瓦萊羅能源 (VLO) 2025 Q4 法說會逐字稿

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 US.

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.

With 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 non-cash 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 non-cash 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. (Event Instructions)

(Operator Instructions)

Theresa Chen, Barclays.

Good morning. 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?

Yeah, 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 five-year average on total light product inventory to above the five-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 US 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.

Hi there, Theresa. This is Randy. I'll kick that off. Obviously having the Venezuela supply kind of back in the fold for our system is great news. The x-forces coming 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 US 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 US 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 US 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.

Thank you, Randy.

Neil Mehta, Goldman Sachs.

Yeah. Good morning, team. 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.

Hey, Neil, good morning. 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 non-discretionary. 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.

Yeah. That's a great answer, Homer. So thank you for that perspective. 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.

Hey, 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 three authorized sellers of crude and we purchased barrels from all three. So we anticipate the Venezuelan crude making up a pretty large part of our heavy diet as we move into February and March.

Great.

Manav Gupta, 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 a more serious note, Homer, look, even when we go back four or five 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 four or five 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?

Yeah. Hey, 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.

Yeah. Hey, 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.

Thank you so much.

Douglas Leggate, Wolfe Research.

Hey, good morning, everyobody. I'm sure Brian has already told you about my family connection, but welcome, Brian. Guys, I wonder if I could just ask two 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 an [AMV and FID] 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 where 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. Thanks.

Yeah. 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 UK, 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.

Great answer, Eric. Thanks so much.

Paul Cheng, Scotiabank.

Hey, guys. Good morning. 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 is 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?

Hey, Paul, it's Lane. I'll take a stab at the first one. I just -- yeah, 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 --

Yeah. 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. Thank you.

Yeah, 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.

Thank you.

Ryan Todd, Piper Sandler.

Okay. Thanks. 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 timeline of the coming shutdown of Benicia and how you're thinking about West Coast dynamics for 2026?

Yes. I'll start on the first. Yeah, 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 two 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 timeline 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. Thank you. 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?

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

Yeah. Look, UK 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 US 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.

Great. Thank you.

Paul Sankey, Sankey Research.

Morning, everyone. Glad to hear Brian that you got the job because of your close family relationship to Douglas Leggate. (inaudible) 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 US 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. Thanks.

Yeah, Paul, I'll just touch on the flat price. I think what we're seeing right now with the geopolitical [rambling] 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?

Yeah. 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. Thanks. 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 US light sweet production whether there might be more CapEx to be undertaken?

Hey, 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 -- 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.

I appreciate that, thank you.

Sam Margolin, Wells Fargo.

Hey, morning. Thanks for the question. On revisiting 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?

Hey, 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 five years or six years or something like that, our 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 (inaudible) 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 [full] price it -- and do you believe the [full price tag] 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. Thank you. 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.

Hey, 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.

Thanks so much.

Joe Laetsch, Morgan Stanley.

Great. Thanks and thank you for taking my questions. 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? Thank you.

Sure. Yeah. 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 two 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 two 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 (inaudible) solution for SRE over authorization. And so those will have to (inaudible)

Great. Thanks. 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. Thank you.

Yeah. 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 US, 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.

Great. Thank you.

Phillip Jungwirth, BMO Capital Markets.

Thanks, good morning. As far as Russia, how are you seeing the EU refinery loophole sanctions impacting diesel markets? And could there be a greater call on US 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?

Yeah, 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 US Gulf Coast, which has been supportive of the US 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.

That's helpful. Thanks, guys.

Jean Ann Salisbury, Bank of America.

Hi, good morning. 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?

Yeah. 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 UK significantly, and it certainly improves the capture rate when that happens.

Okay. Thanks. 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.

That's helpful. Thank you.

Matthew Blair, Tudor, Pickering, Holt.

Thank you and good morning. 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.

Yeah. this is right. 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.

Thank you. 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?

Yeah, 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.

Great. Thank you.

Jason Gabelman, TD Cowen.

Yeah. Hey, thanks for taking my questions. 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? Thanks.

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. Thanks. 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.

All right. Thanks.

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.

Yeah. 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.