Valero Energy Corp (VLO) — Q3 2025 Earnings Call Transcript

Good morning, everyone, and welcome to Valero Energy Corporation's Third Quarter 2025 Earnings Conference Call. I'm joined today by Lane Riggs, Chairman, CEO and President; Jason Fraser, Executive Vice President and CFO; Gary Simmons, Executive Vice President and COO; Rich Walsh, Executive Vice President and General Counsel; as well as several other members of Valero's senior management team. If you have not received a copy of our earnings release, it's available on our website at investorvalero.com. Included with the release are supplemental tables providing detailed financial information for each of our business segments, along with reconciliations and disclosures for any adjusted financial metrics referenced during today's call. If you have any questions after reviewing these materials, please feel free to reach out to our Investor Relations team. Before we begin, I would like to draw your attention to the forward-looking statement disclaimer included in the press release. In summary, it says that statements made in the press release and during this conference call that express the company's or management's expectations or forecasts of future events are forward-looking statements and are intended to be covered by the safe harbor provisions under federal securities laws. Actual results may differ from those expressed or implied due to various factors, which are outlined in our earnings release and filings with the SEC. I'll now turn the call over to Lane for opening remarks.

Thank you, Homer, and good morning, everyone. We're pleased to report strong financial results for the third quarter, highlighting our long-standing track record of operational and commercial excellence. Our refinery throughput utilization was 97% with the Gulf Coast and North Atlantic region setting new all-time highs for throughput following last quarter's record performance in the Gulf Coast. Refining margins remained well supported by strong global demand and persistently low inventory levels despite high utilization rates. Supply constraints were driven by refinery rationalizations, delayed ramp-ups of new facilities, and ongoing geopolitical disruptions. These market dynamics contributed to the margin strength despite relatively narrow sour crude differentials. The Ethanol segment also delivered a strong quarter, achieving record production and solid earnings. Strategically, we continue to make progress on the FCC unit optimization project at our St. Charles refinery. This initiative will enhance our ability to produce high-value product yields, including high-octane alkylate. The $230 million project is expected to begin operations in the second half of 2026. Looking ahead, refining fundamentals should remain supported by low inventories and continued supply tightness with planned refinery closures and limited capacity additions beyond 2025. Sour crude differentials are also expected to widen with the increased OPEC+ and Canadian production. In closing, our strong financial results and record operating achievements this quarter are a testament to our commitment to commercial and operational excellence. This, coupled with the strength of our balance sheet should continue to support strong shareholder returns. So with that, Homer, I'll turn the call back over to you.

