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DATE

Thursday, January 29, 2026 at 10 a.m. ET

CALL PARTICIPANTS

  • President and Chief Executive Officer — Lane Riggs
  • Executive Vice President and Chief Financial Officer — Homer Bhullar
  • Executive Vice President and Chief Operating Officer — Gary Simmons
  • Executive Vice President — Randy (surname not stated in transcript)
  • Executive Vice President — Eddie (surname not stated in transcript)
  • Executive Vice President — Eric Fisher
  • Executive Vice President — Rich Walsh
  • Vice President, Investor Relations — Brian Donovan

TAKEAWAYS

  • Net Income Attributable to Stockholders -- $2.3 billion, or $7.57 per share, reported for the year, down from $2.8 billion, or $8.58 per share, in 2024.
  • Adjusted Net Income Attributable to Stockholders -- $3.3 billion, or $10.61 per share, versus $2.7 billion, or $8.48 per share, in 2024.
  • Refining Segment Operating Income -- $1.7 billion for the year compared to $437 million the prior year.
  • Renewable Diesel Segment Operating Income -- $92 million, down from $170 million in 2024.
  • Ethanol Segment Operating Income -- $117 million, up from $20 million in 2024.
  • Refining Throughput Volumes -- Averaged 3.1 million barrels per day, representing 98% capacity utilization and a record high for both the quarter and year.
  • Refining Cash Operating Expenses -- $5.3 per barrel in the year.
  • Renewable Diesel Sales Volumes -- Averaged 3.1 million gallons per day.
  • Ethanol Production Volumes -- Set a record at 4.8 million gallons per day in the fourth quarter.
  • General & Administrative Expenses -- $315 million in the quarter, $1 billion for the year.
  • Depreciation & Amortization -- $817 million, including approximately $100 million related to idling the Benicia refinery.
  • Net Interest Expense -- $139 million, and Income Tax Expense -- $355 million; effective tax rate was 25%.
  • Net Cash Provided by Operating Activities -- $5.8 billion for the year; adjusted to $6 billion excluding working capital and DGD-related items.
  • Capital Investments -- $1.8 billion attributed to Valero for the year; $405 million in the fourth quarter.
  • Shareholder Cash Returns -- $1.4 billion in the quarter and $4 billion for the year, with payout ratios of 66% and 67%, respectively.
  • Shares Outstanding -- 299 million as of year-end, reflecting a 5% annual reduction and 42% reduction since 2014.
  • Dividend Increase -- 6% quarterly cash dividend raise approved by the Board in January 2026.
  • Total Debt -- $8.3 billion; Finance Lease Obligations -- $2.4 billion; Cash and Cash Equivalents -- $4.7 billion; Debt to Capitalization (net of cash) -- 18%.
  • Available Liquidity (Excluding Cash) -- $5.3 billion at quarter-end.
  • 2026 CapEx Guidance -- $1.7 billion, with $1.4 billion allocated to sustaining business and the remainder to growth projects.
  • Projected Q1 Refining Throughput -- Gulf Coast, 1.695-1.745 million bpd; Midcontinent, 430,000-450,000 bpd; West Coast, 160,000-180,000 bpd; North Atlantic, 485,000-505,000 bpd.
  • Q1 Refining Cash Operating Expense Guidance -- Approximately $5.17 per barrel.
  • Q1 Renewable Diesel Sales Volumes Guidance -- Approximately 260 million gallons; operating expense $0.72 per gallon (including $0.35 per gallon non-cash costs).
  • Q1 Ethanol Production Guidance -- 4.6 million gallons per day; operating expenses of $0.49 per gallon ($0.05 non-cash costs included).
  • Q1 Net Interest Expense Guidance -- Approximately $140 million.
  • Q1 Depreciation & Amortization Guidance -- About $835 million, with $100 million related to the Benicia refinery idling.
  • 2026 G&A Expense Guidance -- Approximately $960 million.
  • West Coast Results -- Capture rates negatively impacted by "gasoline relative to diesel gasoline pretty weak relative to diesel" and retroactive pipeline tariff charges in the fourth quarter.
  • Benicia Refinery Idling -- Units to be idled in February 2026 due to mandatory inspection requirements; the company will import gasoline and blend components to support the Bay Area supply.
  • Board Commitment -- Minimum annual payout ratio target of 40%-50% of adjusted net cash from operations; long-term net debt to cap ratio targeted at 20%-30%.

