions of how carbon were specifically pricing in that quarter.

3Q, you had the exact opposite. We had the impact -- 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. So foreign feedstocks don't capture PTC. So we had a lower PTC capture than the margin indicator.

And 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 -- as those product cargoes were pricing, we saw a lot of volatility impact hit that lag as well. So it's really all tied up in a lag in the volatility of both and the D4. If I think about 4Q, I mean you still have a structurally high D4 RIN. So we continue to see DGD very positive from a margin standpoint. We see positive cash flow. And I think the real strength of kind of like the refining segment where Gulf Coast is the most advantage from a feedstock availability standpoint, combined with Darling being the largest producer of domestic feedstock. PTC benefits domestic feedstock. So 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. So [indiscernible]

The next question is coming from John Royall of Piper Sandler.

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

Yes. So 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 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.

Yes. Fair enough. And 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 -- with the new PTC or benefit with the 45Z, it's encouraging really all ethanol producers to take a look at higher volumes. And so we are looking at mostly capacity creep. So it's not -- I mean, on a refinery scale, this is not significant capital, and it's very quick hitting capital. But it's small capacity creep. We're continuing to pursue our carbon sequestration projects at a couple of our sites. We are 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. So we continue to see pretty strong export demand for ethanol and our capacity is all pointed at growing exports.

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

On the freight rates, you mentioned the benefits on the crude side in your Gulf Coast system. We have two follow-ups here. So one, are these higher freight rates, the headwind to your North Atlantic and West Coast refineries? Or are you able to use like substitute crude? And 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 point on the economics for U.S. product exports?

Yes. This is Gary. For the most part, the higher freight rates actually give us an advantage into the typical export markets into 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 exports, the diesel exports go into Europe. And 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.

Yes. On the crude side, this is Randy. We do have some exposure to the higher freight at our Pembroke refinery into the West Coast. And to a smaller extent, into Quebec City, even though that refinery is mostly supplied via pipeline. 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. And 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? And then what are you thinking on potentially Russia diesel exports picking up here?

Yes. This is Gary. I think 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 off-line in Russia. So 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 600,000 to 700,000 barrels a day below where Russia was last year at this time. So it's not a significant volume. And as we've always stated, really the sanctions or lifting of sanctions just result in change in trade flows, not really incremental supply coming on to or off of the market.

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

So I wanted to just ask on St. Charles. So following the completion of the FCC work during the third quarter. Could you just talk about how that unit is performing relative to expectations? And then maybe what kind of improvement should we expect in product yields or capture rates as we move into the fourth quarter and beyond? And 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. Yes, 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. So 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. And so typically, you would see the greatest benefits from that during gasoline season. So 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.

Yes. And I'll add to it, this is Lane. I mean in terms of projects that we like, it really is feedstock flexibility. If you think pre- -- I'm going to say Ukraine and -- a lot of the to shore up the barrels that are required to fill out U.S. refining capacity with BGO and other intermediates coming from that part of the world. And so consequently, as we went through the summer, even though we had wide margins over time when you had to go out and buy spot in BGO, you're at to your SCC margins are low. So one of the buckets that we see opportunity in is to be a little more to make our system a little more resilient as not be quite so dependent on the VGO out there, so find ways to increase VGO production. And I said earlier, we're optimistic about Venezuela and the Canadian sort of build-out for heavy sour, so we'll look at ways to debottleneck our sort of our heavy sour capability.

Great. That's helpful. And then just given the significant cash generation that we've seen in 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, in particular, like our Gulf Coast system. 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. So we continue to look for opportunities in terms of on that. And we also like the ethanol business. We'll continue to look at the ethanol business. But again, we're going to be very, very right here 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.

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

I got a couple of questions on reliability and the elevated refinery 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 as your -- 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 was a generic question, but I'm just curious on your views.

Yes. So as I mentioned, we haven't really changed anything in terms of our philosophy on maintenance and taking our turnaround. 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 1.5 million barrels of refinery turnarounds were deferred, it does lead you to believe that there could be some reliability there and 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 and market expectations of mid-cycle. I'm curious if you can offer any thoughts on how this might impact your view on how you 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? And I'll leave it there.

Doug, it's Homer. I mean, 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, like, in theory, you 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 is 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. So the dividend is a one-way ratchet. We want to make sure we have some ratable element to dividend growth through cycle. And then also, we look at dividend yield in the context of our closest peers, and we're kind of right in between both. So with all this in mind, we're going to be more ratable 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.

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

I just wanted to go back and revisit the demand destruction -- discussion for a second because 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. So 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. And so 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?

Yes, 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 very -- as expensive as what it could have gone. And so if for some reason, crude runs up, I do think that it could cause some compression of refinery cracks.

Yes. My follow-up is just quickly on the M&A comment. You've obviously mentioned you'd want to grow in the Gulf Coast if an asset became available, which makes sense. But the North Atlantic 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?

Yes. This is Lane. So as long -- it's another region that we like. So if something came available, and again, it met our investment criteria, which again, we're going to be disciplined, and we want to make sure the thing makes sense to the entire economic cycle and not just go to get romanced by the prompt situation. But 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.

Thank you. This brings us to the end of today's question-and-answer session. I would like to turn the floor back over to Mr. Donovan for closing comments.

Yes. We appreciate everyone joining us today. And as always, feel free to contact the Investor Relations team if you have any additional questions. Have a great day.

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.

Greetings, and welcome to the Valero Energy Corp. Second Quarter 2026 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Brian Donovan, Vice President of Investor Relations. Thank you. You may begin.

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 3 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 segment also performed well, supplying additional liquid fuels to the market.

On the financial side, our strong balance sheet remains a hallmark of our capital allocation framework. In addition to building cash during the quarter, we continue 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 output and finished gasoline.

Looking ahead, we continue to see a constructive environment for our business. Refining fundamentals remain supported by low global product inventory, limited excess refining capacity and resilient demand for transportation fuels. U.S. 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 crude. Our strategically positioned and highly competitive asset base is also well suited to supply constrained global products market.

In closing, our strong results reflect the disciplined 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 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 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 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 remain 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. And 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 billion to $5 billion cash target to preserve optionality in a volatile market environment while also exceeding our minimum payout commitment. And 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 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 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 million to 1.83 million barrels per day; Mid-Continent at 460,000 to 480,000 barrels per day; West Coast at 110,000 to 120,000 barrels per day; North Atlantic at 450,000 to 470,000 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 $0.49 per gallon, including $0.21 per gallon for noncash 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 $0.39 per gallon, which includes $0.04 per gallon for noncash 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 2 questions. If you have more than 2 questions, please rejoin the queue as time permits to ensure other callers have time to ask their questions.

[Operator Instructions] Our first question comes from the line of Neil Mehta with Goldman Sachs.

Obviously, an extraordinary quarter. I think a lot of us remember when $4 your mid-cycle EPS and doing $12 in a quarter is pretty extraordinary. And the kind of -- we're not quarter-to-quarter folks here, but as we think about bridging 2Q to 3Q, we just love your guys' perspective. We just look at Gulf Coast indicators, they're up from $30 to $41 on your database. But the shape of the oil curve is probably more favorable with dated Brent versus your month 1 Brent no longer being in such a steep backwardation. So 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.

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 has 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. But 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. So 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.

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

Yes, 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? So the risk that we're trying to address is when you have a rapid pullback in commodity prices, particularly crude, you tend to -- 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.

But that said, because of the current environment we're in, coupled with the 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. I mean 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 2 businesses, ethanol and renewable diesel. And in this environment, I think building cash and shareholder returns don't have to be mutually exclusive.

So 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 billion to $5 billion. Long answer, but hopefully helpful context for you.

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

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. And 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?

Yes, 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 using -- that you would get calculating historic margins, product crack spreads were largely set by cracking margins in Northwest Europe. And as supply and demand balances have tightened, it appears that refinery crack spreads are now really being set by hydroskimming margins in Northwest Europe.

So 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 cost of carbon credits which drives those cracks higher as well as inflationary pressures on both OpEx and CapEx that will result in the 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 has a very positive impact on our future mid-cycle view as well.

And 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.

Yes, Theresa, this is Eric. I think if we start with DGD and renewable diesel, you see the -- 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. And so as we look at that going forward, we still see 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.

So we see RD looks more positive for the rest of this year and into '27. And 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 $0.14 year-to-date probably $0.17 for the full year. And if you look into '27 through '29, it's probably $0.19 a gallon. You put that in perspective with the historical mid-cycle of $0.25, that says that you're almost doubling the value of ethanol through 2029. So 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 in short of the fuels and seeing a lot of volatility.

Our next question comes from the line of Manav Gupta with UBS.

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 question on what -- kind of relating to refining macro. So 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. And 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 shutdown that we are having.

And 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. I'm assuming you're still in max diesel mode, but gasoline cracks are much stronger. So 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.

Manav, I'll try to go through those. So yes, I think we agreed about 5 million barrels a day of refining capacity is off-line. 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 remained 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 the reopening of the Strait. 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 will take a longer time to come back on. And then as you mentioned, the Ukranian 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 U.S. is closed. In addition to that, we see good export demand for gasoline in the Latin America. So the combination of the closed arb import barrels from Europe open-arb export barrels of Latin America has a net gasoline import that's down about 400,000 barrels a day from where it historically is. So that, combined with a good domestic demand is really what's leading to the relative strength in gasoline.

Our next question comes from the line of Sam Margolin with Wells Fargo.

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

Yes, Sam, it's Lane. What I would say is post-COVID we were -- we would had been at about $1 billion post-COVID on strategic spending. And that was really capped by, I would say, our project execution efficiency. Post COVID, we've been about $0.5 billion on average, maybe creep up to $0.7 billion, a lot of which -- if you look back at it was renewable spend. So we sort of carry renewable spend down because the sort of policy isn't super supportive and we're trying to let the renewable business sort of catch up with policy and some of the other things that are happening. So really our spend 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-cycle going forward. But we -- the projects we like in refining obviously, are more around 2 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 things that were potentially long and trying to get rid of those and then where we have a chronic short -- I think it's one of the examples I used in the past the whole United States is short of VGO and so we're trying -- we'll look through and find the projects that make sense for us to sort of improve our overall commercial leverage in that space.

We have higher -- like I said, we have a higher mid-cycle look going forward for that. But we're not going to lose our discipline with respect to our capital and how we're going to spend money. But with that said, Gary kind of touched it the higher cost of these projects also puts sort of a lower -- it supports the higher mid-cycle as well. There's a lot of things here supporting a higher mid-cycle in refining.

Okay. And 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. And now that may be a little different because you have Venezuela that's growing volumes into the U.S. 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? SP999

Well, yes. I would just be -- we don't try to provide too much, I would say, strategic specific projects. I will say we see the same thing. We see that -- we see a forward world, whether it's more Canadian heavy, there's more Venezuelan. That helped our current asset base. If you think about what I said earlier with respect to the -- how I would like to improve our position with respect to BGO and maybe not quite so much naphtha-rich crudes, that's -- I'd like to see projects sort of in that incrementing crude in that space for sure.

Our next question comes from the line of John Royall with Piper Sandler.

So my first question is just a follow-up on DGD margins and specifically looking at the July 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. And 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. And just to confirm, when feedstock prices are coming down, we should expect to capture headwind there in 3Q. Just wanted to confirm that.

Yes, 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 be -- have above expectations in terms of crop yields, and that's globally, not just in the U.S. So that you see length in corn, you see length in soybeans and the U.S. 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 U.S. 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. So 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. But 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. And 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 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. So just wondering what the market for Mexican crude looks like today.

Yes. So I'll start with Venezuela. I mean -- this is Randy, by the way. Yes, 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 U.S. 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 asset crude is a key competitive advantage for our system. But 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. And down in Mexico, right now, their exports have -- they are down compared to last year, mainly due to higher refinery runs at the start of the dose focus. But we do see this pretty volatile month-to-month that -- so as the refining system runs higher, their exports are obviously lower. So we see that trend likely continuing going forward.

Our next question comes from the line of Joe Laetsch with Morgan Stanley.

So 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 in Wilmington. So maybe you just how that asset is performing and competitiveness of it currently relative to the rest of the portfolio.

And 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. That's been exacerbated by the idling of the San Pablo pipeline. It moves crude into the Bay Area, forcing more of these domestic barrels are clear to the refineries in L.A. With these logistic bottlenecks, we have seen prices for California crude weakened considerably, and we've been working with our Wilmington refinery to increase processing rates of these barrels and anticipate any 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 yet 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. And so those premiums into the export market also helped our capture rates as well.

Great. And then could you just talk a bit about the impact of policy changes that we've seen recently. So 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 U.S. Would you expect this to continue to be extended?

Well, 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 supply. Also with the transatlantic arb close to send gasoline from Europe to PADD 1. And the Jones Act waiver has been very critical keeping PADD 1 supplied as well.

Our next question comes from the line of Doug Leggate with Wolfe Research.

I seem to recall having a discussion with Homer about net debt 0 not so long ago, and it seemed unrealistic. So extraordinary times indeed. But my question, I've got 2 things I wanted to bring up, if you don't mind. First of all, we're just sitting here watching extraordinary margins. We don't know what the duration is. But you've got practically no net debt. I think you're kind of signaling our 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?

Doug, it's Homer. I mean 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. And Lane obviously talked about the discipline we're going to have around growth investments, right, with the minimum return threshold, acquisitions we've talked about, they have to have good strategic value, right?

And so -- 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 flushing 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? And so keep in mind, that includes all sustaining capital, not just growth capital. So that tells you our growth projects that have actually returned well in excess of that. So absent those uses, we're clearly not just going to have cash sit on our balance sheet, given, as you highlighted, are 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%. And even at a higher share price, buyback sort of better use of cash than the alternatives I've talked about, especially given the fact that we're talking about excess cash here.

On the dividend, obviously, we want to make sure that most important, it's sustainable through cycle. We also look at our dividend yield relative to our closest peers, and I think we're competitive there. And 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 the cycle. So I think you can expect our actions to be consistent with all of that.

That's all very fair. And I appreciate the answer more. 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 are -- obviously, we all know what's been going on in the Middle East. But 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.

And one of your peers the other day talked about the black swan or the wildcard of China came back into the market. So Gary, I wonder if you could just walk us through what your intelligence is telling us on those 2 dynamics because they seem to be pretty impactful to this near-term margin strength that we've seen just in the last couple of weeks?

Yes, 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. So 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 certainly had an impact as certainly some locations in South America that were pulling Russian diesel have come to the U.S. Gulf Coast to pull the diesel which has caused prices to escalate.

I think the other thing that's happened, as you know, earlier in the year, you just saw such deep backwardation in the diesel market. that it made export arbs difficult. We had high freight steep backwardation which made exports more challenging. And you had buyers who are wanting to sit on the market with the hope that we're going to be able to buy their resupply cheaper in the future. And as we get closer to the 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. The combination of that with the further disruption in Russia is really what's caused the strength in diesel prices.

Our next question comes from the line of Phillip Jungwirth with BMO Capital Markets.

First half turnaround CapEx ran about $374 million, which is pretty low relative to the $1 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 their ability to push some of these out? And then just what's driving the lower first half spend to help frame a go-forward run rate?

Yes. So 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 really is important to execution to keeping those dates kind of set. So nothing different there. And 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.

Okay. Great. And 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 you think is needed to support investment in the new refinery.

In terms of the new refinery, that number I don't have in front of me. It's -- 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.

