Q3 2025 Earnings Call Transcript

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 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, 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 of 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. Sour crude differentials are also expected to widen with the increased OPEC+ 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 member's 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's 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 -- this is a 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 it has -- really, ANS didn't come off like we anticipated it 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 had 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 Kirkuk during the fourth quarter in our system. The arbitrage to move Mars 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 to 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 a 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 queue 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, Dos Bocas. 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. The fact that we've been unable to restock 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, it's kind of been up and down, and it's really just freight that's kind of been what opens and closes that arb. If you look today, that arb is marginally open. And 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 towards share repurchases.

Perfect. You have done exactly what you had said that excess cash will go to shareholders though, thank you for that. Thank you, sir.

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 Basra. We've also bought Kirkuk, 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 it. And 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 E30s. 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 for the fourth quarter.

Obviously, with the PTC changing Jan 1 on all foreign feedstocks as well as SAF, 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 in light of 2 major product pipeline binding open seasons that have been announced over the recent weeks to move more volumes from these regions into PADD 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 Mid-Continent assets? And is there any volition, would it make sense for you to be a shipper on one of these pipes?

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 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 arb 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 into Phoenix.

So we have a lot of connectivity as well as space on the pipe from Houston to 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. 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 deal.

If there's 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?

Yes. 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 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 root 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 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's some transitory issues in 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 seen as a transitory quarter from that standpoint? Maybe for Jason.

Doug, it's Homer. I mean, you'll see this when you see the Q filed, 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 flows in the Q.

So no tax issue, Homer? No temporary tax issues?

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

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 exiting 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 run in -- running this hard?

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

Yes. I mean it's been very strong this year, like over the last 4 or 5 months.

Well, 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, and 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 -- Ryan, 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. It 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 had any hurricane activities to speak of in the Gulf.

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 had a great quarter, but there are a number of things that were, I would say, like modest headwinds on margin capture, whether it was narrow crude 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 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 noting while there have been a number of things that have moved favorably, you still have some pretty weak secondary products. Naphtha has 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 didn't 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, that's not one we'd eagerly jump on.

I told Homer that this is not going to be counted as my question. But anyway...

We will count that as 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 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 technology. 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 that octane question, sorry. When we look at octane, we tend to view that it trades at an inverse to naphtha. And 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 naphtha pulled 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 when naphtha gets stronger, there's less of an incentive. So although the regrade -- the 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. The only -- some examples of those things is we, like lot -- many other people in the industry have been using robotics with respect to tank cleaning. I could 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, flow it 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. 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. Remind me, Joe, what was the second part of that question?

Yes. I was just asking about the crude slate got a bit lighter quarter-over-quarter, but you were able to step up the distillate yield. So just hoping you get a little bit of 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 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 distillate -- or our yield there.

Great. That's helpful. And then, Eric, I wanted to shift to RD. And then as we wait for clarity on the RVO and the SRE 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, 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 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 ILUC 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 one 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.

Great. 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 coker 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 Basra barrels and Kirkuk 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 oil has been pretty strong.

And we haven't seen a real strong incentive to buy high sulfur fuel oil to put into coker. So 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 in April, but when do you kind of reach the point of no return here just given preparations needed and the 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 up 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 SAF 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 SAF 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 SAF 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 SAF 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, 2 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 hype in 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 allows you to have optionality to try to work arbs into that short versus maybe having a huge commitment on the pipeline. It's -- that's sort of our intent. We're not going to go out and term 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, I'll do 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 or sort of 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 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 would 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 Latin American grades are the ones that tend to be the swing. And so they're probably the one that's kind of moved into fill holes when there was a short in the Gulf Coast. So 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.

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.