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RISKS

  • Renewable diesel segment operating income declined to $92 million from $170 million; management cited ongoing policy uncertainty impacting market reentry, causing some capacity to remain offline as "a lot of players that are now sitting out waiting for guidance to get finalized before they reenter the market."
  • West Coast capture rates suffered from retroactive tariffs and weak gasoline margins, directly reducing segment profitability in the quarter.
  • Management identified ongoing regulatory risk regarding the Renewable Volume Obligation (RVO) and Small Refinery Exemptions (SREs) as "a challenge for the agency" and a potential negative for future policy clarity.
  • Incremental depreciation associated with Benicia refinery idling reduces quarterly earnings by approximately $0.25 per share based on current shares outstanding.

SUMMARY

Valero Energy Corporation (VLO +2.30%) reported a year-over-year drop in GAAP net income but delivered record refining throughput, capacity utilization, and ethanol production for both the quarter and full year. The company announced a 6% dividend increase and continued aggressive share repurchases, reducing shares outstanding by 5% annually and 42% since 2014. Management stated that favorable heavy crude differentials, including increased Venezuelan and Canadian supply, are expanding refining margins while capital discipline and sustained high cash balances enable ongoing shareholder returns.

  • The St. Charles refinery SCC optimization project remains on track for a 2026 startup, with $230 million expected total investment.
  • Refining segment operating income increased sharply, but renewable diesel profitability was pressured by capacity offline and policy delays; management expects 2026 to be stronger for renewables, pending final guidance.
  • Valero confirmed capability to expand Venezuelan heavy crude processing above historical highs due to recent investments, increasing flexibility in heavy crude sourcing.
  • Management described current U.S. fuel inventory builds as resulting from "very high refiner utilization" rather than weak demand, citing record December utilization at 95.4% and rising export volumes.
  • Ethanol segment margins benefited from increased export demand and favorable feedstock costs, with all plants positioned to capture future Production Tax Credits once federal guidance is clarified.
  • Coker utilization rates are not publicly disclosed, but management indicated ongoing optimization, with heavy crude expected to fill available capacity as more becomes available.
  • Sustaining capital expenditures are expected to decrease partly due to the idling of the Benicia refinery, lowering long-term maintenance costs.
  • Management asserts that execution risk in global capacity additions and ongoing global supply constraints could maintain tightness in refining markets through 2026.

INDUSTRY GLOSSARY

  • SCC: Secondary Cracking Complex, a refinery unit focused on improving yields of high-value products like alkylate.
  • DGD: Diamond Green Diesel, Valero’s renewable diesel production joint venture.
  • PTC: Production Tax Credit, a U.S. federal policy incentive for renewable fuel production, now income-tax based.
  • RVO: Renewable Volume Obligation, the EPA-mandated renewable fuel blending requirement for U.S. refiners.
  • SRE: Small Refinery Exemption, an EPA-granted waiver from RVO compliance for qualifying refineries.
  • D4 RIN: A Renewable Identification Number associated with the RVO, specific to biodiesel and renewable diesel compliance credits.
  • Capture Rate: The percentage of published spot market margin that a refinery realizes in its reported financial results.

Full Conference Call Transcript

Lane Riggs: 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, environmentally responsible operations resulted in a record refining 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 SCC unit optimization project at our St. Charles refinery. This $230 million initiative will enhance our ability to produce high-valued product yields, including alkylate. We still expect the project to begin operations in 2026. Looking ahead, we believe refining fundamentals should remain supported by continued demand growth and a 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.

Homer Bhullar: Thank you, Lane. For 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 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 2025 compared to $207 million or $0.64 per share for 2024. For 2025, net income attributable to Valero's 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 '24.

The refining segment reported $1.7 billion of operating income for 2025 compared to $437 million for 2024. Adjusted operating income was $1.7 billion for 2025 compared to $441 million for 2024. Refining throughput volumes in 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 $5.3 per barrel in 2025. The renewable diesel segment reported operating income of $92 million for 2025 compared to $170 million for 2024. Renewable diesel segment sales volumes averaged 3.1 million gallons per day in 2025.