Our next question comes from the line of Paul Sankey with Sankey Research.

Homer, I appreciate that you're a CFO with a major problem of too much cash. The -- if I could just ask a couple of questions, which may be more industry-oriented. The first, you mentioned that feedstocks have been really a big driver between high product prices and feedstocks, I guess. And 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, it's more like $0.5 million. I just wondered, and I know this is not a Valero specific issue, more of an industry observation, what you're understanding about how the SPR will continue to draw down from here?

And secondly, again, on the kind of industry observation, and I know you won't comment on the side but for Valero specifically. The refineries in the U.S., 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.

Paul, this is Randy. I'll start on the SPR question. I think when -- back in March, when Trump announced the release, it was 172 million barrels from the U.S. SPR and we believe what's been committed and contracted so far is more like 130 million. So 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 it, it's 300 million or if it's 70 million. 300 million sounds a bit high, 70 million sounds a little low to us. But it's -- right now, it's difficult for us to say kind of what the minimum volume may be that they can draw the same down too.

Yes. 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.

Our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt & Company.

Do you see the RIN market in shortage this year? And if so, can you talk about the implications to your various businesses? If that was the case, it seems like RD profitability to be quite robust in the back half of the year. But then from the refining side, is there any concern that you would not be able to procure enough RINs to meet compliance in 2026?

This is Eric. So 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. And so we see that as structurally keeping the D4 RIN high.

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 and feasible. And it could. I mean, at some point here with the way the RVO is and the amount of production that is the concern.

I mean the only thing I would add on is some of this is going to be driven, at least on a policy side by impact to consumers, right? So if you -- you think about the way we think about it, the rent is in the crack, and that ultimately gets pushed on to consumers. And so it really becomes an affordability issue, right? And so when and if EPA takes action, we'll really probably be driven on how much this actually impacts consumers. So otherwise, I mean we're well positioned on it.

Sounds good. And then I think you mentioned that you're working on some ethanol expansions. Can you share any sort of numbers around that, either like percent capacity growth or the 1 million-gallon expansion number. And then on the R&D side, are you also looking at like small debottlenecking projects or any sort of RD expansions?

Yes. So ethanol, we are looking at small to bottleneck projects to the extent of 100 million 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.

Our next question comes from the line of Connor Fitzpatrick with Bank of America.

So I 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 U.S. So I was just wondering what do you think is the biggest source of change for supply going forward? How do you -- in the event that we do balance the market soon? Where do you think the incremental gallons will come from.

Yes, 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 have the $1 blenders tax credit. And so foreign imports came in to capture that do, 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. And so 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. So 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. So 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 it's -- that is, I think, the main reason why we have not seen foreign imports pick up as rapidly as everyone expected.

Our next question comes from the line of Jason Gabelman with Cowen.

I want 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. So 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 it will be down for an extended period of time?

Yes, Jason, this is Gary. The only thing I could tell you is currently about 1.7 million to 1.9 million barrels a day of Russian capacity offline. If you look at the trend from May to June to July has gotten progressively worse, not better. And then what you hear is that Ukraine is now targeting in critical pieces of equipment where before they were shooting tanks. And so 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. So 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.

Okay. Got it. My follow-up is on U.S. policy. And the administration has done a number of things to try and reduce the amount -- the cost that consumers are paying at the pump, Jones Act, RVP waivers. Are there other kind of levers that the administration has and anything incremental you're hearing from them on a potential product export quota or ban.

This is Rich. I'll make an effort at answering that. I mean 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. So 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. And we believe they're looking through for the ones that are really viable and work.

And the Jones Act that you highlight is actually a really critical one. I mean that's pretty strong Jones Act commitment -- waiver commitment here from the administration, and it's kept the West Coast and the East Coast wet. And I think it's really maximize the U.S. as refining capacities out of the Gulf and allowed it to be shared to the other regions. So I think that's probably been 1 of the most critical ones.

There are other things that we are concerned about. There's 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 [indiscernible] gasoline, it already has. And so -- and then these uplifts and cracks that are caused by these SREs and the misallocation of misalignment that comes out of that is a problem.

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

We have reached the end of the question-and-answer session. And therefore, I would like to turn the call back over to Mr. Donovan for closing remarks.

Yes. I 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.

Thank you. This concludes today's conference, and you may disconnect your lines at this time. Thank you for your participation.

Greetings, and welcome to Valero Energy Corp. First Quarter 2026 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Brian Donovan, VP, Investor Relations. Thank you. You may begin.

Good morning, everyone, and welcome to Valero Energy Corporation's First 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; Harminder 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 [indiscernible] with the release or supplemental tables providing detailed financial intention for each of our businesses along with reconciliations and disclosures for any adjusted financial metrics referenced during todays call.

If you have questions after reviewing these materials, please feel free to reach out to our Investor Relations team. Before we begin, I'd 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. I'm pleased to report that Valero's an excellent first quarter, demonstrating our team's ability to optimize our refining system and deliver strong financial returns. In a period marked by considerable disruption in the commodity markets, our operations and commercial teams executed well.

Early in the quarter, the availability of incremental Venezuelan supply resulted in wider crude differentials. Our advantaged Gulf Coast refining network was well positioned to benefit from the discounted heavy tower feedstocks. Market conditions shifted sharply in March as the global supply of crude and refined products tightened. Our operations team responded decisively adjusting the product slate to reflect market signals, delivering a record month with [indiscernible] At the same time, our commercial and financial team proactively manage commodity risk to mitigate unique adverse impacts of a highly dynamic pricing environment.

Financially, we maintained a strong balance sheet while continuing to honor our commitment to shareholder returns. On the strategic front, we continue to make progress on the FCC unit optimization project at our St. Charles refinery.

The $230 million initiative will enhance our ability to produce high-value products, including [indiscernible] We expect the project to begin operations in the third quarter of 2026. Looking ahead, constrained global refining capacity and low product inventories in key markets should continue to support refining fundamentals.

Our concentration on high complexity [ Cofor ] refinery provide significant feedstock flexibility and direct access to global markets, which are especially beneficial in the current environment. Additionally, our disciplined financial strategy and capital allocation framework position that performed well across market cycles.

In closing, our strong performance in a volatile first quarter and [indiscernible] of operational, commercial and financial crime. Remain focused on things we can control: operational excellence, system-wide optimization and disciplined financial decision-making. Consistent execution across these priorities positions us to benefit from the current margin environment, and will continue to differentiate Valero.

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

Thank you, Lane. For the first quarter of 2026, net income attributable to Valero stockholders was $1.3 billion or $4.22 per share compared to a net loss of $595 million or $1.90 per share for the first quarter of 2025. Excluding the adjustments shown in the earnings release tables, adjusted net income attributable to Valero stockholders for the first quarter of 2025 was $282 million or $0.89 per share. .

The refining segment reported $1.8 billion of operating income for the first quarter of 2026 compared to an operating loss of $530 million for the first quarter of 2025. Adjusted operating income for the first quarter of 2025 was $605 million. Refining throughput volumes in the first quarter of 2026 averaged 2.9 million barrels per day, refining cash operating expenses was $5.13 per barrel in the first quarter of 2026.

The renewable diesel segment reported operating income of $139 million for the first quarter of 2026 compared to an operating loss of $141 million for the first quarter of 2025. Renewable Diesel segment sales volumes averaged 3 million gallons per day in the first quarter of 2026. The ethanol segment reported $90 million of operating income for the first quarter of 2026 compared to $20 million for the first quarter of 2025.

Ethanol production volumes averaged 4.6 million gallons per day in the first quarter of 2026. G&A expenses were $285 million for the first quarter of 2026, Depreciation and amortization expense was $840 million for the first quarter of 2026, which includes approximately $100 million of incremental depreciation expense related to ceasing refining operations at our Venetia refinery.

Net interest expense was $140 million and income tax expense was $401 million for the first quarter of 2026. The effective tax rate was 23%. Net cash provided by operating activities was $1.4 billion in the first quarter of 2026, included in this amount was a $303 million unfavorable impact from working capital and $102 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 $1.6 billion in the first quarter of 2026. Regarding investing activities, we made $448 million of capital investments in the first quarter of 2026, of which $404 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance and the balance looks 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 $430 million in the first quarter of 2026.

Moving to financing activities. We remain committed to our disciplined capital allocation framework. Shareholder cash returns totaled $938 million in the first quarter of 2026, resulting in a payout ratio of 59% for the quarter. And on January 22, our Board approved a 6% increase to the quarterly cash dividend, reflecting a strong financial position and our commitment to a growing dividend. Turning to the balance sheet, in March, we opportunistically issued $850 million of 10-year notes at a 5.15% coupon to derisk upcoming debt maturities later this year.

The notes priced at a refining sector, record low 10-year spread of 102 basis points over treasuries. At quarter end, we had $9.2 billion of total debt, $2.3 billion of total finance lease obligations and $5.7 billion of cash and cash equivalents. Our debt to capitalization ratio, net of cash and cash equivalents was 18% as of March 31, 2026.

Our cash balance was higher at quarter end, reflecting the opportunistic timing of the March debt issuance and our decision to move towards the high end of our long-term $4 billion to $5 billion cash target to preserve optionality in a volatile market environment.

Overall, we ended the quarter well capitalized while still honoring our commitment to shareholder returns. Turning to guidance. As we operate the [ Praca ] refinery at reduced rates, we continue to assess the full extent of the damages and develop a plan for repairs. We expect the incident to result in additional capital expenditures in 2026, which should be covered by insurance subject to our applicable insurance deductibles.

We'll update our 2026 capital investment guidance when we are able to provide a definitive cost estimate and expected repair time line. Outside of [ Poor Arthur, ] our previous guidance regarding capital investments for sustaining the business and growth projects remains unchanged. Our growth 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 second quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.69 million to 1.74 million barrels per day, reflecting reduced rates at Port Arthur, Mid-Continent at 450,000 to 470,000 barrels per day West Coast at 120,000 to 130,000 barrels per day, reflecting the idling of Venetia and North Atlantic at 480,000 to 500,000 barrels per day.

We expect refining cash operating expenses in the second quarter to be approximately $4.85 per barrel. For the renewable diesel segment, we expect sales volumes of approximately 320 million gallons in the second quarter. Operating expenses should be $0.46 per gallon, including $0.22 per gallon for noncash costs such as depreciation and amortization.

Our ethanol segment is expected to produce 4.7 million gallons per day in the second quarter. Operating expenses should average $0.39 per gallon, which includes $0.04 per gallon for noncash costs such as depreciation and amortization.

For the second quarter, net interest expense should be about $145 million. Total depreciation and amortization expense in the second quarter should be approximately $730 million which includes approximately $33 million of incremental depreciation expense related to our plan to idle the processing units and cease refining operations at our [ Venetia ] refinery completed this month. We expect incremental depreciation related to the [ Venetia ] refinery to be included in DNA through April. The second quarter earnings impact of this incremental depreciation is expected to be approximately $0.09 per share based on current shares outstanding.

For 2026, we expect G&A expenses to be approximately $960 million.

Thanks, Omer. That concludes our opening remarks. Before we open the call to questions, please limit each turn in the Q&A to 2 questions. If you have more than 2 questions, please rejoin the queue as time permits to ensure other callers have time to ask their questions. .

[Operator Instructions] Today's first question is coming from Manav Gupta of UBS.

Guys, very strong quarter considering everything else that we are seeing out there. I just quickly wanted to pivot to the global refining macro, and I'm trying to understand as these prices are rising, Gary, if you or somebody could comment as to what you're seeing for demand out there, are you seeing any early signs of demand disruption in your system?

Yes, Manav, this is Gary. Despite the fact as you alluded to, the prices for transportation fuels are moving higher, it appears that especially domestic demand appears to be very resilient. If you look at our wholesale volumes year-over-year, we do show a reduction in sales volumes in our system.

However, this isn't really a reflection of demand, but it's a result of idling the Venetia refinery and then we exited a position in the Boston market. So when we look at sales, we would say U.S. demand for gasoline is flat to slightly up. Diesel demand is up a little and that seems to be consistent with what you're seeing in the DOEs as well with the DOEs reflecting really increases in demand, both gasoline, diesel and jet.

Really, the big change in demand year-over-year is the pull into the export market since the conflict in Iran. The recent DOE data shows exports from the U.S. are up 470,000 barrels a day year-over-year. the pull into the export market is causing inventory to draw in the U.S.

So relative to the 5-year average, total light product inventories in the U.S. have drawn 30 million barrels since January. Distillate inventory is at 5-year lows. Domestic demand remains strong for diesel with good agricultural demand as we start Atlantic season. And then the freight indices are beginning to improve a little.

And then the export demand for distillate, especially jet has been very strong with interest for U.S. Gulf Coast barrels from all over the world. As we approach driving season, gasoline inventory now at the bottom of the 5-year average range, the transatlantic arb to ship to PADD 1 from Europe is closed. Both domestic and export demand remained strong. The Jones Act waiver is allowing us to supply PADD 1 and PADD 5 more efficiently from the U.S. Gulf Coast. And I think as we approach driving season, VGO availability will start to become an issue. It doesn't appear there's sufficient VGO to fill both FCC and hydrocracking capacity. Current economics would favor hydrocracking, which could reduce gasoline production moving forward.

I think you have read a lot about global demand destruction since the traits have been closed. It really appears to us that this isn't really demand destruction that's more insufficient supply to meet demand. our expectations coming into the year was that new capacity additions, along with more bile renewable fuels on the market would be sufficient to meet incremental demand.

We thought supply/demand balances would be similar to last year, and then you start to see a tightening at the end of this year. But the conflict in an has really created a market with demand significantly outpacing supply. We had very little excess refining capacity globally. So it's going to be difficult to restruck inventories even when the conflict is resolved.

Perfect. You kind of alluded to it, so I just wanted to confirm this. So look, as you look into the next at least 6 or 9 months, you have some refiners like Valero who can run as the fish. And then there are some refiners, they may have a good kit somewhere globally, but they can't run because they don't have enough crude.

I'm just trying to understand, within your refining system, sir, are you able to source any crude that you're looking for and run all out if you want to?

Yes, Manav, this is Randy. I think the short answer is yes. I mean most of our systems is located kind of in the Mid-Continent and Gulf Coast. So crude availability is really not much of an issue. I think as we've seen in the stats this week, the U.S. has become a major exporter of crude and that's been amplified by the SPR release.

So any exports out of the U.S. have to overcome high freight and pretty steep backwardation -- so I mean we're always kind of optimizing our crude slate in the Gulf Coast. And this time, kind of no different. Just the volatility on price and freight have been more extreme than normal.

With the high freight costs, we have made some changes in our system by cutting back waterborne crews, running more pipeline. In addition, more SPR volume that's on the market, we purchased more of that grade just kind of optimizing against other crudes.

And since the start of January with the Venezuela sanctions removed, heavy discounts were already very advantage for our system. And we were already kind of pointing our refining system to run MAX heavy sour crude. Since the Iranian event started, those trends will only continue. Canadian heavy crude today is trading like a $16 discount versus TI in the Gulf. So the location of our system in the Gulf Coast makes it a pretty advantaged backdrop there.

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

Yes. Really solid results. Not to focus too much on quarter-to-quarter stuff. But when you think about the second quarter indicators, they're already showing on the Gulf Coast versus Q1 levels, which were $18 and it really harkens back to the second quarter of 2022.