Thanks, Lane. For the third quarter of 2025, net income attributable to Valero stockholders was $1.1 billion or $3.53 per share, compared to $364 million or $1.14 per share for the third quarter of 2024. Excluding adjustments shown in the earnings release tables, adjusted net income attributable to Valero stockholders was $1.1 billion or $3.66 per share for the third quarter of 2025, compared to $371 million or $1.16 per share for the third quarter of 2024. The Refining segment reported $1.6 billion of operating income for the third quarter of 2025, compared to $565 million for the third quarter of 2024. Adjusted operating income was $1.7 billion for the third quarter of 2025, compared to $568 million for the third quarter of 2024. Refining throughput volumes in the third quarter of 2025 averaged 3.1 million barrels per day, or 97% throughput capacity utilization. Adjusted Refining cash operating expenses were $4.71 per barrel. The Renewable Diesel segment reported an operating loss of $28 million for the third quarter of 2025, compared to operating income of $35 million for the third quarter of 2024. Renewable Diesel segment sales volumes averaged 2.7 million gallons per day in the third quarter of 2025. The Ethanol segment reported $183 million of operating income for the third quarter of 2025, compared to $153 million for the third quarter of 2024. Ethanol production volumes averaged 4.6 million gallons per day in the third quarter of 2025, achieving record production. For the third quarter of 2025, G&A expenses were $246 million, net interest expense was $139 million, and income tax expense was $390 million. Depreciation and amortization expense was $836 million, which includes about $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia Refinery next year. Net cash provided by operating activities was $1.9 billion in the third quarter of 2025. This amount included a $325 million favorable impact from working capital and $86 million of adjusted net cash used in operating activities associated with the other joint venture member's share of DGD. Excluding these items, adjusted net cash provided by operating activities was $1.6 billion in the third quarter of 2025. Regarding investing activities, we made $409 million of capital investments in the third quarter of 2025, of which $364 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, with the balance for growing the business. Excluding capital investments attributable to the other joint venture member's share of DGD and other variable interest entities, capital investments attributable to Valero were $382 million in the third quarter of 2025. Moving to financing activities, we returned $1.3 billion to our stockholders in the third quarter of 2025, comprising $351 million in dividends and $931 million for the purchase of approximately 5.7 million shares of common stock, resulting in a payout ratio of 78% for the quarter. Year-to-date, we have returned over $2.6 billion through dividends and stock buybacks for a payout ratio of 68%. Concerning our balance sheet, we ended the quarter with $8.4 billion in total debt, $2.2 billion in total finance lease obligations, and $4.8 billion in cash and cash equivalents. The debt-to-capitalization ratio, net of cash and cash equivalents, was 18% as of September 30, 2025. We ended the quarter well capitalized with $5.3 billion in available liquidity, excluding cash. Turning to guidance, we expect capital investments attributable to Valero for 2025 to be around $1.9 billion, which includes expenditures for turnarounds, catalyst, regulatory compliance, and joint venture investments. Approximately $1.6 billion of that is allocated to sustaining the business, while the rest is for growth. For modeling our fourth quarter operations, we expect Refining throughput volumes to range: Gulf Coast at 1.78 million to 1.83 million barrels per day; Mid-Continent at 420,000 to 440,000 barrels per day; West Coast at 240,000 to 260,000 barrels per day; and North Atlantic at 485,000 to 505,000 barrels per day. We anticipate refining cash operating expenses in the fourth quarter to be about $4.80 per barrel. For the Renewable Diesel segment, we expect sales volumes of about 258 million gallons in the fourth quarter, reflecting lower production due to economics. Operating expenses should be $0.52 per gallon, including $0.24 per gallon for noncash costs such as depreciation and amortization. Our Ethanol segment is anticipated to produce 4.6 million gallons per day in the fourth quarter, with operating expenses averaging $0.40 per gallon, which includes $0.05 per gallon for noncash costs such as depreciation and amortization. For the fourth quarter, net interest expense is expected to be about $135 million. Total depreciation and amortization expense for the fourth quarter should be approximately $815 million, which includes roughly $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia Refinery next year. We expect this incremental depreciation related to the Benicia Refinery to be reflected in D&A for the next two quarters, resulting in a quarterly earnings impact of about $0.25 per share based on current shares outstanding. For 2025, we still expect G&A expenses to be around $985 million. That concludes our opening remarks.

This is a comment from your opening remarks. As you mentioned, not much of a contribution from heavy crude this quarter regarding differentials. I guess we're about a year into TMX barrels fully flowing. I wonder if you could share any insights on the differential side, being 12 months into TMX, and also on the overall availability picture that's emerging into 2026.