The ethanol segment reported $117 million of operating income for 2025 compared to $20 million for 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 2025 and $1 billion for the full year. Depreciation and amortization expense was $817 million for 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 2025. The effective tax rate was 25% for 2025. Net cash provided by operating activities was $2.1 billion in 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 a $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 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 total debt, $2.4 billion of total finance lease obligations, and $4.7 billion cash and cash equivalents. The debt to capitalization ratio net of cash and cash equivalents was 18% as of 12/31/2025.

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 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 assets.

For modeling our first quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.695 to 1.745 million barrels per day, Midcontinent at 430 to 450 thousand barrels per day, West Coast at 160 to 180 thousand barrels per day, and North Atlantic at 485 to 505 thousand 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 72¢ per gallon, including 35¢ per gallon for noncash costs such as depreciation and amortization.

Our Ethanol segment is expected to produce 4.6 million gallons per day in the first quarter, operating expenses should average $0.49 per gallon, which includes 5¢ per gallon for noncash costs such as depreciation and amortization. For the first quarter, net interest expense should be about $140 million. Total depreciation and amortization expense in the first quarter should be approximately $835 million, which includes approximately $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia refinery. We expect incremental depreciation related to the Benicia refinery to be included in D&A for the first quarter and in April. The 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.

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

Operator: Thank you. The floor is now open for questions. The first question is coming from Theresa Chen of Barclays. Please go ahead.

Theresa Chen: 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 precarious supply and demand setup given significant capacity slated to come online in Asia balanced against limited closures for the year. In light of these developments, how do you view the evolution of and demand dynamics for light products and crack spreads going forward?

Gary Simmons: Yes, Theresa, this is Gary. Certainly, during November and December, we saw fairly significant builds in total light product inventory. It followed typical seasonal patterns, but the magnitude of the build was much larger than we typically see. So we kinda went from below the five-year average on total light product 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 refiner 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 pad three. And, you know, we've always stated we like our position in pad three because it allows you to clear any link to the export markets.

We didn't really build any inventory during the fourth quarter. Didn't see any economic incentive to carry inventory or produce summer grade gas, so we're not really sure what caused the inventory build in pad three. Going forward, when you look at 2026, most of the consultant data shows similar supply-demand balances to last year, but they are assuming lower refinery utilization. You know, refinery utilization coming back to normal levels. I think we agree with that. You know, you've already seen utilization drop as we start into turnaround activity. As we wrap up turnarounds, I think you'd get into warmer weather, which, again, it's hard to push refiner utilization due to some overhead temperature limits.

You know, 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 in net capacity additions. We're showing about 500,000 barrels a day of total light product demand growth. So things look tight, you know, 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, you know, 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 thus far this year mainly due to the weather. You know, I can tell you that first couple of weeks in January were fairly soft on domestic demand. That's typically the case. Things had started to recover nicely. Last week, we were back up to around the 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 to Europe is open. Diesel exports into Latin America are economic. Good gasoline demand into Latin America. And then, you know, we don't see an arb to really send winter grade gas to New York Harbor. So all of those things are constructive.

Theresa Chen: Super helpful. Thank you, Gary. Looking at the feedstock side of things with the Venezuelan 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 light heavy diffs as well as light heavy diffs in the Mid Con given the related impact to WCS?

Randy: Theresa, this is Randy. I'll kick that off. Obviously, having Venezuela supply kind of back in the fold for our system is great news. The exports that are coming out of Venezuela tend to be very heavy, high sulfur, high acid, and that fits our configuration pretty well. In fact, if you look over the last ten years, Valero has been the largest purchaser of Venezuelan heavy crude more than any other US refiner. You know, 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 expect our Venezuelan processing capability to be substantially north of that number now. Kinda looking at differentials, I mean, not only Venezuela, but we've had, you know, several beneficial factors that have occurred that kinda help move this market weaker. You know, after last year with discounts fairly tight, you know, most of these market moves tend to are making differentials increasingly favorable for refiners with the high complexity refineries such as ours. In OPEC increases of announced 2.9 million since April, seen growing sour crude production in the US Gulf. It's now over 2 million barrels a day. It's up about 200,000 barrels from a year ago.

We've seen a resumption of the Kirkuk exports that started in October. And we continue to see high production or growing production out of Canada. That's been helpful. One other factor that's been helping discounts is freight rates have been sharply higher. You know, if we 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, you know, wider discounts in order to allow those exports to happen. So, you know, right now, we're seeing, you know, heavy 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, Mars in the Gulf has been around $5 discount to Brent. That's about a dollar kinda cheaper than we were in the fourth quarter. So all looks pretty favorable, I think, for discounts kind of heading into 2026.