And at that point, your share count was kind of closer to $400 million today, it's closer to $300 million. So maybe this is a question for Homer. But as we start thinking about modeling out Q2 here, any pluses and minuses that we should sort of be thinking about and anchoring to and anything about March profitability that can give us a sense of what Q2 could shape up like.

Yes, Neil, I think if you look to the second quarter, definitely some headwinds and tailwinds Certainly, the steep backwardation in the crude market is a headwind. In addition to the backwardation, when you see the physical markets disconnect from the futures, it's also difficult to see.

It becomes very complex to look at what that's going to do to capture rates. But in terms of tailwinds, certainly, the heavy sour discounts our system be able to maximize heavy sour crude is a tailwind. The premium regrade for jet fuel is a tailwind as well as premium for secondary products. So a lot of pluses and minuses as we move into the second quarter.

All right. Well, one specific product want to dig into with Jet, Gary. I mean there's a lot of talk about the potential for shortages in parts of the world. How are you just thinking about that product in general, how you can maximize your production of it? Where are you trying to get it to? And are these concerns about jet availability globally founded or unfounded? .

Yes. So to start with, I would say they are found at Jet is incredibly short. We've been trying to maximize jet in our system Typically, if you look at Jet as a percentage of total distillates that's a number that averages about 26% in our system. In March, we got that up to over 30%, yet as a percent of total distillates. In addition to that, we have a couple of refineries that don't make Jet today that we're moving into jet production mode to try to increase jet yields even further as we go forward.

Our next question is coming from Theresa Chen of Barclays.

This order has highlighted the earnings volatility that a refiner shelf face and the range of outcomes have been wide in part due to different commercial and financial strategies. But despite operating in the same macro environment, your results appear to have been less volatile.

And from your perspective, I'm curious as to what you think has enabled that. Does it reflect differences in crude sourcing, product placing or hedging strategies or something else structural in the business. And relatedly, this environment is also stress testing the balance sheet and leverage thresholds across the sector.

You've chosen to maintain a relatively elevated cash position to Homer's earlier point in the prepared remarks. How are you thinking about that capital strategy today, particularly as a buffer against the volatility .

Theresa, it's Homer. I mean, let me start on the risk side and hedging specifically. Under normal market conditions, -- our approach can be more formulaic and process-driven where we basically manage our exposure above or below Lifewire derivatives positions. But when we started seeing higher volatility in both crude and product markets, our team met frequently daily to review our positions, and we were just more proactive in managing our exposure.

For example, we maintained our inventory positions much closer to LIFO. So that reduced our overall exposure to derivatives and associated price swings, right? And then in addition to that, that also ensures that you don't have a significant draw on cash for margin calls. And you can see that we had minimal impact on that through working capital.

To your second point around cash, we did move our overall base cash position towards the high end of the $4 billion to $5 billion minimum cash balance that we talked about. This is why we moved to a higher cash balance really after the pandemic, right, to ensure that our liquidity never ever comes into question.

And while we didn't have a huge cash flow draw, hopefully, this highlight this quarter highlights the value of the higher cash balance. So our cash balance, coupled with our bank facilities, we ended the quarter with almost $11 billion of total liquidity. So we're really well positioned for whatever the rest of the year brings.

The last thing I'll mention is separately, we were also proactive, as I mentioned in the opening remarks, and we opportunistically pre-finance or upcoming maturities for the balance of the year. So we saw an attractive window to derisk that part of the balance sheet, and we were able to do that at a record low spread.

So we just try to be proactive on every financial aspect of our business, whether that's risk or balance sheet or shareholder returns.

And shifting gears, how should we think about the trajectory of DGD profitability going forward? -- considering current macro conditions, feedstock considerations and regulatory changes that we've seen recently.

Yes. This is Eric. Home did a great job explaining the risk management structure for DGD is a little bit different. And so the mark-to-market that we have on our forward feedstock positions will be a little bit of a headwind if we see the underlying commodities continue to rise like we did for the last month or so.

So that being said, the RVO is a pretty strong tailwind. We see a lot of higher margins, certainly higher in 2Q than in 1Q and overall, a better '26 versus '25.

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

So as we look beyond the middle disruption. Can you just talk about how you see the supply-demand balance shaping up over the next couple of years? It seems like the balance was already pretty tight before the disruption and now there is refinery damage and the need to replace inventories to contend with. Does this change how you think about mid-cycle margins going forward?

Yes. So I don't know that it will change our approach to mid-cycle margins. We take a fairly conservative approach because of our distinction capital investment we'd like to take a conservative mid-cycle because we use it to justify the capital. But certainly, it will create a market that's very tight.

I think even before the conflict started, our view was starting at the end of this year. Global demand would outpace new refining capacity additions, and we have several years of tightness. That has brought that all forward with the situation that's happened.

In our view, if you look at the lost total light product production that's happened since the strains have closed, it takes a minimum of at least 3 days to rebuild stock for every day that the straight have been closed.

So at this stage, it's at least 6 months to a year to start restocking inventories back to where they were. There's just not a lot of excess refining capacity out there. And then as we move forward in global demand continues to grow, it makes that situation even tighter.

Great. That's helpful. And then on Port Arthur, I recognize you're still going through the assessment. But to the extent you can, could you just talk through the refinery damage assessment process and potential restart time line? And what are the signposts that we should be watching for from the outside here?

Yes. So on March 23, we had a fire in the diesel hydrotreater Port Arthur. The entire refinery was shut down as a precaution. All employees were accounted for no refinery reportable injuries as a result of the incident. .

The investigation into the cause is ongoing, so I can't share too much around that. But our operations team did an excellent job getting the smaller crude unit train back up early April. Along with the coker, hydrocrackers and the reformer and distillate hydrotreater. We're currently starting up the larger crude unit as we speak, along with the FCC and alky so we would expect by May 1 that throughput looks fairly normalized at the Port Arthur refinery.

The diesel hydrotreater that experienced the fire along with an adjacent kerosene hydrotreater do remain down which could negatively impact capture rates some in the second quarter. We expect to get the kerosene hydrotreater back by the third quarter. The diesel hydrotreater did sustain extensive damage.

We don't have a time line for the rebuild yet on that. But as Homer mentioned, the throughput guidance, all of that is reflected in our throughput guidance for the quarter.

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

I think you might have just answered part of my question here. Thanks for having me on. I'm trying to understand what's going on with physical crude impact on capture rates. And if I can kind of walk through the thought process here, we saw Maya, saw cut their K factor in half.

We're seeing dated Brent, obviously, a big premiums. And now apparently a flotilla of tankers coming to the U.S. Gulf Coast, perhaps putting a bit under TI. So I'm just curious, when you look at your slate -- how is the physical set of the crude market impacting the capture rate?

And if I may, my follow-up is specifically for Homer. You got -- Homer got probably one of the best balance sheets, if not the best balance sheet in the sector, which means you don't have a lot of options for your surplus cash. And my question is that your valuation today, if you sort of look at the implied free cash flow forever, not the windfall we have now is north of $7 billion at a 10% discount rate.

How do you think about your valuation in the context of what you do with that cash as it relates specifically to share buybacks?

Doug, I'll start on the crude side. I mean, for the most part, as Gary mentioned before, part of the headwind on capture is on the backwardation. It is in the market, the steep backwardation. I mean it some highs last month at 11% to 14%. It's into the $6 range now and has moved higher over the last couple of days. .

As I look kind of in the capture, I mean some of the grades are already included in the pure calculation, so it's already reflecting some of that movement in the capture calculation. But outside of that, I mean, there's things that we're doing that's not captured in it, it's Venezuelan purchases.

Since the January sanctions removal, we've meaningfully ramped up Venezuela runs in our systems and all that done at better economics in our alternative on heavy tower and as we've touched on before, the heavy grades in the Gulf Coast continue to look very, very attractive for our system.

Doug, this is Homer. Thanks for your comment on the balance sheet. But I think your comment on annuitizing current margins, there's no doubt current margins are good. But as you can tell by our results, we put ourselves in a really good position to take advantage of that, right? And we're not hanging our strategy on just the current margin environment.

Obviously, we continue to optimize and grow the business. But we're doing that with discipline around minimal return thresholds, and we're using a longer mid-cycle price set, as Gary highlighted earlier. We also continue to work hard to manage our costs, and all of this puts us in a great position for shareholder returns.

And with respect to buybacks, I think you have to start by understanding that share repurchases are really in efficient and flexible means of returning excess cash to shareholders in the broader context of capital allocation, right?

When you look at other uses of cash in our balance sheet, and as you touched on our balance sheet and cash position are in the best position that they've been for a very, very long time, and so what we will do is our underlying commitments around balance sheet, minimum cash and shareholder returns will not change, but we may move within the balance we've laid out depending on the environment that we're in. and we clearly did that with respect to cash during the first quarter.

Outside of that, our net debt to cap is still below our long-term range, 20% to 30%, right? And we've got plenty of coverage of other uses of cash. And so I think -- you'll continue to see us return excess free cash flow to shareholders through share repurchases.

And this approach has reduced our overall share count by 42% since 2014. And for what it's worth, Doug, our return on buybacks is close to 20% over that time period, so buybacks do create perpetual value by reducing the share count. So I think you should expect us to continue to operate in that model.

A lot of downturns gave you that opportunity in the last 10 years or for sure.

Our next question is coming from Philip Jungwirth of BMO Capital Markets.

You mentioned earlier, making some adjustments in the Gulf Coast. On the feedstock sourcing side. And I was just wondering if you could talk about any changes you made specific to the North Atlantic region. You've dated Brent in the indicator, but I assume you can do a bit better here, especially at with Quebec City. And maybe also just touch on the export side, too, and how you're optimizing given market volatility and global demand for products.

Sure, Phil. This is Randy. For Quebec, I mean, it's mostly 100% North America crude slate. So it's taking barrels from Western Canada and from the Gulf Coast that tend to avoid some of the spikes that we saw in Dated Brent kind of earlier in the month. For pembro, I mean, obviously, we do have some volatility that we saw in the prompt dated that seems to have lined out as some of the initial panic buying what's happening in the market and even got to the point where people were reportedly cutting runs as dated spiked higher.

Fortunately, we've kind of avoided some of the peak numbers on some of the crude purchases. So looking ahead, it looks like our margin environment for Pembroke still looks favorable as we move forward.

Okay. Great. And then one of the questions we regularly get is around some form of restriction on product exports. Just based on your conversations, where would you put the level of government support here what would be an unintended consequences? And then what other levers are there to pull to ease some of the upward pressure on gasoline prices, whether it's RVP or other things that could be done?

Yes, this is Rich Walsh. What I would say is we've had -- there's been lots of conversations with the administration and they're keenly aware of what they are watching the prices out there. And they've already taken actions. They gave a Jones Hack waiver real early on. That really helped out.

And the reality is any kind of export ban actually just makes the situation way worse, and they're keenly aware of that already. The U.S. is long crude and long refining production. And so we are tethered to the world market. So it's important to make sure that we get optimized and provide, and this is a huge competitive advantage for the U.S. as well.

So I think the administration fully understands that. They're looking at all the options and tools that are out there. But we're not positioned like some other countries where they just don't have -- they just don't have the resources that we have. And so I don't think those kinds of strategies really makes sense for us. I think the administration is well aware of that.

And I don't think there's any real meaningful potential for that to happen.

The next question is coming from Jason Gabelman of TD Cowen.

Yes. The first conflict at all and really 2 conflicts that have resulted in pretty massive dislocations in the market change your way you think about investment opportunities and how you run the business in the medium term. I know, for example, you talked about a VGA shortage in the contrary, if that's an area that you could figure out some investment and to help close your own shortage or other opportunities such as that?

Jason, it's Lane. I think it is a good point. How I think about it in the course we think about it is the Ukrainian Iran conflict has really demonstrated, I would say, the resilience of North America. They been largely due to just the fact that we have such a robust and oil and gas industries really help position us for the 2 conflicts that have occurred. .

And of course, we sit here in the Gulf Coast. We have the most flexibility on crude feedstocks. We can export anywhere in the world. So in terms of how we sort of think about our projects, we like to bucket them, right? And so the way I -- the way I'm going to characterize it is we like projects that increase our commercial leverage. So if you think about your VGO question, that's a position that we want to get through our gating system to maybe position ourselves not to be so lenient or so dependent upon BDO imports. And so doesn't mean we're going to lose our discipline, but it means that we see that there's an issue has been really pointed out with respect to these projects is the conflicts.

And then we also, obviously, like reliability projects, the key to this is to be able to run through all these -- be able to move your assets around and run reliably through it and then finally, yields better yields, which is essentially the FCC project.

And we can upgrade to what we're making that we like that. ethanol, which isn't obviously -- you wouldn't think of it as being directly tied to this, but what you are seeing in the world is people are looking at, hey, can I blend more ethanol in the fuel mix.

And so we have a positive view on the ethanol business. And so we have been investing in ethanol, same thing, incremental growth and how much we make yield improvements to increase the amount of ethanol and again, there's this backdrop of improving carbon intensity. In the renewable diesel, I don't know that it's so much dependent on what we've seen in the world.

But obviously, we have the SaaS project hanging out there. We just want to see policy. Everything that happens in that space is very dependent on how policy works out and how you can sort of survive from administration to administration.

Great. That's a really helpful framework. My follow-up is just on the interest curves and specifically on futures cracks. And I think the market broadly uses that to help price the refining stocks. But the reality is, based on conversations we've had, it seems like there's not so much liquidity on the back end of those curves.

And thinking about your comment that it could take 6 to 12 months if Hormuz was open to today inventories. How do you think about where cracks are on futures in the second half of the year? Do you think we see a similar dynamic as during the Russian war where cracks kind of in the back-end trend higher through the year and end up higher than what was represented early in the year? Just any color around future scratch would be helpful.

Yes. So that is our view as we think the back end of the curve is undervalued. And I think a lot of it is it's somewhat hindering trade flows that need to happen. The high freight rates along with steep backwardation are making markets that are really short and need product today, looking to the future and thinking they're going to be able to buy that product at lower values in the future. And in reality, the curve is just rolling up, and we expect that to continue.

Our next question is coming from Matthew Blair of Tudor, Pickering, Holt & Co.

You mentioned some of your commercial opportunities in areas like the North Atlantic. Do you also have opportunities on the West Coast? And I guess in particular, are you using Jones Act waivers to ship both crude and products to the West Coast?

Matt, this is Randy. I'll touch on that. I mean we have issued several Jones Act waivers primarily for products, both renewables and conventional products moving both from the Gulf Coast to the West Coast and to Florida.

Sounds good. And then the ethanol results seem pretty good, but better than our expectations. Was that just a function of improving values on the co-products or were you able to record any 45 contributions in the ethanol segment? And I guess, what's the overall outlook for and the potential contribution this year in ethanol.

Yes, this is Eric. Lane alluded to what we're seeing in the ethanol demand globally. So as the one of the largest exporters of ethanol, you're seeing a pull on ethanol. And so the underlying value is really as the hydrocarbon prices have increased, so has the value of octane and ethanol being an octane component has now become the cheapest form of octane in the world.

And so that is why you're seeing a lot of interest and you can use ethanol as a supplement, just like it has in the U.S., you see a lot of countries going from 0 to 10 Brazil is going from E30 to E32 India is going to E20 and talking about going higher than that. Everyone sees that ethanol is a cheaper form of liquid fuel. So you're seeing demand in ethanol. As far as PTC, what we booked in the first quarter was $0.10 a gallon on 10 of our plants using the original definition of qualified sales.