Yes. I would say that we have been somewhat disappointed that TMX hasn't had as much of an impact on West Coast crude values and ANS didn't decline as we expected. Most of those barrels are flowing to the Far East. Overall, we have seen quality differentials change quite a bit. WCS is currently trading at a 12% discount to Brent, while Maya is at a 14% discount to Brent, which had been as narrow as 7% earlier this year. Medium sours had seen discounts as narrow as 2.5%, but that has widened to nearly 8%. These discounts have moved to a point where we are seeing economic benefits in our system from processing medium and heavy sour crudes. We expect these differentials to continue widening. Although OPEC started to unwind their production cuts in April, much of that volume was balanced by an increase in summer power burn, so we didn't see any significant increase in OPEC export volumes until September. The current pricing signals indicate that most of that additional OPEC volume will be directed toward Asia, but we have been receiving more offers in the U.S. market, particularly for Rocky crude. We will process both Basra and Kirkuk in our system during the fourth quarter. The arbitrage for moving Mars into Asia has closed, and we are beginning to see Asia push back on some Latin American grades, which is starting to pressure medium sours in the Gulf Coast. All these factors are emerging in October. As medium sour discounts widen, heavy sours will respond to remain competitive. We expect this trend to continue throughout the fourth quarter. In addition to OPEC, heavy Canadian production has been increasing, along with some deepwater medium sour production in the Gulf. Chinese demand for medium and heavy sour barrels has also been very strong as they fill their strategic petroleum reserve. At some point, we expect that to be full, and their demand might decrease. The real wildcard is the recent announcements regarding an increase in Russian sanctions. Historically, sanctions have had limited effectiveness, mainly altering trade flows. However, today's market reaction suggests that this round of sanctions may effectively reduce some Russian oil from the market. On paper, OPEC could potentially offset that lost supply, but it might pose a challenge to quality differentials. Conversely, this situation could be very positive for product cracks.

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

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

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

Manav, this is Gary. I think we've seen good export demand all year. The fact that we've been unable to restock inventories in the United States is keeping somewhat of a pull into the domestic market, but the export markets are very good, continue to see really good export demand for gasoline into Latin America and South America. On the diesel side, a bigger pull into South America than what we've been seeing. Freight has really been volatile. And so on the export arbs going to Europe, it's kind of been up and down, and it's really just freight that's kind of been what opens and closes that arb. If you look today, that arb is marginally open. And I think you'll start to see a heavier flow going to Europe from the U.S. Gulf Coast on diesel.

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

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

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

Yes, Lane, there has been extensive discussion about crude oil that is currently on the water and in transit, with some estimates exceeding 3 million barrels per day based on shipping tracking data. You have valuable insight into whether that crude is indeed on the water. I would be interested in how your commercial team is perceiving this situation. Do you think that this oil will ultimately arrive in OECD countries, or will it be directed towards China specifically? I mention this considering the possibility of crude differentials starting to widen; do you view this as a potential catalyst? Additionally, could you elaborate on Iraq in particular, as it may serve as a leading indicator?

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

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

We'll continue monitoring the situation. Regarding the non-refining businesses, they performed better than we anticipated this quarter. Ethanol is still doing well, and it seems DGD is nearing profitability. Could you discuss both of these businesses and whether the ethanol margins are sustainable? Additionally, are we on track to return to profitability in DGD post the RVO?

Neil, this is Eric. Ethanol continues to look positive. I think a lot of that is we've had a record corn crop. Ethanol demand has been strong, both domestically and in the export markets. We're seeing the continued interest in countries going from E0 to E10. Canada has gone to E15 in some of the provinces. And you see Brazil and India looking at moving from the E20s to the E30s. And so all of this is creating more ethanol demand in the world. And being the largest exporter of ethanol, that favors our segment pretty well. So cheap feedstock and lots of demand. So ethanol, I think outlook is good and continues to look good in the future. On DGD, you're exactly right. We've seen throughout the year, there's just been a lot of impact from tariffs and policy downturns in the U.S. We've seen fat prices rising for the better part of the year. And I think just most recently, we are seeing enough rationalization in both biodiesel and renewable diesel where fat prices are finally starting to soften. And with that lower fat price, we've seen DGD margins return back to positive EBITDA. So that's a good sign for the fourth quarter. Obviously, with the PTC changing Jan 1 on all foreign feedstocks as well as SAF, that will be a challenge as we start 2026. But I think everyone seems to expect that the RVO will be net positive for renewables. That's a lot of speculation because there is a lot of back and forth on these policies right now. But I think the general view is the number is probably going up and will probably be supportive of renewable diesel.