Theresa Chen: Thank you, Randy.

Randy: Sure.

Operator: Thank you. The next question is coming from Neil Mehta of Goldman Sachs. Please go ahead.

Neil Mehta: Yes. Good morning, team. The first question, I guess, would be for you, Homer, be around return of capital. Last year, you guys were pretty strong versus, I think, what Mark had 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.

Homer Bhullar: Hey, Neil, good morning. I'll start. Obviously, returning excess free cash flow to our shareholders through share repurchases has been a pretty core tenant of our capital allocation framework, right, for over a decade. We've reduced our share count by over 40% since 2014. 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 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 gonna mention sustaining CapEx and dividend, which we obviously considered 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, you know, we've we're going to be guided by our minimum return threshold. Right? We're gonna stay disciplined. On acquisitions, you know, same, we have to see good strategic value and a clear and quantifiable assessment of synergies. We're not gonna just do growth projects or acquisitions just because we have excess cash.

So absent those uses of cash, we're gonna continue to lean into share repurchases. And if you think about share repurchases, there's always 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 repurchase and that's really any given period where we see weakness, particularly our share price is weak on a relative basis to the broader sector. And, you know, to your point on stock trading near all-time highs, I mean, you go back ten 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 ten-year period with where the share price is today. And, frankly, I hope we keep getting the same question for the next ten years because that means the stock is doing well.

Neil Mehta: Yeah. That's a great answer, Homer. Thank you for that perspective. Follow-up is just, we are seeing heavy start to discount, particularly Western Canadian crude. And so as you just there was a story out there that some of the folks who are marketing the Venezuelan barrels were trying to bid them in pretty tight into 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.

So know, if you if you could expand a little bit more on that specifically as you are you 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 in order to compete with your alternatives.

Eddie: Hey, Neil. This is Eddie. 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 put it into the basket of alternatives, and will purchase Venezuelan grade if it beats our alternative. So, yeah, you've seen all the articles. I've read them as well. You know, looking forward, you know, 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.

Neil Mehta: Ready.

Operator: Thank you. The next question is coming from Manav Gupta of UBS. Please go ahead.

Manav Gupta: 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. Target achieved very quickly. Thanks. 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 the same refining margin.

Homer Bhullar: Yeah. Hey, Manav. So 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, you know, having discipline around capital and then a strong balance sheet, which ultimately all translate to, you know, higher cash flow and higher shareholder return. So, you know, starting with operations, we've obviously worked really hard to manage cost and our reliability over the years, and you can see that with the record throughput and mechanical availability this past year. And then, you know, we've also been very disciplined around growth investments.

You know our minimum return threshold, which effectively, you know, 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, you know, return on equity or return on invested capital over the last five or ten years, you know, that's in the mid-teens or higher number. And, again, keep that keep in mind, that denominator for that 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, you know, 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, a per share basis, share repurchases have helped a lot as well.

Manav Gupta: All very good points. My quick follow-up here is, very good improvement in renewable diesel. I know there were a few quarters where you know, the industry struggled. You did much better than the industry. But the industry was struggling. I we sign finally seeing, you know, at the light end of this tunnel where possible RVO, and then all those policies will become clear. 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.

Eric Fisher: 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 you contrast the 2025 being the transition to PTC and everyone trying to understand it, we were the first and perhaps one of the 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 you know, 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 offline.

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 fat prices to really level off and even drop throughout the fourth quarter and into this first quarter. So what I see in '26 is, you know, a policy should be a tailwind. The expectation is it should come out favorably for renewables. We do see that, there's a lot of talk of know, and tariffs continue to be a pretty strong headwind. But, you know, we'll see what the supreme court comes out with. And so I think, you know, you're gonna see 2026 starting off more like the '25.

And so that would indicate a stronger year in '26 versus '25.

Manav Gupta: Thank you so much.

Operator: Thank you. The next question is coming from Doug Leggate of Wolfe Research. Please go ahead.

Doug Leggate: 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. All across your system. Mexico looks like it's now running a little better so less imports or less exports rather from there. WCS has TMX. Of course, there's Venezuela. 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, ten years ago, fifteen 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 a million today. Where can that get to?