And so what we'll ultimately see once the guidance is published, which hopefully, at the end of this year, but it may not be until next year is you'll get the next $0.10 to $0.20 across all our plants across all our sales.

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

Can you hear me guys?

Yes, we can hear you.

Sorry, I got like a $15 phone here. Thanks for everything that you -- you had mentioned the shortage of VGO. And I just wondered if you could talk a little bit about where you might anticipate other shortages, actual physical shortages emerging in the oil chain. That's sort of Question number one.

I don't know any -- yes, obviously, VGOs and issue, this is Lane. I mean we -- if you think about how trade flow worked before all this started, net DG flowed from essentially Europe and the Middle East into the U.S. to sort of satisfy the complexity of the FECs and the hydrocrackers here.

I don't know that we see upside the jet just everybody knows about Jet. We're talking about all these other intermediates. I don't know that at least in the United States, we see any other sort of structural issues in terms of intermediates.

Okay. That's great. And secondly, Lane, you've talked about in the past, I remember Joe is certainly saying this that when you look at your inventories over time, you kind of don't play inventories.

It's almost more that you are just working operationally to optimize your performance. I had a question, firstly, I assume that you're still doing that. Secondly, how do you see a situation where inventories deplete? I assume that the industry won't go to 0 inventories, right? So I was thinking as we get these draws but when is the point at which, I guess, prices go, it on higher is the best guess?

Paul, I'll take the first thing. So the answer is yes. I mean I think Homer earlier alluded to the fact we could see all this volatility in the commodity market, we're keenly aware that the tendency would be for us to say if a refinery incident, and you're not -- in crude oil inventories start creeping up above what we would consider to be our working inventory and we can get into where it puts a short paper.

And so we worked very hard just to avoid the derivative volatility and worked hard to make sure that we are operating around our working inventory, which equals our LIFO inventories. In terms of the latter part of that question.

Yes. It's very difficult for us to tell. I do think, as I alluded to before, with the steep backwardation that you see in the market, a lot of markets that are short product today are basically trying to live hand-to-mouth, thinking that they'll be able to buy replacement barrels in the future at cheaper values. At some point in time, they'll realize that they need the volume, and I think you'll see a reaction in price -- but at what inventory level that occurs, I don't really have any insight. .

Yes, I understand. It's a tough one.

Thank you. At this time, I would like to turn the floor back over to Mr. Donovan for closing comments.

All right. We appreciate everyone joining us today for the call. And as always, feel free to contact our Investor Relations team if you have any additional questions. Have a great day.

Ladies and gentlemen, thank you for your participation. 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.

Greetings, and welcome to Valero Energy Corp. Fourth Quarter 2025 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Brian Donovan, VP of Investor Relations. Thank you. Please go ahead.

Good morning, everyone, and welcome to Valero Energy Corporation's Fourth Quarter 2025 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. I'd like to begin by highlighting some of our team's accomplishments in 2025. Last year was our best year for personnel safety and environmental performance, building on personnel and process safety records we set in 2024. Our continued commitment to safe, reliable and environmentally responsible operations resulted in a record retained throughput and record ethanol production for both the fourth quarter and the full year. We also set a record for mechanical availability in 2025. These accomplishments reflect the hard work, expertise and dedication of our entire team.

We delivered strong financial results in the fourth quarter, reinforcing our consistent track record of operational and commercial excellence. We captured favorable refining margins during the quarter driven by strong product cracks and widening sour crude discounts and our fourth quarter performance capped off excellent financial results for the year.

Strategically, we continue to make progress on our SEC unit optimization project at our St. Charles refinery. This $230 million initiative will enhance our ability to produce high-value product yields, including outlet. We still expect the project to begin operations in the second half of 2026.

Looking ahead, we believe refining fundamentals should remain supported by continued demand growth and tight supply environment driven by limited capacity additions. Sour crude differentials are also expected to benefit from increased Canadian crude production, along with additional Venezuelan crude supply into the U.S.

In closing, Valero's strong financial results and record operating performance, highlight our operational and commercial excellence. We remain committed to our disciplined capital allocation framework that prioritizes balance sheet strength, disciplined capital investments and shareholder returns.

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

Thank you, Lane. For the fourth quarter of 2025, net income attributable to Valero stockholders was $1.1 billion or $3.73 per share compared to $281 million or $0.88 per share for the fourth quarter of 2024. Excluding the adjustments shown in the earnings release tables, adjusted net income attributable to Valero stockholders was $1.2 billion or $3.82 per share for the fourth quarter of 2025 compared to $207 million or $0.64 per share for the fourth quarter of 2024.

For 2025, net income attributable to Valero stockholders was $2.3 billion or $7.57 per share compared to $2.8 billion or $8.58 per share in 2024. 2025 adjusted net income attributable to Valero stockholders was $3.3 billion or $10.61 per share compared to $2.7 billion or $8.48 per share in 2024. The refining segment reported $1.7 billion of operating income for the fourth quarter of 2025 compared to $437 million for the fourth quarter of 2024. Adjusted operating income was $1.7 billion for the fourth quarter of 2025 compared to $441 million for the fourth quarter of 2024.

Refining throughput volumes in the fourth quarter of 2025 averaged 3.1 million barrels per day or 98% throughput capacity utilization. And as Lane highlighted earlier, we achieved record throughput for both the quarter and the full year. Refining cash operating expenses were $5.03 per barrel in the fourth quarter 2025. The renewable diesel segment reported operating income of $92 million for the fourth quarter of 2025 compared to $170 million for the fourth quarter of 2024.

Renewable Diesel segment sales volumes averaged 3.1 million gallons per day in the fourth quarter of 2025. The ethanol segment reported $117 million of operating income for the fourth quarter of 2025 compared to $20 million for the fourth quarter of 2024. Ethanol production volumes averaged 4.8 million gallons per day in the fourth quarter of 2025, also setting a quarterly and full year record.

G&A expenses were $315 million for the fourth quarter of 2025 and $1 billion for the full year. Depreciation and amortization expense was $817 million for the fourth quarter of 2025, which includes approximately $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia refinery.

Net interest expense was $139 million and income tax expense was $355 million for the fourth quarter of 2025. The effective tax rate was 25% for 2025. Net cash provided by operating activities was $2.1 billion in the fourth quarter of 2025. Included in this amount was a $349 million unfavorable impact from working capital and $269 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 $2.1 billion in the fourth quarter of 2025.

Net cash provided by operating activities in 2025 was $5.8 billion, included in this amount was $192 million unfavorable change in working capital and $30 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 $6 billion in 2025.

Regarding investing activities, we made $412 million of capital investments in the fourth quarter of 2025, of which $368 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 $405 million in the fourth quarter of 2025 and $1.8 billion for the year.

Moving to financing activities. We remain committed to our disciplined capital allocation framework. Shareholder cash returns totaled $1.4 billion in the fourth quarter of 2025 resulting in a payout ratio of 66% for the quarter. For the full year, shareholder cash returns totaled $4 billion, resulting in a payout ratio of 67% for the year. We ended the year with 299 million shares outstanding, reflecting a reduction of 5% for the year and 42% since 2014.

Earlier this month, our Board approved a 6% increase to the quarterly cash dividend slightly higher than last year, reflecting a strong financial position and our commitment to a growing dividend.

With respect to our balance sheet, we ended the quarter with $8.3 billion of total debt, $2.4 billion of total finance lease obligations and $4.7 billion of cash and cash equivalents. The debt-to-capitalization ratio, net of cash and cash equivalents was 18% as of December 31, 2025, and 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 $1.7 billion, which includes expenditures for turnarounds, catalysts regulatory compliance and joint venture investments. About $1.4 billion of that is allocated to sustaining the business and the balance to growth projects. These growth 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 first quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.695 million to 1.745 million barrels per day; Mid-Continent at 430,000 to 450,000 barrels per day; West Coast at 160,000 to 180,000 barrels per day; and North Atlantic at 485,000 to 505,000 barrels per day.

We expect refining cash operating expenses in the first quarter to be approximately $5.17 per barrel. For the Renewable Diesel segment, we expect sales volumes of approximately 260 million gallons in the first quarter. Operating expenses should be $0.72 per gallon, including $0.35 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 first quarter. Operating expenses should average $0.49 per gallon, which includes $0.05 per gallon for noncash costs such as depreciation and amortization.

For the first quarter, net interest expense should be about $140 million. Total depreciation and amortization expense in the first quarter should be approximately $835 million, which includes approximately $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia refinery. We expect incremental depreciation related to the Benicia refinery to be included in D&A for the first quarter and in April.

First quarter earnings impact is approximately $0.25 per share based on current shares outstanding. For 2026, we expect G&A expenses to be approximately $960 million. Lastly, our capital allocation framework remains unchanged with a commitment to a through-cycle minimum annual payout ratio of 40% to 50% of adjusted net cash provided by operating activities, and our long-term target net debt-to-cap ratio remains 20% to 30% with a minimum cash balance between $4 billion to $5 billion, with all excess free cash flow going towards shareholder returns.

Thanks, Homer. That concludes our opening remarks. [Operator Instructions]

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

Looking at the macro outlook, certainly, we're seeing inventories building coupled with relatively high domestic utilization as well as what seems like a curious supply and demand setup, given significant capacities latest to come online in Asia, balanced against limited closures for the year. In light of these developments, how do you view the evolution of supplying to demand dynamics for light products and crack spreads going forward?

Yes, Theresa, this is Gary. Certainly, during November and December, we saw a fairly significant build in total light product inventory it followed typical seasonal patterns, but the magnitude of the build was much larger than what we typically see. So we kind of went from below the 5-year average on total light product inventory to above the 5-year average. We didn't see anything abnormal in product demand in our system. Gasoline sales in the fourth quarter were flat year-over-year. Distillate sales in our system were actually up 13%. And I would tell you that's probably more related to a change in our customer mix than anything else. But good domestic demand.

Our exports quarter-over-quarter were up. Exports year-over-year were up. So again, good demand in the product market. But really what caused the inventory build is exactly what you alluded to, we just ran very high refinery utilization. So especially in December, where you were at 95.4% utilization, very strong for that time of year. I think some of that was related to the very strong margin environment we had in November. Cooler weather allows you to push utilization rates as well.

The thing that's really interesting to us is almost all that inventory build was in PADD 3. And we've always stated we like our position in PADD 3 because it allows you to clear any link to the export markets. We didn't really build any inventory during the fourth quarter. We didn't see any economic incentive to carry inventory or produce summer-grade gasoline. So we're not really sure what caused the inventory build in PADD 3.

Going forward, when you look at 2026, most of the consultant data show similar supply-demand balances to last year, but they are assuming lower refinery utilization, refinery utilization coming back to normal levels. think we agree with that. You've already seen utilization drop as we start into turnaround activity. As we wrap up turnarounds, I think you get into warmer weather, which, again, it's hard to push refinery utilization due to some overhead temperature limits.

With the assumption of more normal refinery utilization to us, it looks like demand is outpacing additional supply. Our numbers would indicate about 400,000 barrels a day of net capacity additions, we're drilling about 500,000 barrels a day of total light product demand growth. So things look tight in the consultant data. There's also a lot of assumptions in the consultant data. They assume Russian refining capacity comes on, runs normally. They assume a lot of the new capacity that's starting up runs at nameplate assumptions around bio and renewable diesel coming back into the market in a strong way. And then really no refinery rationalization outside of what's already been announced.

So I would say our outlook is a little more bullish than what the consultants are showing just because we believe execution risk remains high on a lot of those assumptions that I just mentioned. Really difficult to get much of a read on the market as far this year mainly due to the weather. I can tell you that first couple of weeks in January were fairly soft on domestic demand. That's typically the case. Things have started to recover nicely. Last week, we were back up to around 1 million barrels a day on U.S. wholesale, but then we had the winter storm hit. So last weekend, we saw wholesale liftings that were about 40% of the prior weekend, it's remained soft this week, but gradually recovering. Sales yesterday were about 90% of normal, continue to see good export demand, diesel export arb to Europe is open, diesel export into Latin America are economic, good gasoline demand into Latin America. And we don't see an arb to really send winter-grade gasoline to New York Harbor. So all of those things are constructive.

Super helpful. Thank you, Gary. Looking at the feedstock side of things, with the distillate crude being rerouted to the Gulf Coast, how much of this can be absorbed within your footprint over time? And can you also elaborate on how you see this impacting differentials without a meaningful and immediate increase in Venezuelan production itself, how do you see this equilibrating over time? And what are the implications for both Gulf Coast live heavy diffs as well as live heavy diffs in the Mid-Con given the related impact to WCS.

Out of Venezuela tend to be very heavy, high sulfur, high asset and that fits our configuration pretty well. In fact, if you look over the last 10 years, Valero has been the largest purchaser of Venezuelan heavy crude more than any other U.S. refiner. Historically, you look back and we ran as much as 240,000 barrels a day of Venezuelan heavy in our system. However, that was prior to the new coker project at Port Arthur that was installed in 2023. That project has substantially increased our processing capability for heavy crude. So we'd expect our Venezuelan processing capability to be substantially north of that number now.

Kind of looking at differentials, I mean not only Venezuela, but we've had several beneficial factors that have occurred to kind of help move this market weaker. After last year with discounts fairly tight, most of these market moves tend to -- are making differential increasingly favorable for refiners with high complexity refineries, such as ours.

In OPEC increases of the announced 2.9 million since April of last year. We've seen growing sour crude production in the U.S. Gulf. So it's now over 2 million barrels a day. That's up about 200,000 barrels from a year ago. We've seen a reduction of the exports that started in October. And we continue to see high production -- growing production out of Canada. That's been helpful.

One other factor that's been helping discounts is freight rates have been sharply higher. When you look at current rates compared to where we were in the fourth quarter, freight's up about 30%. So when freight goes up since the U.S. barrel must price to clear, it's having to have wider discounts in order to allow those exports to happen. So right now, we're seeing Head Canadian in the Gulf Coast, trading at about $11 to $11.50 under Brent. That's about $4 cheaper than our Q4 average. And similarly, margin the Gulf has been around $5 discount to Brent, that's about $1 kind of cheaper than we were in the fourth quarter. So all looks pretty favorable. I think for this kind of heading into 2026.

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

Yes. First question, I guess this would be for you, Homer, would be around return of capital. Last year, you guys were pretty strong versus, I think, what Mark expected. Just -- we do get the question with the stock having done well. How aggressive you will continue to be around buying back stock and love your perspective on that, especially as you step into the CFO seat.

Neil, I'll start, obviously, returning excess free cash flow to our shareholders through share repurchases has been a pretty core tenet of our capital allocation framework, right, for over a decade, and we reduced our share count by over 40% since 2014. So maybe I'll just talk a little bit about the framework. So it all starts with the balance sheet, right? It's in one of the best positions in the industry. If you look at our net debt to cap ratio at 18%, it's actually below our long-term target of 20% to 30%.

Our year-end cash balance was at $4.7 billion, again towards the high end of our target range of $4 billion to $5 billion, so we don't really have any pressing need to pay down debt or build more cash. So then let's move to like the discretionary uses of cash, right? I'm not going to mentioned sustaining CapEx and dividend, which we obviously consider nondiscretionary. So on the discretionary side, you've got growth projects, you've got acquisitions and share repurchases, right? So starting with growth projects, we're going to be guided by our minimum return threshold, right? We're going to stay disciplined.