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

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

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

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

Sure. If you look at our gasoline demand, I think in our system, we would say year-over-year gasoline demand is flat to slightly down, pretty similar to what's in the DOEs. Third quarter, our volumes were flat year-over-year. It looks to us like vehicle miles traveled are up year-over-year, but probably not enough to offset the more efficient automobile fleet. So again, probably flat to slightly down gasoline demand. As I mentioned, export demand looks good. When you look at gasoline fundamentals in addition to good export demand, the transatlantic arb to ship from Europe into New York Harbor is closed, and it's actually closed on paper all the way through the first quarter. So really for this time of year, gasoline fundamentals look about as constructive as you could hope for. Obviously, we've transitioned out of driving season, producing high RVP winter-grade gasoline, so you wouldn't expect a lot of strength in gasoline cracks in the fourth quarter. Jet demand, we're continuing to see good nominations from the airline. So again, comparing to the DOEs which show about a 4% bump in jet demand. That looks consistent with what we're seeing in the market. And then finally, on diesel. In our system, in the third quarter, year-over-year sales were up 8%. I don't think that's representative of the broader market. DOE data showing about a 2% year-over-year increase in diesel demand is probably close. We've seen good agricultural demand in our system. That continues. Harvest season starting to wind down, but then you'll start heating oil season, which again will be a good pop in demand. And as I mentioned, good export demand as well. Freight volatility is hindering that, but the demand is there.

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

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

Doug, the approach we're taking towards turnarounds has been something we've focused on for about a decade now. There isn't a significant shift in our strategy, but we have seen positive results from our current approach. Regarding AI, we are cautiously optimistic about its potential to enhance our availability. We are exploring various applications where we can leverage this technology, particularly in areas that can create real value. Through our experiences with AI and machine learning, we've learned that having reliable operational data is crucial for successful implementation. Fortunately, we have been working for many years to improve and standardize the collection of our data, which positions us well to utilize AI for further enhancements. We start from a solid foundation with the quality of our operations, and we believe AI techniques can help us achieve additional improvements.

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

Doug, it's Homer. You'll notice this in the Q filing, but part of it relates to items like PTC, where you record it within earnings, and the payment arrives later. Therefore, this will appear as a deduction from net cash flow from operations, contributing to one of the significant variances. Again, you’ll see that when you review the statement of cash flows in the Q.

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

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

U.S. refining utilization has been notably strong compared to historical averages over the past six months. What are your thoughts on the factors contributing to this? Do you think it is related to moving past a period of significant maintenance in recent years? Are there concerns that might hinder this trend from normalizing as we approach next year, or do you believe the U.S. refining system can maintain this level of operation?

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

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

I’ll begin and let Gary or Greg join in later. We embarked on a journey about 15 years ago to enhance our reliability, and we have demonstrated that it can be achieved. Many others in the industry are focused on similar objectives and are improving their execution. The systems are becoming more effective, whether related to AI or not. There are tools available to help manage turnarounds, enhance maintenance, and provide predictive insights on failure mechanisms, all of which contribute to what we define as availability, including better scheduling. Overall, the industry has been improving in this area, and that’s how I would respond.

The only thing I might add is that when I reflect on this past summer compared to previous periods, there wasn't a lot of extreme weather during the summer, and refineries tend to operate better under favorable ambient conditions. We have all been motivated to push production during these times. This could be related to maintenance, but also when you're not facing extreme heat, it allows for optimization of operations to maximize output. While I don't have concrete evidence, I believe this positive impact on our operations was evident this past summer.

Well, that's a great point. Hurricane, we have not had any hurricane activities to speak of in the Gulf.

Right. As we consider the fourth quarter, I want to point out that while the third quarter was great, there were several factors that acted as modest headwinds on margin capturing, including narrow crude differentials, crude backwardation, some West Coast jet fuel dynamics, and secondary products. Many of these issues seem to have reversed or improved early in the fourth quarter. Do you have any insights on the trends that might influence our profitability capture in the fourth quarter, which appears to be a strong environment?