Lane Riggs: Doug, it's Lane. I'll 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. They ensure that our coker availability or coker sort of utilization was where we felt like it needed to be to meet FID. We're also purchasing outside resid. So we're doing all that. I think what you can expect is you get more available from Venezuela more avail 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 because we believe there'll be a driver to fill the coker with heavy.

Doug Leggate: Lane, is it possible to give a utilization rate on your coker so you your coker capacity today and where it could get to or is that too granular?

Lane Riggs: We 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 Yeah. But I know. We normally, from a just from a signaling perspective, most of the time, we optimize the crude diet into sort of, you know, the way you would do it, and then we purchase outside feed or internal resid feed to make sure that coker is full most of the time. Yeah.

Doug Leggate: Alright. That's that's helpful, guys. My follow-up is actually on one of Manav's questions about the RVO and RIN prices. They're 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, we're up around the one I think we're up one twenty or something today. Per gallon. What do you think the mid-cycle earnings capacity of DGD is or maybe free cash flow, whichever one you prefer to lean on? And I'll leave it there. Thanks.

Eric Fisher: Yeah. That's that's not really a question that can you can easily come up with an answer on about mid-cycle for RINs. What I would say is you've kind of been a new framework with the PTC. The previous ten years of DGD was on the blender's tax credit. So everyone gets a dollar cash from the government for every gallon that 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 in the as it is going forward. Think as we think about, you know, where this all goes, what the government has suggested as an RV as a obligation range of five two to five six billion gallons for 2627. 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 compliant you're you're essentially raising the obligation while also making it harder to generate.

That all points to a higher d four RIN price especially as you draw the bank down, which a five two to five six obligation number would certainly do, And so what I would say is, you know, it's not really you know, trying to think about what a mid-cycle it is. More just saying you know, there's a good chance d four 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 in this new framework of PTC. So all of that, you know, 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 markets into Canada, and Europe and The UK, those that operate just like refining the most efficient capacity in the Gulf Coast, and then those that can run waste oils over veg oils.

Doug Leggate: Great answer, Eric. Thanks so much.

Operator: Thank you. The next question is coming from Paul Cheng of Scotiabank. Please go ahead.

Paul Cheng: Hey guys, good morning.

Lane Riggs: Good morning.

Paul Cheng: I don't know whether you guys will be willing to share. That's a as usual, every several years that we have the labor contract being negotiate 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 if that's in case if there's any strike, I'm sure that you guys are well prepared. Management will be able to take care of it for a period of time. But which we find, you know, what percent of your capacity is actually will be impacted? Second question is that I think that has been asked previously.

If we look back in your utilization rate, historically, I think on a full-year basis that your Mac maximum may be doing somewhere in the 94, 95%. Do you believe, given you've been look like there had been done a phenomenal job in operating your facility better and better? Do you think that now on a maximum full cycle basis, that you would be able to do better than that? Or that I mean that the entire curve have been shipped up? What I mean, they're comparing to maybe ten years ago. What, one or 2%. Is there anything that you can help to quantify it?

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

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

Paul Cheng: Hey, Gary. Do you think that the whole industry is getting better?

Gary Simmons: 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'll 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.

Paul Cheng: 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.

Gary Simmons: Yeah. 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. You know, if you look at our guidance, I would tell you there was nothing material that related to the winter storm that's gonna impact the quarter.

Paul Cheng: Thank you.

Operator: Thank you. The next question is coming from Ryan Todd of Piper Sandler. Please go ahead.

Ryan Todd: Okay, thanks. Maybe one on the 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 some of the drivers were there? And then can you maybe walk us through the timeline of the coming shutdown of Venetia, and how you're thinking about West dynamics for 2026?

Gary Simmons: 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 pretty weak relative to diesel. 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 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.

Rich Walsh: And this is Rich Walsh, I'll try to answer on the timeline there. You know, in terms of the Venetia idling, we're executing our plan to safely idle it, the refinery operating units that is. And know, so well planned out and phased process. And in February, you know, you saw you saw our most recent announcement. You know, we will be idling the process units because they have some mandatory inspection requirements. That are that are kicking in then, and so we'll we'll be pulling those offline. And but, you know, we will be continuing to produce fuel as we work down the inventory through this process.