On acquisitions, same, we have to see good strategic value and a clear and quantifiable assessment of synergies. So we're not going to just do growth projects or acquisitions just because we have excess cash. So absent those uses of cash, we're going to continue to lean into share repurchases. And if you think about share repurchases, there's always like an underlying ratable part of share repurchases to meet our minimum commitment of 40% to 50%. And then beyond that, we do look for opportunities to be more aggressive around share repurchases, and that's really any given period where we see weakness, particularly if our share price is weak on a relative basis to the broader sector.

And to your point on stock trading near all-time highs, I mean, you go back 10 years when the stock was trading around $50 to $60, we've been getting that question ever since then. And for what it's worth, our return on buybacks is above mid-teens over that 10-year period with where the share price is today. And frankly, I hope we keep getting the same question for the next 10 years because that means the stock is doing well.

Yes. That's a great answer, Homer. The follow-up is just we are seeing heavy start to discount, particularly Western Canadian crude. And so just -- there was a story out there that some of the folks who are marketing the Venezuelan barrels we're trying to bid them in pretty tight into the Gulf Coast, maybe even move it into China. I just think from your guys' perspective, you have options for heavies, including Western Canadian down on the Gulf Coast. If you could expand a little bit more on that specifically. As you are -- as you see the go forward for the barrels that are being marketed in you think they're going to have to compete a little bit wider in order to compete with your alternatives.

Neil, this is Randy. I'll comment a bit on that. We're not going to comment on pricing for deals that we've done. But I'll just say that we're evaluating Venezuelan crude like we always do for all of our alternatives. We've put it into the basket of alternatives, and we will purchase Venezuelan grid if it beat our alternatives. So you've seen all the articles I read them as well.

Looking forward, we've already kind of engaged with the 3 authorized sellers of crude and we purchased barrels from all 3. So we anticipate the Venezuelan crude making up a pretty large part of our heavy diet as we move into February and March.

The next question is coming from Manav Gupta of UBS. .

First, wanted to congratulate Brian on the new role of Investor Relations. And then also really wanted to congratulate the incoming CFO for pushing the stock price to an all-time high, very quickly. On the [indiscernible] Homer, look, even when we go back 4 or 5 years, for the same refining margin, what we are seeing is the cash flow profile of the company is different. You're producing more cash even if the margin was the same 4 or 5 years ago, can you help us understand the dynamics over there? Like what's been behind this transition to generate the -- ability to generate more cash with the same refining margin?

Manav, as Lane talked about this in the past, but it's really a result of a number of things. And it all starts with being a good operator, having discipline around capital investments and then a strong balance sheet, which ultimately all translate to higher cash flow and higher shareholder returns. So starting with operations, we've obviously worked really hard to manage costs in our reliability over the years, and you can see that with the record throughput and mechanical availability this past year.

And then we've also been very disciplined around growth investments. Obviously, you know our minimum return threshold, which effectively ensures you have a good return when things are good, but also hopefully protects us with a return that's well above our cost of capital even in kind of a downside scenario.

And you can see that if you look at our return on equity or return on invested capital over the last 5 or 10 years, that's in the mid-teens or higher number. And again, keep that -- keep in mind that denominator for the return on equity or return on invested capital includes all capital right, including sustaining CapEx.

And then also generally on capital, we have been trending a little bit lower in recent years, which just frees up more free cash flow for shareholder returns. Lastly, I mean, the balance sheet obviously plays a strong role in that, both in terms of we've got lower debt and higher cash balance. So at the margin, you have lower interest expense but then higher interest income as well. But really more importantly, just having a strong balance sheet gives you much more flexibility with respect to shareholder returns. And then lastly, obviously, on a per share base, the share repurchases have helped a lot as well.

All very good points. My quick follow-up here is a very good improvement in renewable diesel. I know there were a few quarters where the industry struggled, you did much better than the industry, but the industry was struggling. Are we finally seeing at the light end of this tunnel where possible RVO and then all those policies will come clear and -- and do you expect generally a renewable diesel to deliver better earnings in 2026 versus '25, primarily a function of more maybe policy clarity, if you could talk about that.

Yes, Manav, this is Eric. You're exactly right. We're still waiting on final policy guidance on the RVO and PTC. And so if you contrast the first half of '25 being the transition to PTC and everyone trying to understand that we were the first and perhaps maybe the only company that has really figured out how to capture the PTC. So the second half of '25 was getting into full PTC capture, getting into full SAF commercialization and between that differentiation, our ability to capture the PTC and the overall margins tightening in renewable diesel allowed us to outcompete a lot of our competitors. And as we have started 2026, there's a lot of capacity off-line. There's a lot of players that are now sitting out waiting for guidance to get finalized before they reenter the market, and that has caused SAF prices to really level off and even drop throughout the fourth quarter and into this first quarter.

So what I see in '26 is a policy should be a tailwind. The expectation is it should come out favorably for renewables. We do see that there a lot of talk -- and tariffs continue to be a pretty strong headwind but we'll see what the Supreme Court comes out with. And so I think you're going to see 2026 starting off more like the second half of '25, and so that would indicate a stronger year in '26 versus '25.

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

I'm sure Brian has already told you about my family connection, but welcome, Brian. Guys, I wonder if I could just ask 2 quick ones. First of all, on all the dynamics of heavy oil in the Gulf Coast, there is obviously a lot of complexities. But across your system, Mexico looks like it's now running a little better, so less imports or less exports rather from there, WCS as TMX. And then, of course, there's Venezuela. And my question really is about your coker utilization and the volume of your heavy runs, where that can get to, not the crude utilization but where you can actually get your throughput to -- and my specific question is, 10 years ago, 15 years ago, you were running about 1.3 million barrels a day of advantaged crude, including fuel oil. You've added the coker you're less than 1 million today. Where can that get to?

So Doug, it's Lane. I'll answer this one. If you really look at what happened, we did sort of when we added the coker because of the dynamics you're talking about in terms of heavy availability. What we really did is we incremented medium and light crude with some heavy actually ramping up into higher rates may ensure that our coker availability, our coker sort of utilization was where we felt like it [indiscernible] we're also purchasing outside resids. So we're doing all that. I think what you can expect is you get more available from Venezuela, more avails from Canada, you'll see us actually fill the coker up sooner with that crude diet, and we'll see on an incremental basis, so we actually increase crude rates or actually lower them depending on how incremental crude economics because we believe it will be a driver to fill the coker with heavy.

Lane, is it possible to give a utilization rate on your coker capacity today and where it could get to? Or is -- is that too granular?

I don't know we've ever really been public with coker utilization. In fact, I don't think we even have it in front of us. So we normally from a -- just from a signaling perspective, most of the time, we optimize the crude diet into sort of the way you would do it and then we purchase outside feed or internal resid feed to make sure that, that coker is full most of the time.

All right. That's helpful, guys. My follow-up is actually on one of Manav's questions about the RVO and RIN prices have obviously spiked here pretty dramatically since the start of the year. I'm trying to understand how should we think I don't know if there is such a thing as mid-cycle earnings. But at today's RIN price, obviously up around the -- I think we were at 120 or something today per gallon. What do you think the mid-cycle earnings capacity of DGDs or maybe free cash flow, whichever one you prefer to lean on. And I'll leave it there.

Yes. That's not really a question that you can easily come up with an answer on but mid-cycle for RIN. What I would say is you've kind of been a new framework with the PTC. So the previous 10 years of DGD was on the blenders tax credit. So everyone gets $1 cash from the government for every column that you produce. Now we're into a regime where it is dependent on your CI, it's dependent on your income tax because it's now an income tax credit. So you're into a different -- just an overall different framework.

Now RINs have been underlying this will be a part of this in the past as it will as it is going forward. I think as we think about where this all goes what the government has suggested as an obligation range of 5.2 billion to 5.6 billion gallons for '26 and '27 is well above domestic production capability. So if you see that and with the combination of tariffs on foreign feedstocks and the elimination of credits for foreign imports, the entire compliance area, essentially you're rating the obligation while also making it harder to generate. That all points to a higher D4 RIN price, especially as you draw the bank down, which a 5.2 to 5.6 obligation number would certainly do.

And so what I would say is it's not really trying to think about what a cycle is more just saying that there's a good chance D4 RINs are going to go up.

And so then the next question is, does fat prices just follow that up and keep overall RD margins tight? Or do you see from a competitive standpoint, going back to the PTC, that low CI and the ability to run waste oils over veg oils, is still going to have an advantage in this new framework of PTC. So all of that just really saying 2026 is going to likely look better than 2025 for the segment, and then it particularly looks better for those that can export into advantage marks into Canada and Europe and the U.K., those that operate just like refining and the most efficient capacity in the Gulf Coast, and then those that can run a oils over veg oils.

The next question is coming from Paul Cheng of Scotiabank.

Lane, I don't know whether you guys will be willing to share. That's -- as usual, every several years that we have the labor contract being negotiated and Marathon is having that with the USW. And can you tell us that which of your refinery -- yes, currently under that contract. So in other words that -- in case if there's any so, I'm sure that you guys are well prepared management, you will be able to take care of need for a period of time, but which refinery or what percent of your capacity is actually will be impacted?

Second question is that I think that has been answered previously. If we look back in your utilization rate, historically, I think on a full year basis that your maximum may be doing somewhere in the 94%, 95% do you believe, given you've been -- look like they had been done a phenomenon job in operating your facility better and better. Do you think that now on a maximum full cycle basis that you will be able to do better than that? Or that I mean that the entire curve have been shipped up, what I mean they compare to maybe 10 years ago, 1% or 2%. Is there anything that you can help to quantify it.

Paul, it's Lane. I'll take a stab at the first one. I just -- yes, so your instincts are correct. We're very -- we're not about to disclose exactly where -- which one of our sites and everything are under USW, we -- and some of the other maybe units that are out there. What I will say, one of the advantages that Valero has versus our competitors in that space, however you think about it is we're less unionized directionally than a lot of the people in the space. I don't buy everybody, but directionally, that's true. And on the second one, I guess, it's...

Yes. So I think, Paul, what I'd tell you is we obviously had a record year in terms of mechanical availability last year. With better mechanical availability, you would expect to see better refinery utilization to try to quantify that would be very difficult. .

Gary, do you think that the whole industry is getting better? .

It's a good question. I think a lot of what you saw in the fourth quarter was very strong margins and moderate temperatures. And so that allows you to kind of push refinery hardware a little bit harder than you normally could. I think it will come back off. I don't think what we saw in December is sustainable, but everyone is certainly trying to drive up mechanical availability as we have. .

And that you're talking about the weather. Do you guys have any noticeable downtime from the winter? That's my last question.

Yes, Paul, we really fared the winter storm pretty well. We had a few nuisance-type heater trips, but nothing material. I think most of what we saw was really things external to the refinery, some interruptions in hydrogen steam hitting up against product containment type limits. But if you look at our guidance, I would tell you, there was nothing material that related to the winter storm that's going to impact the quarter. .

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

Okay. Maybe one on West Coast, if you could just talk a little bit about West Coast refining. A couple of things, maybe profitability was a little weaker in the quarter. Can you maybe talk about what some of the drivers were there? And then, can you maybe walk us through the time line of the coming shutdown of Benicia and how you're thinking about West Coast dynamics for 2026?

Yes. I'll start on the first. Yes, our capture rates were a little down on the West Coast, some of that is to do with the fact that gasoline relative to diesel, gasoline was pretty weak relative to diesel. As we've talked about, especially our Benicia refinery has a really strong gasoline yield. And so it tends to lower our capture rates. The other thing that hurt us is there was a retroactive tariff adjustment on one of the pipelines we utilize on the West Coast and all those charges hit during the fourth quarter. So those are the 2 big things that impacted our capture rates in the fourth quarter on the West Coast.

And this is Rich Walsh, I'll try to answer on the time line there. In terms of the Benicia idling, we're executing our plan to idle it, the refinery operating units that is. And it's a well planned out and phased process. And in February, we -- I'm sure you saw our most recent announcement, we will be idling the process units because they have some mandatory inspection requirements that are kicking in then. And so we'll be pulling those off-line.

And -- but we will be continuing to produce fuel as we work down the inventory through this process. And as we've shared with the governor and the CEC, we are going to be importing some gasoline and/or gasoline blend components over the near term. And we remain committed to our contractual obligations out there to meet the supply obligations that we have. So we're working cooperatively with state officials, the CEC and the governor on our plans, and we've kept them fully informed and aware of our supplemental supply commitments to the Bay Area. So I think that's pretty much where we are. And then in terms of Wilmington, it's normal operations. and we'll continue to supply the California market out of Wilmington.

Great. And then maybe -- just maybe one follow-up for you, Eric, on the RVO stuff. Any thoughts in terms of what you're hearing on timing or any of the any of the items which are kind of debated out there, whether it's SRUs or reallocations or penalties for foreign fees or products directionally, what you're hearing on those things?

Yes. That's really kind of a government question. I'm going to let Rich answer that.

Yes. Look, U.K. has got a big challenge in dealing with the RVO right now and the SREs in this -- I think the administration started to recognize how -- now that all of this is getting caught up with these SREs have really gotten out of hand. If you look at EPA, they sort of defaulted to this outdated DOE process at the government accounting office has already said, was a flaw process in both EPA and DOE had acknowledged that previously. And this metric is so out of date. It doesn't even account for the shale revolution and the domestic production, which is completely transformed in the U.S. energy market. So really flowed SRE basis that's out there.

And in terms of solutions, I mean, I think there is a legislative proposal out there as a compromise is supported by API, by ag interest, by retail trades and most refiners that would allow a process to go forward that would kind of help correct all this and get it kind of realigned and supporting the RFS. But there are a small number of conglomerate so-called small refiners that are out there that are having windfall on these SREs and they're kind of holding it up. So that's what we think this stuff is going to have to be worked down. It's a challenge for the agency that kind of gotten into a fix it over issuing these SREs.

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

Glad to hear Brian that you got the job because of your close family relationship to Douglas Leggate. Joke. Just on demand and supply at the moment, obviously, we're seeing oil through 70. Is that -- would you say that's related to the sanction shadow fleet being shut down effectively or more shut down than it has been. I'm just wondering it's a big surprise I think to all of us. There's obviously the demand side of the equation. And I was just wondering what your perspective is on U.S. oil demand right now in the storm because we're seeing some big numbers from some of the Northeastern generators, I mean, 300,000-plus type daily use of oil to generate power. You didn't seem to really highlight that in your very complete comments so far. I just wondered if you're seeing a big impact from the storm in terms of the demand side of the equation, which might help to explain why we're at 70. So the overall question is how come we've gone through 70 here at a time seasonally of weak oil prices.

Yes, Paul, I'll just touch on the flat price. I think what we're seeing right now with the geopolitical going on in Iran, I think has put quite a bit of a geopolitical risk factor on top of flat price plus you had the winter storm take off some oil production in the shale patch in addition to the continued issues with the CPC and Tengiz over in Kazakhstan, had quite a bit of oil off-line. So I think all those are leading to some short-term tightness plus the geopolitical factors that's kind of running up oil here in the short term?

Yes. In terms of heating oil demand, I think a lot of that is just where we have a strong wholesale presence, we're not really strong in the heating oil markets. In markets like Boston, where we do have a presence, we have seen a significant uplift in diesel demand as a result of heating oil. And then the rest of it, for us, a strong incentive to shift to New York Harbor, which is again tied to heating oil demand.