Yes, Ryan, it's Greg. It's early for the fourth quarter, and you mentioned some favorable developments we've seen as October begins. As we approach winter, we will blend more butane into gasoline to meet winter specifications, which typically helps improve margin capture. However, it's important to highlight that despite several positive changes, some secondary products remain quite weak. Naphtha has weakened a bit, and propylene continues to show weakness. So, there are still a few factors that have not yet improved as we enter the quarter.

Just before my question, just curious that and have a comment. I was surprised that you guys didn't increase your G&A full year. I thought with the strong earnings that you guys are going to increase your bonus accrual. So I was surprised, maybe that is a part of the cost savings from Lane.

Yes, that's not one we'd eagerly jump on.

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

We will count that as a good comment, Paul.

Okay. My question is regarding the third quarter, where I believe part of the issue related to margin capture involves the octane. The octane value has decreased compared to the second quarter. Can you provide some insights on what occurred and whether this trend is expected to continue? Additionally, I'd like to discuss not just AI but also robotic technology. Lane and the team, do you think the new technology now available to you represents an evolution, or will it transform how you conduct business, not only in refining but also in your back office and trading? We've seen some of your upstream counterparts announce significant cost reduction efforts due to new technology, and I'm interested in understanding your position and that of the industry.

I'll address the naphtha question first and then let Greg handle the octane question. In terms of octane, we generally observe that it moves inversely to naphtha. In the last quarter, naphtha strengthened for a few reasons. There was a reduction in naphtha supply from Russia, some naphtha from the U.S. Gulf Coast was sent back to Venezuela as diluent, and more naphtha was directed to Asia for the petrochemical market. When naphtha prices are low, there’s a strong motivation to blend it with gasoline, which requires octane. However, as naphtha strengthens, that motivation diminishes. Although the octane regrade was slightly weaker, it likely set the stage for stronger fundamentals in gasoline.

All right, Paul. This is Greg. Regarding the question about robotic automation and AI, we may not discuss it often, but we've been utilizing and expanding these techniques over time as they help improve efficiency. They enhance our ability to inspect equipment and perform some of our tasks. I expect this trend to continue, and new techniques will provide more opportunities to use these tools in the future. While starting from a strong position makes it harder to identify significant opportunities, we are focused on finding those that offer good value.

And Paul, I'll add to it. Some examples of those things are that we, like many others in the industry, have been using robotics for tank cleaning. I can see how that would really help the upstream guys. Additionally, we have utilized drones for inspection. Instead of having to set up scaffolding to reach a difficult location on an FCC, we can deploy a drone to analyze the area, allowing us to understand the situation without immediate scaffolding. While we may still need to set up scaffolding later, we gain clarity on the scope of work beforehand. We are continually looking for ways to consolidate our control rooms and improve efficiency with our operators, which often involves technological advancements.

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

I'll begin with the second part of your question. We've experienced strong diesel yield, and the 38% to 39% range is consistent with our historical performance. This reflects our current operational approach, which focuses on maximizing diesel and distillate production over gasoline. During the last quarter, we operated very efficiently and reached higher production levels than we typically achieve with our existing equipment. We believe we can maintain this level with continued strong operations. What was the second part of your question, Joe?

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

Yes, we did experience a slight reduction, but in areas where we lightened up, the growth was primarily on the jet fuel side rather than diesel. We managed to redirect that back into naphtha and jet fuel while still producing a distillate product, which we had good motivation to do. I'm not entirely sure about the overall distillate yield calculation, but I don't believe the changes in the areas we lightened had a significant impact on our distillate yield.