And, you know, as we've shared with the governor and CEC, we are gonna be importing some gasoline, and or gasoline blend components you know, over the over the nears near term. And, we remain committed to our, you know, contractual obligations, out there to meet to meet the supply obligations that we have. So we're working cooperatively with state officials, the CDC, and the governor on our plans, and we've kept them fully informed. And they're aware of our supplemental supply commitments to the 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 them California market out of Wilmington.

Ryan Todd: 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 kinda debated out there, whether it's you know, SREs or reallocations or penalties for foreign feeds or products, you know, directionally? What you're hearing on those things?

Eric Fisher: Yeah. That's really kind of a government question. I'm a let Rich answer that.

Rich Walsh: Great. Yeah. You know, I mean, look, UK has got a big challenge on dealing with the RVO right now. And, you know, the SREs. In this I think the administration is starting to recognize how now that know, all of this is getting caught up with these SREs. They've really gotten out of hand. You know, if you look at EPA, they sort of defaulted to this outdated DOE process that the government accounting office has already, you know, said was a flawed process in both EPA and DOE. Had acknowledged that previously. And, you know, this matrix is so out of date.

It doesn't even account for the Shell revolution in the domestic production, which is completely transformed with the US energy market. So it's a really flawed SRE basis. It's out there. And in terms of solutions, I mean, I think there is a legislative proposal out there that's a compromise that's supported by API, by ag interest, by retail trades and most refiners that you know, would allow a process to go forward that would kind of help correct all this and get us kind of realigned and supporting the RFS.

But, you know, there are a small number of conglomerate so called small refiners that are that are out there that are having windfall on these SREs, and they're they're kinda holding it up. So that's where we think this stuff is gonna have to be worked down. It's a it's a challenge for the agency that kinda gotten into a into a fix with the with over issuing these SREs.

Ryan Todd: Great. Thank you.

Operator: Thank you. The next question is coming from Paul Sankey of Sankey Research. Please go ahead.

Paul Sankey: Good morning, everyone. Glad to hear, Brian, that you got the job because you're close family relationship to Doug Leggett. That's But I joke. Hey, guys. We'll have to clarify that. Yeah. Just some demand and supply at the moment obviously we're seeing oil through 70. Is that would you say that's related to the sanctions and shadow fleet being shut down effectively or more shut down than it has been? I'm just wondering, it's a big surprise, I think, to all of us. There's obviously the demand side of the equation. And I was just wondering what your perspective is on U. S.

Oil demand right now in the storm because we're seeing some big numbers from some of the Northeastern generators, I mean 300,000 plus type daily use of oil to generate power. You didn't seem to really highlight that in your very complete comments so far. I just wondered if you're seeing a big 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.

Lane Riggs: Yes, Paul, I'll just touch on the flat price. I think what we're seeing right now, with the geopolitical wrangling going on in Iran, think has put quite a bit of geopolitical risk factor on top of flat price. Plus you've had, you know, the winter storm take off some oil production, the shale patch. In addition to the continued issues with the CPC and Tengiz over in Kazakhstan. Stan. Had quite a bit of oil offline. So I think all those are leading to some short-term tightness. Plus the geopolitical factor just kinda running up oil here in the short term.

Gary Simmons: Yeah. In terms of heating oil demand, I think, you know, a lot of that is just where we have a strong wholesale presence. We're not really strong in the heating oil markets. You know, 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 for us, you know, a strong incentive to ship to New York Harbor, which is again tied to heating oil. Demand.

Paul Sankey: 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 kind of effectively exit that market or if you have access to it through other means. Secondly, whether or not you would consider perhaps with more heavy oil coming back on the market with the decline of potential certainly decline of U. S. Light sweet production, whether there might be more CapEx to be undertaken?

Lane Riggs: 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 look how long we've 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, because we didn't see a that we were going to grow you know, grow the capacity to produce into it. So what you're actually going to see is when as we shut Venetia down, our sustaining CapEx should fall on a number somewhere around a 150,000,000 ish, our sustaining capital actually fall.

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

Paul Sankey: And anything on incremental spending on a heavier slate going forward potentially?

Lane Riggs: No, not on the West Coast. Mean, in the print? Yeah. We will definitely look at we'll definitely look at that, you know, in terms of our strategic are looking at that. We have, you know, 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, you know, we have a pretty good position as it is, so we wanna 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 probably still fit into the small we'll study, we'll we'll see what it would take to do, you know, those CapEx. We're not going to do a great coker expansion or anything like that. That's not the foreseeable future.