Great. And if I could ask a follow-up. Lane, is there a way that you could see more investment as you shut down California, I'm wondering how your exposure to California is going to change if you're going to kind of effectively exit that market or if you'll have access to it through other means? And secondly, whether or not you would consider perhaps with more heavy oil coming back on market with the decline of potential certainly decline of U.S. light sweet production whether there might be more CapEx to be undertaken?

Paul, this is Lane. I don't think you'll see our CapEx increase with respect to the West Coast. As a matter of fact, I'd have to go back and how long we sort of -- we've -- obviously, what we've done out there is to maintain our sustaining capital for all these years with respect to the West Coast and we didn't see a market that we were going to grow the capacity to produce into it. So what you're actually going to see is as we shut Benicia down, our sustaining CapEx should fall I'm going to pick a number, somewhere around $150 million, so our sustaining capital actually fall.

With respect to how we see California, it's still a very -- it's a challenge to operate out there. We'll continue to operate Wilmington. It's a good asset and a good market. It has its challenges with respect to regulatory capital end of the decade, and that's when we'll sort of make our decision on how we'll -- how our presence in the West Coast will with -- how it will be, so.

And anything on incremental spending on a heavier slate going forward potentially, Lane?

No, not on the West Coast, meaning the -- yes. We'll definitely look at that in terms of our strategic cap -- looking at that. We have things that we have in our gated process. We don't necessarily -- our tendency as a company is to talk about projects as we FID and not as we are studying them. But we have a pretty good position as it is. So we want to make sure that we don't hurt that position, but clearly, as we -- there's more avails in the heavy oil market and we hit these constraints again, we'll study we'll see what it would take to do this probably still fit into the small CapEx. We're not going to do a great coker expansion or anything like that, that's not the foreseeable future. .

The next question is coming from Sam Margolin of Wells Fargo.

On visiting CapEx, growth CapEx is pretty moderated. I think you've explained why, just drill into it. How much is inflation a factor with the gated process and returns? And if it is a big factor, what do you think that means for sort of buy versus build decision making to the extent that you're interested in growth?

Sam, I will back up and explain the kind of our strategic CapEx. If you really go back for a long time, and we feel like we have the capacity to strategically develop about $1.5 billion of strategic CapEx. When we went into COVID, we sort of lowered that number to about $0.5 billion, really emphasizing at a time renewables, the renewable side of the business. .

So if you kind of -- if you look at the trend of where we've been for like the past 5 years or 6 years or something like that, or half of the joint venture, where we're spending about $250 million-ish of CapEx with respect to R&D. But with all the policy uncertainty, starting last year and on an ongoing basis until we get some more clarity on how all that will work, that's falling, right?

Our refining CapEx, strategic CapEx is fairly stable, and it is in that sort of 300-ish to -- 300-ish kind of number. And that is -- I'm not going to -- with respect to inflation, what I will say about inflation of our gated process, if it does make these projects more difficult to do because the cost of building has gone up. I mean our -- as an example, our [indiscernible] cost, I don't know, $350 million, $400 million. And now that we costed on too long ago, it's more like $600 million. So it is you have to think about -- you have to think about 4 price it -- and do you believe the 4 price that is going to accommodate the inflationary cost of standing up units. And obviously, we are always interested in existing assets. We look them through a lens of -- are there arbitrages with our current system, either through sort of call it, processing arbitrage or trading arbitrage that's how we like to think of these things. And we're obviously -- we always look at those and through the -- and particularly through that lens.

Got it. Okay. And then just revisiting heavy crude for a second. I know there's competitive reasons why you might not want to give an exact number of what the headroom is for incremental barrels. But maybe we could frame it this way. On crude valuation, just like while TMX has been ramping and availability has been low, do you have just kind of a ballpark number off the top of your head of how much you think heavy crude globally has sort of been overvalued from a refinery economics perspective and where it could normalize to, whether that's freight costs or some other method that use.

Sam, this is Read, probably difficult to kind of give a value. I just will maybe talking back to 2025 when the differentials on the sours were all pretty narrow and -- we got to a point where we were in different running sweet crude versus the sour for most of the year, especially through Q2 and Q3. I think where we're at today, it's firmly planted. We're going to buy as much on the heavy and mid size as we can to fill up the cookers and downstream units. .

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

Great. Eric, can you talk a bit about the ethanol segment. The segment continues to perform well from both the volume and capture standpoint. Can you unpack some of the drivers here? And then as part of that, I was hoping you could talk about how you think about the potential impact and probability of addition wide E15?

Sure. Yes. Ethanol has had another good year and continues to, as Lane said, break throughput records as we've kind of grown capacity creep for the last couple of years and have plans to continue to creep capacity in the ethanol segment. The corn crop has been good the last 2 years. So we see essentially cheap feedstock as one of the big drivers. And -- and then I think overall, it's easy to see with the way export demand has grown that the world is figuring out that ethanol is a very cheap source of octane. And so we've seen a lot of growth in ethanol exports, there's also continued growth in ethanol as a low-carbon solution. So we see a lot of programs that are now allowing first-gen ethanol into low-carbon programs. So between those 2 things, you've seen export demand grows. So the ethanol segment continues to be very competitive and flow a lot of cash.

I think in terms of E15, all of our ethanol plants are registered to sell E15. That's -- we still see very slow customer acceptance of that, but it is slowly growing. I think that's one of those that if and when that happens, we're positioned to take advantage of that. And it's just a question of how this RVO policy is going to work out. So Rich alluded to, this is all wrapped up in the entire SRE conversation and this idea that what part of renewables is going to -- what part is renewables going to play in the domestic slate is what we're waiting for clarification on. I don't know, Rich, if you had other comments about E15?

No. I mean I do think it's the national E15 waivers caught out with this SRE issue, and you can't have anything that's going to undermine the RFS, like these are doing. And so I think you're going to see ag and most refinery aligned on how to [indiscernible] solution for SRE over authorization. And so [indiscernible]

That's helpful. And then shifting to the refining side. I was hoping to get your perspective on the fuel oil market here. Cracks weakened recently, which I think is driven by the prospects of more Venezuela crude, but I was hoping to get your thoughts on the recent dynamics and outlook here for fuel oil as it relates to coker economics. .

Yes. This is Randy again. I would say, yes, things look really weak right now. I think we're hit 79% on high-sulfur fuel oil this morning, if I look at the paper. I think it's what you mentioned before, more heavy crude in the market. We're also seeing some of the Venezuelan fuel get pointed to the U.S., at least get offered this way which are barrels that normally didn't get shown into this market. We're also seeing a little bit higher runs out of Mexico, which they tend to make fuel incrementally. So that's the more barrels that are getting pointed this way as well.

So all that's kind of pushing freight costs are high. So there's typically a movement from the west to the east on fuel oil, higher freight goes, the west just needed to account more.

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

As far as Russia, how are you seeing the EU refinery loophole sanctions impacting diesel markets? And could there be a greater call on U.S. Gulf Coast barrels and tougher question to answer, but it's been acquired a month as far as drone strikes on Russian refineries. Just how are you thinking about the fundamental versus geopolitical tightness in diesel cracks early?

Yes, this is Gary. I think overall, you are seeing EU shy away from Russian diesel barrels, thus far, we've seen that being able to rebalance throughout other parts of the world. I think the big area we saw some of those barrels were going to South America, we've seen those South American markets return to the U.S. Gulf Coast, which has been supportive of the U.S. Gulf Coast market. I don't know we have seen a fairly quiet month in terms of drone attacks on Russia. What happens there going forward. I really don't have any insight.

Okay. Great. And then this might be a short answer, but you've always said you'll stay out of the CITCO auction, but just given the regime changes in business oil, is there any reason you might revisit this stance depending on what happens with the process in your...

Yes. This is Lane. It's still -- I mean, if anything, it's at of a degree of uncertainty to the product, I think, again. So we're still sort of -- we chose to stay out of it because of the uncertainty of the process, the length of it all, all the difficulty with respect to how that would all work. And I don't know that our change with respect to Venezuela has made that clearer. I would say like we always do, we're obviously interested in any assets that become open or there gets to be more certainty around the process that might change the way we think of it. .

The next question is coming from Jean Ann Salisbury of Bank of America.

Capture in the North Atlantic has outperformed in recent quarters. Is this driven by closure-related tightness in Europe? And do you view it as a structural shift?

Yes. I think a lot of it has been. From our Pembroke refinery, our highest netback barrels are the ones that we can sell domestically. And as people have chosen to exit that market. We've seen our wholesale volumes grow in the U.K. significantly, and it certainly improves the capture rate when that happens. .

Okay. And then as a follow-up, both refined products pipeline open seasons were extended, and I believe one now offers a path to multiple California markets. Now -- do you still prefer, as you kind of said on previous calls, to move product waterborne, thinking that, that's a better dilution here?

Yes. So overall, there's a lot of volatility in the California market, so we hate to be committed to a pipeline that has a shipping into closed arbs. We like the optimization opportunities from waterborne supply. You can supply the barrels from anywhere in the world. The one thing I would clarify is we have a significant commitment to supply the market in Phoenix and to the extent one of these pipeline projects offers us a more efficient way to get to the Phoenix market, we would certainly entertain that. .

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

You touched on the 45Z for your renewable diesel segment. But are you going to be recording 45Z credits in your ethanol segment in 2026 due to removal of the indirect land use change? And if so, do you have a approximate EBITDA benefit it might be. We're estimating somewhere between $50 million and $100 million.

Yes, this is that we are looking at that very closely. So what I'd say is, given our experience with PTC through DGD, we have set the ethanol segment up to capture PTC from a prevailing wage and qualified sales standpoint. So really, we're just waiting on final guidance from the PTC to be able to answer your question directly. But what I would say is we are poised to capture whatever the PTC is going to give us. And -- you could -- what we'll add is it works in $0.10 increment. So if you qualify, you'll get $0.10 or $0.20 a gallon for whatever they ultimately define as qualified sales. So you can speculate on how that's all going to work. But really, yes, we are poised to capture PTC in the ethanol segment we're just waiting on finalization of guidance.

And one follow-up on the Venezuela discussion. You mentioned you're already running more Venezuelan crude in the first quarter. What barrels are you pushing out to do that? Are you shifting to an overall heavier copay so pushing out lights and mediums or are you pushing out other heavies?

Yes, this is Randy. It's kind of a mix of everything. I mean depending on the location. It may be some incremental fuel oil cargoes, it may be some Latin America heavy, and it could be Canadian heavy. So it's kind of a bit of a mix. But I would say, as mentioned before, we are pushing to maximize heavy crude processing in the system going forward with the better differentials. .

The next question is coming from Jason Gabelman of TD Cowen.

I wanted to ask another one on the crude quality desk. Given they've widened out quite a bit. And I know you kind of mentioned a bunch of reasons why that is. But if we kind of look back a few years prior to COVID, it seems like there was more kind of saw availability back then than there is now. But at the same time, differentials look wider today than they were prior to COVID. So I guess the question is, do you think that the levels we're at today are sustainable? Are there reasons why the differential should be wider now than they were prior to COVID?

Yes. This is Read, again. I mean I don't know that I have a firm answer on what we think market should be. I think the things that I mentioned before, are kind of chief reasons, and I don't see those really going away as we head through the year. Probably the one thing on the freight side that is kind of pressuring differentials down in the prompt as freight rates have went up significantly, kind of resulted more enforcement on some of these shadow fleet vessels and that could be with us as we head through the rest of the year.

Got it. Great. And my quick follow-up is just on 2026 throughput. It seems like sustaining CapEx is down a couple of hundred million dollars versus what you've done in the past couple of years. So is that an indication that mechanical availability should be higher and given your track record of squeezing out more barrels out of the system, should we expect kind of throughput excluding the shutdown of Benicia to continue to improve?

It's Lane. I would say should be most of it, there's timing, obviously, timing year-over-year differences. But a big part of it is we -- is Benicia. We have one less refinery to sustaining capital on. .

This brings us to the end of the question-and-answer session. I would like to turn the floor back over to Mr. Donovan for closing comments.

Yes. Well, we appreciate everyone joining us today. And of course, feel free to contact our IR team if you have any follow-up questions, and have a wonderful day. .

Ladies and gentlemen, thank you for your participation. 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.

Greetings, and welcome to Valero Energy Corp. Third 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. You may begin.

Good morning, everyone, and welcome to Valero Energy Corporation's Third Quarter 2025 Earnings Conference Call. I'm joined today by Lane Riggs, Chairman, CEO and President; Jason Fraser, Executive Vice President and CFO; Gary Simmons, Executive Vice President and COO; Rich Walsh, Executive Vice President and General Counsel; as well as several other members of Valero's senior management team.

If you have not received a copy of our earnings release, it's available on our website at investorvalero.com. Included with the release or 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, Homer, and good morning, everyone. We're pleased to report strong financial results for the third quarter, highlighting our long-standing track record of operational and commercial excellence. Our refinery throughput utilization was 97% with the Gulf Coast and North Atlantic region setting new all-time highs for throughput following last quarter's record performance in the Gulf Coast. Refining margins remained well supported by strong global demand and persistently low inventory levels despite high utilization rates.

Supply constraints were driven by refinery rationalizations delayed ramp-ups in new facilities and ongoing geopolitical disruptions. These market dynamics contributed to the margin strength despite relatively narrow sour crude differentials. The ethanol segment also delivered a strong quarter, achieving record production and solid earnings. Strategically, we continue to make progress on the FCC unit optimization project at our St. Charles refinery. This initiative will enhance our ability to produce high value product yields, including high octane alkylate. The $230 million project is expected to begin operations in the second half of 2026. Looking ahead, refining fundamentals should remain supported by low inventories and continued supply tightness with planned refinery closures and limited capacity additions beyond 2025. So our crude differentials are also expected to widen with the increased OPEC Plus and Canadian production. In closing, our strong financial results and record operating achievements this quarter are a testament to our commitment to commercial and operational excellence. This, coupled with the strength of our balance sheet should continue to support strong shareholder returns. So with that, Homer, I'll turn the call back over to you.

Thanks, Lane. For the third quarter of 2025, net income attributable to Valero stockholders was $1.1 billion or $3.53 per share compared to $364 million or $1.14 per share for the third quarter of 2024. Excluding the adjustments shown in the earnings release tables, adjusted net income attributable to Valero stockholders was $1.1 billion or $3.66 per share for the third quarter of 2025 compared to $371 million or $1.16 per share for the third quarter of 2024. The refining segment reported $1.6 billion of operating income for the third quarter of 2025 compared to $565 million for the third quarter of 2024.

Adjusted operating income was $1.7 billion for the third quarter of 2025 compared to $568 million for the third quarter of 2024. Refining throughput volumes in the third quarter of 2025 averaged 3.1 million barrels per day or 97% throughput capacity utilization. Adjusted refining cash operating expenses were $4.71 per barrel. The renewable diesel segment reported an operating loss of $28 million for the third quarter of 2025 compared to operating income of $35 million for the third quarter of 2024. Renewable Diesel segment sales volumes averaged 2.7 million gallons per day in the third quarter of 2025. The ethanol segment reported $183 million of operating income for the third quarter of 2025 compared to $153 million for the third quarter of 2024. Ethanol production volumes averaged 4.6 million gallons per day in the third quarter of 2025, achieving record production.

For the third quarter of 2025, G&A expenses were $246 million, net interest expense was $139 million and income tax expense was $390 million. Depreciation and amortization expense was $836 million, which includes approximately $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia refinery next year.