Yes, I think there are more variables than fixed factors in this situation. There are various combinations of the number, an SRE reallocation, and a final figure. Currently, that figure stands at 3.3 billion D4s. Reflecting on the original goal of keeping the BD producer breakeven with a $1 BTC, significant progress has been made this year by removing ILUC from the soybean oil model. They provided a small benefit to producers, affecting nearly all BD producers, and now they seem to be around $0.70 to $0.80 compared to last year's $1. The additional $0.20 would likely require RIN prices to increase by about $0.25 to $0.30 to bring BD back to breakeven. Any mathematical combination leading to that figure essentially meets the initial objective of maintaining BD operations. The corresponding RIN figure would be higher than it is today. However, a challenge lies in the fact that the production of '25 D4 RINs is lower than last year. We currently aim for a target of 3.3. If we fall short, we will deplete the bank by early next year. Setting that target too high complicates determining how to fulfill the BD requirement without overshooting and negatively impacting diesel prices. This is a critical question that needs resolution. Awareness of how these adjustments will influence the overall market is growing, but these two factors will ultimately dictate whether improved profitability in the fourth quarter can be sustained into 2026.

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

Yes. So overall, yes, we do see declining production from Mexico. Our volumes from Mexico aren't really down much yet, but they continue to forecast that we'll see declining production from Mexico. A lot of that is being made up with additional volumes from Canada as they continue to ramp up production and fill the pipeline capacity coming to the Gulf. So I would say those somewhat offset each other. We do have Venezuelan barrels back in the mix, which is helping. And then the additional OPEC production, as I alluded to, getting the Basra barrels and Kirkuk barrels, all that really, I think you'll see in the fourth quarter a heavier crude diet than what we had in the third quarter, filling out a lot of our conversion capacity. On the high sulfur fuel oil question, actually, high sulfur fuel oil has been pretty strong. And we haven't seen a real strong incentive to buy high sulfur fuel oil to put into coker. So there's been some opportunistic purchases, but for the most part, on paper, those economics haven't been strong.

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

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

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

Most of the improvement is linked to lower feedstock prices, which are beginning to decrease. This trend is enhancing the profitability of DGD. We continue to benefit from strong SAF advantages in both the U.S. and European markets, giving DGD an edge over many other renewable diesel producers, as SAF commands a premium. The fourth quarter looks promising in terms of overall production rates and PTC capture, aided by lower fat prices. However, as we approach 2026, the key question will be whether sufficient premiums on SAF will compensate for the loss of PTC benefits. Additionally, we need to consider the RVO impact, which will be crucial in bridging any profitability gaps for biodiesel and renewable diesel, dependent on how the RVO is established. Current policies seem to conflict with an increase in RVO while decreasing generation due to foreign feedstocks, complicating the situation. Navigating these issues may lead to higher RIN prices. Ultimately, these factors will influence whether the improved profitability seen in the fourth quarter can be sustained into 2026.

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

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

Hopefully, 2 quick ones. First, just on the Russian refining disruptions. There's a lot of headlines on the Ukraine drone strikes, but it does seem like in many cases, the refineries come back online quickly. So I was wondering if you could provide some numbers around the amount of disruption that you're seeing on Russian product exports and kind of before today, trying to parse out how much of the product strength was driven by actual disruptions versus geopolitical risk premium in the prices? And then my second one is on the Benicia shutdown. Can you talk about your plans to resupply the market? Or are you going to have to kind of import products from Asia in order to meet your contractual obligations? Or do you not have really many outstanding in that market once the plant shuts down?

I will address the first part of your question. We believe the drone strikes have been quite effective. It appears that much of what's occurring in Russia involves attacks on their more complex refining capabilities. Consequently, as this unfolds, Russia is likely to increase its lower complexity refining capacity. This is evident in the changes we're observing in fuel exports and other related aspects. Regarding your second question, the spike we are witnessing today is not primarily attributed to any disruptions from Russia at this point. Instead, it reflects market speculation about potential future developments. However, we are indeed seeing a decline in product exports from Russia.

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

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

It could be from anywhere in the world. This is kind of what Gary mentioned earlier; having waterborne options allows you to work on arbitrage opportunities instead of making a large commitment to pipeline capacity. That's our intent. We won't be procuring barrels from any specific market; we'll find a way to supply it.

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

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

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

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