Paul Sankey: Great. Appreciate that. Thanks, Dan.

Operator: Thank you. The next question is coming from Sam Margolin of Wells Fargo. Please go ahead.

Sam Margolin: Hey, morning. Thanks for the question. Yes. On revisiting CapEx, know, growth CapEx is pretty moderated. I think you've you've explained why. Just drilling into it. How much is inflation a factor with the gated process and returns? And, you know, if it is a big factor, do you think that means for sort of buy versus build? Decision making? You know, to the extent that you're interested in growth.

Lane Riggs: Hey, Sam. So I will back up and explain the kind of our CapEx. If you really go back for a long time and we feel like we have the capacity to strategically develop about $1,000,000,000 of strategic CapEx. When we went into COVID, we sort of lowered that number to about 500,000,000.0 really emphasizing at a time renewable, the renewable side of the business. So if you kind of if you were to look at the trend of where we've been for, the past five years or six years or something like that. Our half of the joint venture we're spending about $250,000,000 ish of CapEx with respect to R and 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, you know, sort of three hundred ish to, you know, three hundred ish kind of number. And that is I'm not gonna with respect to inflation, what I will say about inflation and regated process is it does make these projects more difficult to do because the cost of building has gone up.

I mean, our as an example, our alkyd cost, I don't know, 4 or 3 or $300.400000000 and now they're up we costed one out not too long ago. It's more like 600,000,000. So when you it is, you have to have you have to think about you have to think about a forward price set and do you believe the Ford price set is going to accommodate the inflationary cost of standing up units. And obviously, we are always interested in assets. We look at them through a lens of are there, you know, are there arbitrages with our current system either through you know, sort of, I would call it processing arbitrage or trading arbitrage.

That's how we like to think of these and we're we're obviously we always look at those and through the and particularly through that lens.

Sam Margolin: Got it. Okay. And then just revisiting heavy crude, for a second. I know there's competitive reasons you might not want to give an exact number of what know, the headroom is, for incremental barrels. But maybe we could frame it this way. On crude valuation, just like, you know, 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 a refinery economics perspective and, you know, where it could normalize to whether that's freight costs or some other method that you use.

Randy: Hey, Sam. Just ready. Probably difficult to kinda give a value. I just will maybe harken back to 2025 when differentials on the sours were all pretty narrow and we got to a point where we were indifferent on running sweet crude versus sour for most of the year, especially in through Q2 and Q3. I think where we're at today, it's it's firmly planted. We're gonna buy as much on the heavy and medium size as we can to fill up the filters and downstream units.

Sam Margolin: Alright. Thank you so much.

Operator: Thank you. The next question is coming from Joe Lache of Morgan Stanley. Please go ahead.

Joe Lache: Great. Thanks. Good morning and thanks 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 standpoints. 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 Nationwide E15? Thank you.

Eric Fisher: Sure. Yes, ethanol has had another good year and continues to as Lane said, break throughput records as we've kind of grown capacity creep for the last couple of years. And have plans to continue to creep capacity. In the ethanol segment. The corn crop has been good the last two years. So we see, essentially cheap feedstock is one of the big drivers. And then I think overall, you know, 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 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 grow. So the ethanol segment continues to be very competitive and flow a lot of cash. I think know, in terms of e 15, all of our ethanol plants have are registered to sell e 15. That's a we still see very slow customer acceptance of that. But it is slowly growing. I think, that's one of those that know, if and when that happens, we're positioned to take advantage of that.

And, it's just a question of, you know, how RVO policy is gonna work out. You know, Rich alluded to, this is all wrapped up in the entire SRE conversation and this idea that you know, what part of renewables is gonna what part is renewables gonna play in the in the domestic slate is what we're waiting for clarification on. I don't know, Rich, if you had other comments about e 15.

Rich Walsh: No. I mean, I think I do think it's it you know, the national e 15 waivers caught up with this SRE. Issue and you can't have anything that's going to undermine the RFS. But like you said are doing. And so I think I think you're gonna see you see ag and most of refinery aligned on how to go forward with the team and a solution for SRE. Over the authorization. And so I those will have to be recognized.

Joe Lache: Great. That's helpful. And then shifting to the refining side, was hoping to get your perspective on the fuel oil market here. Cracks have 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.