Net cash provided by operating activities was $1.9 billion in the third quarter of 2025. Included in this amount was a $325 million favorable impact from working capital and $86 million of adjusted net cash used in operating activities associated with the other joint venture members share of DGD. Excluding these items, adjusted net cash provided by operating activities was $1.6 billion in the third quarter of 2025. Regarding investing activities, we made $409 million of capital investments in the third quarter of 2025, of which $364 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 $382 million in the third quarter of 2025.

Moving to financing activities. We returned $1.3 billion to our stockholders in the third quarter of 2025, of which $351 million was paid as dividends and $931 million was for the purchase of approximately 5.7 million shares of common stock, resulting in a payout ratio of 78% for the quarter. Year-to-date, we have returned over $2.6 billion through dividends and stock buybacks for a payout ratio of 68%. With respect to our balance sheet, we ended the quarter with $8.4 billion of total debt, $2.2 billion of total finance lease obligations and $4.8 billion of cash and cash equivalents. The debt-to-capitalization ratio, net of cash and cash equivalents was 18% as of September 30, 2025. And 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 2025 to be approximately $1.9 billion, which includes expenditures for turnarounds, catalyst, 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 fourth quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.78 million to 1.83 million barrels per day; Mid-Continent at 420,000 to 440,000 barrels per day; West Coast at 240,000 to 260,000 barrels per day and North Atlantic at 485,000 to 505,000 barrels per day. We expect refining cash operating expenses in the fourth quarter to be approximately $4.80 per barrel. For the renewable diesel segment, we expect sales volumes of approximately 258 million gallons in the fourth quarter, reflecting lower production due to economics. Operating expenses should be $0.52 per gallon, including $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 fourth 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 fourth quarter, net interest expense should be about $135 million. Total depreciation and amortization expense in the fourth quarter should be approximately $815 million, which includes approximately $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia refinery next year.

We expect this incremental depreciation related to the Benicia refinery to be included in D&A for the next 2 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 today is coming from Sam Margolin of Wells Fargo.

On the comment from your opening remarks. As you mentioned, not much of a contribution from heavy crude this quarter on differentials. I guess we're like a year into TMX barrels sort of fully flowing. And I wonder if you could share any insights you have into the differential side as kind of 12 months into TMX and then just on the overall kind of availability picture that's emerging into 2026.

Yes. So I would tell you, we've been somewhat -- I'll start with TMX, somewhat disappointed that TMX hasn't had as much of an impact on West Coast crude values and has really ANS didn't come off like we anticipated would. And most of those barrels are flowing to the Far East. In the broader sense, in terms of quality differentials, we have seen the quality differentials move quite a bit. WCS now trading at a 12% discount to Brent, Maya 14% discount to Brent. Those have been as narrow as 7% previously in the year. On medium sours, we had seen discounts as narrow as 2.5%. That's widened up closer to an 8% discount. So discounts have certainly moved to the point where we are seeing an economic benefit in our system to running medium and heavy sour crudes. Our expectation is you'll continue to see those widen. Although OPEC began unwinding their production cuts in April, much of that volume was offset by an increase in summer power burn. So it wasn't really until September that we saw any meaningful increase in the export volume from OPEC. The pricing signals that are there still suggest that most of that incremental OPEC volume will be directed towards Asia.

However, we've been seeing increased offers to the U.S. market, especially for Rocky crude. We'll be processing both Basra and Kirk Cook during the fourth quarter in our system. The arbitrage to move [indiscernible] into Asia has closed. Additionally, we're starting to see Asia push back on some of the Latin American grades, which ultimately is beginning to pressure medium sours in the Gulf Coast. So all of those effects are things that we're starting to see in October. And as medium sour discounts widen, you'll see heavy sours react remain competitive with medium sour. So we anticipate that to continue to happen as we move through the fourth quarter.

In addition to just OPEC, heavy Canadian production has continued to ramp up as well as some of the deepwater medium sour production in the Gulf and then you've seen Chinese demand has been very high for medium and heavy sour barrels as they fill their SPR. At some point in time, you'd expect that to be full and they would back off. I think the real wildcard here is with the headlines on ramp-up in Russian sanctions yesterday. In the past, we felt like sanctions were largely ineffective. They just result in the change in trade flows. At least if you see the market reaction today, the market believes this round of sanctions could be successful and result in some Russian oil being taken off the market.

On paper, OPEC has the capacity to make up that lost supply, but that certainly could be a headwind to quality differentials. However, it would be very bullish for product cracks.

Okay. I guess we'll keep it on industry macro for a second, if that's okay. And just on the capacity globally next year, we've encountered some feedback about what looks like a fairly heavy schedule of capacity additions next year after a number of years of kind of trailing demand or lagging demand. If you have any insights on to the timing of the capacity additions? Or what do you think we can expect reliability-wise or just a change in balances. That would be much appreciated.

Yes. So our numbers would show about 460,000 barrels a day of total light product demand growth next year. Net capacity additions are about 415,000 barrels a day. So those numbers, if you assume somewhere around an 80% total light product yield on crude, you would still have tighter supply-demand balances next year than what you have this year. In addition to that, I think a lot of the forecast you see assume that new capacity that started up is going to run at nameplate. We haven't seen them be able to get up to nameplate yet. And our expectation is a lot of that capacity won't hit nameplate next year. And then Russian capacity is a real wildcard here, also 1.5 million barrels a day of Russian capacity off-line.

A lot of the forecasts assume that Russian capacity is up and running beginning of the year, our expectation is it will take longer to get that up and running as well. So we expect things to be tighter next year as well.

The next question is coming from Manav Gupta of UBS.

I just quickly wanted to follow-up on that. We are seeing a massive spike in global outages. Russia, Dangote, [indiscernible]. I think over the weekend, there were issues where you had Romania having issues. So what are you seeing in terms of global product markets out there, all these outages and what they are causing for the margins out there? If you could talk a little bit about that.

Manav, this is Gary. I think we've seen good export demand all year fact that we've been unable to restrike inventories in the United States is keeping somewhat of a pull into the domestic market, but the export markets are very good, continue to see really good export demand for gasoline into Latin America and South America on the diesel side, a bigger pull into South America than what we've been seeing freight has really been volatile. And so on the export arbs going to Europe has kind of been up and down and it's really just freight that's kind of been what opens and closes that arm.

If you look today, that arb is marginally open. And while I think you'll start to see a heavier flow going to Europe from the U.S. Gulf Coast on diesel.

Perfect. My quick follow-up is on the capital returns. A big jump in the buybacks. And should we assume if margins remain well above mid-cycle like they are then your payout ratio remaining the same, you would continue to buy back your stock as you did in the third quarter? If you could talk a little bit about the capital discipline as well as the return to shareholders.

Yes. Manav, it's Homer. Absolutely. I mean we've talked about this for the last several quarters. We've been in this mode where effectively all excess free cash flow goes towards share buybacks, and you saw that this quarter as well. You had a small build in cash, but that was largely because of working capital. But I think you should continue to assume that we stay in that mode where any excess free cash flow goes to share repurchases.

Perfect. You have done exactly what you had said that excess cash will go to shareholders store.

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

Yes. Lane, there's been a lot of talk about crude that's on the water and in transit and some estimates have it north of 3 million barrels a day, if you look at some of the shipping tracking data. You guys have unique visibility into whether that crude is actually on the water. And so I'd be curious how your commercial team is seeing it. And do you think it's going to land here in OECD or if that moves into China specifically, and I say that in the spirit of to your point of crude differentials potentially starting to widen out, do you start to see that as the factor that could be the catalyst? And maybe you could talk about Iraq in particular because that could be a leading indicator.

Neil, I'm going to sort of pass the ball over to Gary to answer that question.

Yes, Neil, I kind of alluded to that a little bit previously, but where we see the big change is a lot more Rocky barrels flowing this way. As I mentioned, we have bought Balsara. We've also bought Kercook, and we see that to be a portion of our diet in the fourth quarter and moving forward is really the big change that we've seen. Most of the other barrels seem to be making their way to Asia.

All right. We'll keep on watching. And then the other question is just on some of the non-refining businesses did better than expected than we expected this quarter. Ethanol continues to perform well. And I guess DGD is getting closer to profitability. So can you talk about both of those businesses and whether we're -- there's sustainability at the ethanol margins and weather post the RVO, we are on a path back to the black in DGD.

Neil, this is Eric. Ethanol continues to look positive. I think a lot of that is we've had a record corn crop. Ethanol demand has been strong, both domestically and in the export markets. We're seeing the continued interest in countries going from E0 to E10. Canada has gone to E15 in some of the provinces. And you see Brazil and India looking at moving from the E20s to the E30. And so all of this is creating more ethanol demand in the world. And being the largest exporter of ethanol, that favors our segment pretty well. So cheap feedstock and lots of demand. So ethanol, I think outlook is good and continues to look good in the future. On DGD, you're exactly right. We've seen throughout the year, there's just been a lot of impact from tariffs and policy downturns in the U.S. We've seen fat prices rising for the better part of the year. And I think just most recently, we are seeing enough rationalization in both biodiesel and renewable diesel where fat prices are finally starting to soften.

And with that lower fat price, we've seen DGD margins return back to positive EBITDA. So that's a good sign. That's a good sign for the fourth quarter. Obviously, with the PTC changing Jan 1 on all foreign feedstocks as well as SAP, that will be a challenge as we start 2026. But I think everyone seems to expect that the RVO will be net positive for renewables. That's a lot of speculation because there is a lot of back and forth on these policies right now. But I think the general view is the number is probably going up and will probably be supportive of renewable diesel.

The next question is coming from Theresa Chen of Barclays.

I wanted to talk about your PADD III and PADD II assets and [indiscernible] of 2 major product pipeline binding open seasons that have been announced over the decent weeks to move more volumes from these regions into PAD V given ongoing West Coast refinery closures, including your own Benicia facility. So if one of these 200,000 barrels per day plus systems were to be built, how do you anticipate this could reshape flows and margin capture across your Gulf Coast and the continent assets? And is there any evolution would it make sense for you to be a shipper on 1 of these types.

Yes, Theresa, this is Gary. We engaged in conversations with both the projects that we think could go forward. In both cases, we'll have to wait and see what the final tariff numbers are. It looks like the tariff would be set such a it's competitive versus the Jones Act movement to the West Coast. But we believe we can be more competitive with foreign flag waterborne movements into the West Coast. In addition to that, we like the waterborne movements because, one, the volatility on the West Coast, if you take a position on that pipe, you could be shipping into a closed [indiscernible] of a good portion of the time. And then we like the waterborne option as well because it allows you to source barrels from anywhere in the world and take advantage of international arbs that can be open. So we have connectivity through McKee already to El Paso and in the Phoenix. So we have a lot of that activity as well as based on the pipe from Houston, El Paso. So I don't think you'll see us participate in those projects.

This is Lane. The second part of that would be, you would expect it to firm up the group in the Gulf Coast as barrels do get committed and move West, assuming those projects go through.

That's very helpful. And separately, Gary, there's been some noise in the DOEs as of recently I'd love to get your take on what you're seeing across your domestic distribution channels and your commentary on domestic demand in addition to the color you gave already on exports?

Sure. If you look at our gasoline demand, I think in our system, we would say year-over-year gasoline demand is flat to slightly down, pretty similar to what's in the DOEs. Third quarter, our volumes were flat year-over-year. It looks to us like vehicle miles traveled are up year-over-year, but probably not enough to offset the more efficient automobile fleet. So again, probably flat to slightly down gasoline demand. As I mentioned, export demand looks good. When you look at gasoline fundamentals in addition to good export demand, the transatlantic arb to ship from Europe into New York Harbor is closed, and it's actually closed on paper all the way through the first quarter. So really for this time of year, gasoline fundamentals look about as constructive as you could hope for Obviously, we've transitioned out of driving season, producing high RVP winter grade gasoline, so you wouldn't expect a lot of strength in gasoline cracks in the fourth quarter.

Jet demand, we're continuing to see good nominations from the airline. So again, comparing to the DOEs which show about a 4% bump in jet demand. That looks consistent with what we're seeing in the market. And then finally, on diesel. In our system, in the third quarter, year-over-year sales were up 8%. I don't think that's representative of the broader market. DOE data showing about a 2% year-over-year increase in diesel demand is probably close. We've seen good agricultural demand in our system. That continues. It's the harvest season starting to wind down, but then you'll start heating oil season, which again be a good pop in demand. And as I mentioned, good export demand as well. Freight volatility is hindering that, but the demand is there.

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

Lane, your throughput performance has been extraordinary again. My question is kind of a bigger picture. I guess it's kind of an AI, machine learning kind of question. And I'm wondering if there's a change going on in how you're running your business, things like planned turnarounds just in time as opposed to the behavioral once every 4 year kind of deliver. Is there anything happening that would lead us to think some of this throughput performance could be sustainable, not just for you but perhaps for the broader industry.

Doug, I'm going to have Greg Bram to sort of start off on this question.

Doug, so the journey you're talking about related to how we plan turnarounds. We've embarked on that for, gosh, probably at least a decade. So I wouldn't say there's a shift there, but we definitely have reaped some benefits from the kind of the approach we take now, which aligns with kind of the way you described it. But if you want to talk about AI in general, I'd say that we're probably cautiously optimistic about how that can help us further improve our availability. We're we're evaluating a number of places where we can use that technology. As you'd expect, focusing on areas where we think we can create some tangible value and we've deployed that in some of those new techniques and a few applications. But I think one of the key learnings that we picked up as we've embarked on looking at AI machine learning applications is that you really have to have good quality data of your operation to have a successful use of that kind of a tool. And I think it's an advantage for us because we've embarked on an effort to improve that data and gather that data in kind of a consistent way kind of consistent practices across our system, again, probably 10 or 15 years ago. And so having that data makes it makes the opportunity to try to use that to make further improvements more real. And so we start from a good place. You've mentioned the quality of our operation today, good performance to start with. But again, some optimism that AI type techniques can help us make some further improvements.

I appreciate the answer. I guess we're trying to figure out if we should lift our expectations of mid-cycle throughput for Valero. I guess that was at the rear of my question, but I appreciate the insights. My follow-up, and I apologize to Homer specifically because I've had a couple of chances to talk to him this morning about this already. But I'm trying to understand what's going on with the cash flow because your tax rate is obviously up a little bit on mix. But if we look at the translation of your earnings to your cash flow, a big beat on earnings didn't show up in cash flow. And we're trying to figure out if there are some transitory issues and there don't necessarily go into all the specifics, but is cash tax part of that? Or was there another reason that this might be seems a transitory quarter from that standpoint, maybe for Jason.

Doug, it's Homer. I mean, you'll see this when you see the Q file, but part of that is some -- like PTC, for example, you book it within earnings and then obviously, the payment comes in later. So you'll see that as a deduct from net cash flow from operations. So that's one of the big variances. Again, you'll see that when you see the statement of cash flow isn't the key.

So no tax issue, Homer, no temporary tax issues.

There might be some small deferred tax items, but nothing that's substantial.

All right. We'll have to wait in the queue appreciate.

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

Maybe one on refining utilization. U.S. refining utilization has been quite strong versus historical norms over the last 6 months. Any thoughts on drivers of this, whether it's an impact of exited a period of heavy maintenance over the last couple of years? And any thoughts on whether like suggestions that this -- that would prevent this from normalizing as we head into next year? Or are there reasons to believe that we can -- the U.S. system can continue to running this hard?

Ryan, it's Lane. So you're talking about just the U.S. industry refining utilizations improved over the last few years.

Yes. I mean it's been very strong this year, not like over the last 4 or 5 months.

I'll start and let Gary or Greg tune me afterwards. I think we started on the journey, I'm going to say 15 years ago, to work extensively on our reliability, and we actually showed that this could be done. I think A lot of the rest of the industry is sort of working on the same things. They're getting better at it, being more careful in their execution. The systems are getting better, whether like the previous question, from Doug, how many people are using something that they might call AI. I don't know, but there are systems out there to let you execute turnarounds better, do your maintenance better, have some predictive capabilities with respect to failure mechanism, which all that improves what we actually term is availability. Even through -- even better scheduling, things like this. And I think generally, the industry has done a little better job on this. So that's how I would answer it.

The only thing I might add, Lane, [indiscernible] just maybe the only thing I would add, the only thing I think about when I think about this past summer versus some of the previous periods is we didn't really have a lot of extreme weather throughout the summer and refineries run well when you kind of got nice ambient conditions. And so I think we all have been incented to run hard for -- throughout these different periods. Could be maintenance part of it. It could just be that when you're not dealing with a lot of really hot temperatures, you can definitely tune up the operation and eke out that last little bit. So I don't have proof of that. But when I think about how our operation runs, I can see that being a positive impact this past summer.

Well, that's a great point. Hurricane, we have not hurricane activities to be given [indiscernible].

Right. Maybe one other, as we think about the fourth quarter here. During the third quarter, there were a number of things that were -- I mean, you were a great quarter, but there are a number of things that were got, I would say, like modest headwinds on margin capture, whether it was narrow differentials crude backwardation, some West Coast jet fuel dynamics and secondary products, et cetera. Many of these appear to have reversed or improved here early on in the fourth quarter. Any thoughts on direction of some of these trends that may impact the type of capture of profitability that we see during the fourth quarter and what looks like a pretty strong environment.

Yes, Ryan, it's Greg. It's early for the fourth quarter, right? And you did mention a few of the things that have have turned more favorable as we've gotten started out here in October. A couple of things I always think about as we approach the winter season, we'll blend more butane into gasoline as RVP shifts to winter specifications. That tends to be -- create some uplift on margin capture. But I think it's also worth doing. While there have been a number of things that have moved favorably. You still have some pretty weak secondary products, naphtha's turned a bit weaker. Propylene continues to be fairly weak. So there are a few things out there that have not really turned positively yet as we started out in the quarter.

The next question is coming from Paul Cheng of Scotiabank.

Just before my question, just curious that and have a comment. I was surprised that you guys did increase your G&A full year. I thought with the strong earnings that you guys are going to increase your bonus accrual. So I was surprised maybe that is a part of the cost savings from Lane.

Yes, [ let's not ] when we'd eagerly jump on for.

So I told Homer that this is not going to count as my question. But anyway.

That is a good comment, Paul.

Okay. My question is actually that in the third quarter, I think part of the issue related to the margin capture is on the octane, octane value comparing to the second quarter, I think, has come down just curious that if you guys will be able to share some insights what happened? And then whether you think that will continue that trend? Secondly, I want to go back into not so much about just AI, but also robotic technology and all that. So Lane and the team or Greg, do you guys think that we are seeing all this new technology now available to you is more the evolution or that is going to transform the way how you guys may conduct business, not just near -- in the refining side, but also in your back office in your trading commercial, as such that I mean we have seen your upstream counterparts some of them that announced some pretty sizable cost reduction effort because of the new technologies. Just wanted to see where we stand for you guys or for the industry?

So maybe I'll take the naphtha question and let Greg take the second one. So -- or the octane question, sorry. When we look at Octane, we tend to view that it trades at an inverse to naphtha. So what you really had in the last quarter was naphtha got a little bit stronger. And I think there are several reasons for that. You had less naphtha coming out of Russia. You had some of the naphtha from the U.S. Gulf Coast going back to Venezuela as diluent. And then you're seeing a little bit more nettable to Asia into the pet chem market. So when naphtha's weak, there's a big incentive to try to blend it into gasoline and that takes octane to do it, but naphtha get stronger, there's less of an incentive. So although the regrade octane, regrade was a little bit weaker, it probably helped set up stronger gasoline fundamentals.

All right, Paul. And so this is Greg. On the question around robotic automation and AI. I think maybe -- we don't talk about this a lot, but we've been using those techniques and further expanding the use of those techniques over time as -- again, as they make sense in terms of improving efficiency. And it improves our ability to inspect equipment certainly to execute some of the work that we do. So that will continue to grow. I suspect and some of these new techniques will create more opportunity to use those tools going forward, which is kind of back to the answer before. I think there will be some improvement that comes from this -- some of this new technology and these new techniques that are out there. And it will be -- if you start from a really good place like we do, it's going to be harder to find a lot of big opportunities there, but we're certainly focused on trying to find ones that make good sense from a value standpoint.

And Paul, I'll add to it on some examples of those things is we like many other people in the industry, have been using robotics with respect to tank cleaning. I can see where the upstream guys would really -- that would really help them. The other thing that we've used is drones for inspection, like if you go into a -- today, we get into a big structure on an FCC and we can actually just rather than have to get in scaffold up to a particular location that might be problematic, we can put a drone in, float up, look at it, understand that situation without having to -- we may have to go back in and put scaffold, but now we understand the scope of work. So there are certainly things like that. And then with -- in our systems, we're always trying to think about ways to consolidate our control rooms and work on being more efficient with the operators that we have and some of which has to do with technology improvement.

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

So I want to start on the refining side. And with the strength in the diesel crack, can you talk about the ability to maintain the strong, I think it was 38% or 39% diesel yield level going forward? And then as part of that, the crude slate got a bit lighter quarter-over-quarter, but the diesel yield also stepped up, which I was hoping you could talk to as well.

So I'll take -- I'll start with the second one, I think. So well, actually, I can probably cover both of them. Yes. Joe, we've had strong diesel yield. That 38%, 39% is not too far from where we've run in the past. It reflects a mode of operation where we're maximizing diesel production or distillate production over gasoline. Again, as we kind of tuned up the operation and ran very well in the quarter, I think you saw us reach some of the highest levels that I think we can achieve with the current hardware we have. So sustainable, we can probably stick in this range with continued strong operations like we had.

Yes, remind me, Joe, what was the second part of that question?

Yes. So I was just asking about the crude slate got a bit lighter quarter-over-quarter. You're able to step up the distillate yields. So just hoping you get a little bit thoughts on that.

Yes. No, we did get a little bit lighter, but I think in some of the places where we lightened up, we were still able to -- the growth was more on the jet side than on the diesel side, and we were able to to kind of drop that back into the naphtha into the jet, still make a distillate product and had good incentive to do so. So I'm not sure that the slate itself, if I were to try to back in, and I haven't tried to back into what was the total available distillate yield. But I don't know that it was a big enough shift in some of the places where we got lighter that would have had a material impact on our yield there.

Great. That's helpful. And then, Eric, I wanted to shift to RD. And then -- wait for clarity on the RVO and the SRU reallocation. Can you talk to how you're thinking about the path for D4 RINs here and then as part of that, is there a level that you think it needs to rise to incentivize the marginal producer?

Yes. I think it's one of those things where there's more variables than knowns. I mean -- so -- but there's any number of combinations of a number, an SRE, a reallocation and a final number. But any combination of those numbers, the current number is $3.3 billion D4s. I think if you go back and look at the original premise of keeping the BD producer breakeven with a $1 BTC, they've done a lot of work this year with removing [indiscernible] out of the model for soybean oil. They gave a small producer benefit, which I think counts almost every single BD producer. And I think they're around $0.70 to $0.80 versus that $1 last year. So this last $0.20 is probably -- if you took that to a D4 RIN, you probably need RINs to go up something like $0.25 to $0.30 to get BD back to breakeven. So that's kind of how I see -- so any combination of the math that gets to that kind of number essentially satisfies the original design of trying to keep BD operational.

What that number translates out to RINs is a number higher than today. Although 1 of the challenges, I think, is they're trying to figure out this math is 25 D4 RIN production is down versus last year. So we're -- we have a current target of 3.3. If we underperform that number, we will consume the bank early into next year. So depending on how high you set that number, it's very difficult to pick exactly where you'll meet that BD requirement, but not overshoot and then create an impact to overall diesel prices. So I think that's kind of the challenge of how this works. But if I try to anchor on something, I go back to the dollar BTC and where was the BD producer and where are they today? And so I think there's still a gap there. And clearly, with the trade issue with China and soybean oil and soybeans in general, how that plays into this is really difficult to predict. But I think the math is something like that.

I realize there's a lot of moving pieces, but I appreciate your thoughts.

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

Specific to the heavy sour mix in the Gulf Coast, can you just talk through the moving pieces here with Mexico production declining, the Venezuela uncertainty. I assume that wasn't any help in the quarter and also just Canada TMX capacity? And then also just how fuel imports might be helping replace some of these barrels in your Gulf Coast system. And maybe also just touch on [indiscernible] margins with high diesel cracks, but also still tight differentials.

Yes. So overall, yes, we do see declining production from Mexico. Our volumes from Mexico aren't really down much yet, but they continue to forecast that we'll see declining production from Mexico. A lot of that is being made up with additional volumes from Canada as they continue to ramp up production and fill the pipeline capacity coming to the Gulf. So I would say those somewhat offset each other. We do have Venezuelan barrels back in the mix, which is helping. And then the additional OPEC production, as I alluded to, getting the baser barrels and [indiscernible] barrels, all that really, I think you'll see in the fourth quarter a heavier crude diet than what we had in the third quarter. filling out a lot of our conversion capacity.

On the high-sulfur fuel oil question, actually, high sulfur fuel has been pretty strong. And we haven't seen a real strong incentive to buy high sulfur fuel to put into [indiscernible]. There's been some opportunistic purchases, but for the most part, on paper, those economics haven't been strong.

Okay. Great. And then on the planned Benicia closure, you did have the charge in the quarter. Recognizing the state would like to keep this open and the official close date is it in April, but when do you kind of reach the point of no return here just given preparations needed and scheduled turnaround?

This is Rich Walsh. I'll take an effort to answer at least the interaction with the government part of it. I mean we have been in discussions with California, but nothing has materialized out of that. And so as a result, nothing has changed. Our plans are still moving forward as we've shared and as we've informed the state. So I don't see anything changing on that.

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

Could you talk about DGD performance so far in the fourth quarter? I think your indicator is just quite a bit maybe $0.36 a gallon quarter-over-quarter. Are you realizing that improvement so far? Or are there other factors we need to take into account, like hedging or feedstock lag? Or I think some of the staff credits changed on October 1. But yes, just any sort of broader commentary on DGDs so far in Q4 would be great.

Yes. I think most of that, I would say, is tied to lower feedstock prices. I think you're seeing rationalization and feedstock prices starting to come off. And so a lot of that is improving the profitability of DGD. We still have strong staff benefits both in the U.S. and in the European and U.K. markets. So that's an advantage that DGD has over a lot of other RD producers and SAP has a premium in the base. And so fourth quarter looks good from an overall production rate standpoint as well as just PTC capture and on lower fat prices is really the fourth quarter.

I think the question is still going to be as we enter into '26, will you see adequate premiums on staff to cover the loss of the PTC benefit. And are you going to see, as we were -- we've discussed a couple of times, what is going to be the RVO impact because that will have to be the vehicle to make up any gap in profitability for biodiesel and renewable diesel to comply with wherever the RVO gets set. And so we still have a lot of policy that appears to be in conflict of increased RVO but decreased generation because of foreign feedstocks. Those are all going to be things where you're trying to raise the number, but make it more difficult to generate that usually is going to mean higher RIN prices. And so I think that is the question that everyone's got to get settled on. And I think there's good awareness of how these knobs will affect the overall market. But I think those are the 2 things that will determine whether or not this fourth quarter improved profitability can continue into '26.

Indeed, a lot of moving parts there. And then if I could follow up on Theresa's question on the new product pipes that are headed West. Could you talk about what this means for the prospects for your Wilmington refinery, I think Los Angeles currently ships about 125 a day of product East out of the market to Phoenix. If one of the proposal goes through, then Los Angeles could actually receive about 200 a day. So that's a pretty big shift on California supply/demand and do you think Wilmington would be able to compete with an extra 200 a day coming into that Los Angeles market?

Yes, this is Gary. I think when we look at the numbers, if you look at the California market today, it looks like it's being set by import parity. And if you look at the tariffs on those pipes, import parity through the pipeline doesn't look to be significantly different than import parity on the waterborne barrels. So I don't know that you'll see much of a change in the California market as a result of the pipelines.

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

Hopefully, two quick ones. First, just on the Russian refining disruptions. There's a lot of headlines on the Ukraine drone strikes, but it does seem like in many cases, the refineries come back online quickly. So I was wondering if you could provide some numbers around the amount of disruption that you're seeing on Russian product exports and kind of before today, trying to parse out how much of the product strength was driven by actual disruptions versus geopolitical risk premium in the prices?

And then my second one is on the Benicia shutdown. Can you talk about your plans to resupply the market? Or are you going to have to kind of import products from Asia in order to meet your contractual obligations? Or do you not have really many outstanding in that market once the plant shuts down.

Yes, I'll take the first part of that. I think we do think the drone strikes have been pretty effective. It looks like a lot of what's happening in Russia is that they're largely attacking some of the higher complexity refining capacity. And so as that happens, then Russia will go ahead and ramp up some of the lower complexity refining capacity. So you can kind of see that with the fuel exports and some of those things.

The second part of your question, I think the spike we're seeing today is not so much due to any kind of disruption from Russia yet. It is just hyping the market on what could happen in the future. But we definitely see exports from -- product exports from Russia falling.

Jason, this is Lane on the second part. Our intent is to continue to supply our contractual obligations for our wholesale business after we shut down the refinery.

Okay. And those would be essentially imports from Asia presumably.

It could be from anywhere in the world. This is kind of what Gary alluded to earlier, waterborne alleged, you have optionality to try to work hours into that short versus maybe having a huge commitment on the pipeline. It's -- so that's sort of our intent. We're not going to go out and turn up barrels from some particular market, we'll figure out how to supply it.

The next question is coming from Nitin Kumar of Mizuho Securities.

I really just have one although a part a and b. You've talked a little bit about the crude spreads widening from here on out. Just maybe some thoughts on what do you see the mid-cycle also at least 12-month view on some of these spreads because you should have at least based on what's going on between Canada Iraqi barrels, you were mentioning there seems to be a lot of supply of heavier crudes coming at the same time to the market. And then maybe part B is, given your complexity, especially in the Gulf Coast, you have like a buffet of crudes that you could choose from. Is there a specific crude that you think falls to the bottom if it's not discounted appropriately?

Yes. So I'll just take a stab at that. I guess our view is, without getting into a lot of specifics on what we call mid-cycle, I guess we would say where the quality differentials are today, it would be a little inside of what we view as mid-cycle, and we do see those continuing to widen going forward. In terms of crude we see falling out, I don't really know that I have a view on that, Greg. I don't know if you have one, but.

What I'd probably add, if you look back, and I think the market works its way today as well, the the Latin American grades are the ones that tend to be the swing. And so they're probably the 1 that's kind of moved into fill holes when there was a short in the Gulf Coast, they're probably the first ones that would back out as some of that supply comes in.

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

Great. Thank you, Donna. We appreciate everyone joining us today. And as always, please feel free to contact the IR team if you have any additional questions. Have a great day, everyone. Thank you.

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