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

All that's kind of pushing the you know, and freight costs are high, so the movement from the West to the East on fuel oil. So the higher freight goes, west just need to discount more.

Joe Lache: Great. Thank you.

Operator: The next question is coming from Philip Jungwirth of BMO Capital Markets. Please go ahead.

Philip Jungwirth: 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 U. S. Gulf Coast barrels? And question to answer, but it's it's been a quieter month as far as drone strikes on Russian refineries. Just how are you thinking about the fundamental versus geopolitical tightness in diesel cracks currently?

Gary Simmons: Yes. This is Gary. I think overall you are seeing EU shy away from Russian diesel barrels. Thus far, we've seen that being able to rebalance throughout other parts of the world. I think the big area we saw is 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.

Philip Jungwirth: Okay. Great. And then might be a short answer, but you've always said you'll stay out of the Cisco auction, but just given the regime changes in Venezuela, is there any reason you might revisit this stance depending on what happens with the process in here?

Lane Riggs: Yeah. This is Wayne. You know, it's still I mean, anything, it's added a degree of uncertainty to the process, think, again. So we're sort of we've we chose to stay out of it because of uncertainty of the process, the length of it all, just all the difficulty with respect to that would all work. And I don't know that it's 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 the or there gets to be more certainty around the process that might change the way we think of it.

Philip Jungwirth: That's helpful. Thanks, guys.

Operator: Thank you. The next question is coming from Jean Ann Salisbury of Bank of America. Please go ahead.

Jean Ann Salisbury: 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?

Gary Simmons: Yeah. I think a lot of it been. From our Pembroke refinery, 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.

Jean Ann Salisbury: Okay. And then as a follow-up, both refined products pipeline open seasons were extended, and I believe one now offers a path to multiple California markets now. Do you still prefer, as you kind of said on previous calls, to move product waterborne thinking that's a better solution. Here.

Gary Simmons: Yes. So, you know, 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 arms. 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, you know, 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.

Jean Ann Salisbury: That's helpful. Thank you.

Operator: Thank you. The next question is coming from Matthew Blair of Tudor, Pickering, Holt. Please go ahead.

Matthew Blair: Thank you and good morning. You touched on the 45Z for your renewable diesel segment. Are you going to be recording 45Z credits in your ethanol segment in 2026 due to the removal of the indirect land use change? And if so, do you have a approximate EBITDA benefit it might be? We're we're estimating somewhere between, like, 50,000,000 and 100,000,000.

Eric Fisher: Yeah. This is Eric. 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 know, you could what I will add is it works in 10¢ increments. So, you know, you'll if you qualify, you'll get 10 or 20¢ a gallon for whatever they ultimately define as qualified sales.

So you know, you can, you know, you can speculate on, you know, how that's all gonna work. But really, yes, we are poised to capture PTC in the ethanol segment. We're just waiting on finalization of guidance.

Matthew Blair: 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? Are you shifting to an overall heavier crude slate, so pushing out lights and mediums? Or are you pushing out other heavies?

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

Matthew Blair: Great. Thank you.

Operator: Thank you. The next question is coming from Jason Gabelman of TD Cowen. Please go ahead.

Jason Gabelman: Yes. Hey, thanks for taking my questions. I wanted to ask another one on the crude quality discs. Given they've widened out quite bit, and I know you kinda mentioned a bunch of reasons why that is. But if we kinda look back a few years prior to COVID, it seems like there was more kind of sour 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, 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.

Randy: Yeah. This is Randy again. I mean, I don't know that I have a firm answer on where 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 as we head through the year. Probably the one thing on the freight side that is kind of pressuring differentials down in the prompt is freight rates have went up significantly. That's kind of result is more enforcement on some of these shadow fleet vessels and that could be with us as we head through the rest of the year.

Jason Gabelman: Got it. Great. Thanks. And my quick follow-up is just on 2026 throughput, and it seems like sustaining CapEx is down a couple of $100,000,000 versus what you've you've done the past couple 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 Venetia to continue to improve?

Lane Riggs: This is Wayne. I would say, can attribute most of it There's timing, obviously, year over year differences. But a big part of it is we're, you know, is Venetia. We have one less refinery to do sustaining capital on.

Jason Gabelman: Alright. Thanks.

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

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

Operator: 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. Enjoy the rest of your day.