Greetings, and welcome to Valero Energy Corp third quarter 2026 earnings conference call. At this time, all participants are on a listen-only mode. A question-and-answer session will follow the formal presentation. If anyone requires operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Brian Donovan, VP of Investor Relations. Please go ahead.
Good morning, everyone, and welcome to Valero Energy Corporation's third quarter 2026 earnings conference call. Today, I'm joined by Lane Riggs, Chairman, CEO, and President, Gary Simmons, Executive Vice President and COO, Rich Walsh, Executive Vice President and General Counsel, Homer Bhullar, Senior Vice President and CFO, and several other members of Valero's senior management team. If you have not yet received a copy of our earnings release, it can be found on our website at investorvalero.com. Included with the release are supplemental tables providing detailed financial information for each of our business segments, along with reconciliations and disclosures for any adjusted financial metrics referenced during today's call. If you have any questions after reviewing these materials, please feel free to reach out to our investor relations team.
Before we begin, I would like to draw your attention to the forward-looking statement disclaimer included in the press release. In summary, it says that statements made in the press release and during this conference call that express the company's or management's expectations or forecasts of future events are forward-looking statements and are intended to be covered by the safe harbor provisions under federal securities laws. Actual results may differ from those expressed or implied due to various factors, which are outlined in our earnings release and filings with the SEC. I'll now turn the call over to Lane for opening remarks.
Thank you, Brian, and good morning, everyone. During the third quarter, our business teams executed well in all reporting segments. The market volatility and tight product inventories we saw in the prior quarter continued through the third quarter. Our teams remained focused on execution, running our refineries at near record levels of utilization and helping keep the market supplied with critical transportation fuels. Our ethanol segment also achieved a quarterly record for production during the third quarter, supplying fuel and contributing to our overall performance.
Financially, we remain in a strong position. During the quarter, we continued to honor our longstanding shareholder commitments while also strengthening our cash position. As we look ahead, we remain constructive on the long-term outlook for our business. Refining fundamentals remain favorable, supported by low product inventories, limited excess refining capacity, and continued demand for transportation fuels.
Compared to other regions around the world, the U.S. is well-positioned in the current market environment, and the U.S. Gulf Coast continues to be one of the most advantaged regions globally, supported by abundant domestic crude production and access to cost-competitive feedstocks. Combined with our strategically located refining system and the flexibility of our commercial team, these advantages support our ability to respond to changing market conditions and resilient customer demand. Turning to strategic capital projects, we completed the FCC unit optimization project at St. Charles Refinery during the third quarter on schedule and within budget. This $230 million investment has already increased production of higher-valued products, including alkylate and gasoline. We continue to evaluate additional strategic opportunities to further strengthen the competitiveness and long-term value of our refining system.
However, as we assess these opportunities, we remain committed to our disciplined investment process that has served us well for more than a decade. In closing, our third quarter performance underscores the quality of our assets and our consistent operational, commercial, and financial performance. This is a result of a long-term strategy that we've been committed to for well over a decade. With that, I'll turn the call over to Homer.
Thank you, Lane. For the third quarter of 2026, net income attributable to Valero stockholders was $6.8 billion or $23.89 per share, compared to $1.1 billion or $3.53 per share for the third quarter of 2025. Excluding the adjustments shown in the earnings release tables, adjusted net income attributable to Valero stockholders for the third quarter of 2026 was $6.8 billion or $23.90 per share, compared to $1.1 billion or $3.66 per share for the third quarter of 2025. The refining segment reported operating income of $8.8 billion for the third quarter of 2026, compared to $1.6 billion for the third quarter of 2025. Refining throughput volumes in the third quarter of 2026 averaged 3 MMbpd . Refining cash operating expenses were $5.03 /bbl in the third quarter of 2026.
The renewable diesel segment reported operating income of $353 million for the third quarter of 2026, compared to an operating loss of $28 million for the third quarter of 2025. Renewable diesel segment sales volumes averaged 3.4 million gallons per day in the third quarter of 2026. The ethanol segment reported operating income of $272 million for the third quarter of 2026, compared to $183 million for the third quarter of 2025. Ethanol production volumes averaged 4.8 million gallons per day in the third quarter of 2026. G&A expenses were $308 million for the third quarter of 2026. Depreciation and amortization expense was $684 million for the third quarter of 2026. Net interest expense was $144 million, and income tax expense was $2.1 billion for the third quarter of 2026. The effective tax rate was 23%.
Net cash provided by operating activities was $6.9 billion for the third quarter of 2026. Included in this amount was a $526 million unfavorable impact from working capital and $205 million of adjusted net cash provided by operating activities associated with the other joint venture member share of DGD. Excluding these items, adjusted net cash provided by operating activities was $7.3 billion in the third quarter of 2026.
Regarding investing activities, we made $432 million of capital investments in the third quarter of 2026, of which $371 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, and the balance was for growing the business. Excluding capital investments attributable to the other joint venture member share of DGD and other variable interest entities, capital investments attributable to Valero were $429 million in the third quarter of 2026.
Moving to financing activities, we remain committed to our disciplined capital allocation framework. Shareholder cash returns resulted in a payout ratio of 52% for the quarter. Also in the third quarter, we repaid the outstanding principal balances of our $100 million note that matured in July and our $426 million note that matured in September. An additional $146 million of debt maturing later this year will be repaid using proceeds from the debt we proactively issued in the first quarter during a lower rate environment. Turning to the balance sheet, we ended the quarter with $8.6 billion of total debt, $2.4 billion of total finance lease obligations, and $9.8 billion of cash and cash equivalents. The debt-to-capitalization ratio net of cash and cash equivalents was 4% as of September 30th, 2026, reflecting the cash build this year.
While our long-term $4 billion- $5 billion cash target remains unchanged, we continue to maintain cash above the high end of that range to preserve optionality in a volatile market environment, consistent with our messaging throughout this year, while also honoring our payout commitment. Overall, we ended the quarter well-capitalized with $5.3 billion of additional liquidity excluding cash. Turning to guidance, we still expect capital investments attributable to Valero for 2026 to be approximately $2 billion.
This includes expenditures for turnarounds, catalysts, regulatory compliance, joint venture investments, and the estimated cost to repair the DHT unit at our Port Arthur refinery. Approximately $1.7 billion is allocated to sustaining the business, with the remainder directed toward growth projects. Repairs to the Port Arthur DHT unit remain on track for completion by year-end. Total repair costs are still estimated to be approximately $250 million, which are included in our sustaining capital guidance.
As previously guided, we expect a substantial portion of the cost to be covered by insurance. In the meantime, the refinery continues to operate at normal throughput rates. Our growth projects continue to be focused on shorter cycle opportunities that improve crude and product flexibility, optimize the value of our product mix, and maximize utilization of existing conversion capacity across our refining operations. We've also been pursuing efficiency and capacity expansion projects at our ethanol plants. These investments should enhance the earnings power of our assets. For modeling our fourth quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.855 - 1.905 MMbpd , Mid Continent at 440,000 - 460,000 bbl/ day, West Coast at 100,000 - 110,000 bbl/ day, and North Atlantic at 480,000 - 500,000 bbl/ day.
We expect refining cash operating expenses in the fourth quarter to be approximately $4.85/bbl . For the renewable diesel segment, we expect sales volumes of approximately 325 million gallons in the fourth quarter. Operating expenses should be $0.53 / gal, including $0.23/gal for non-cash costs such as depreciation and amortization. Our ethanol segment is expected to produce 4.9 million gallons per day in the fourth quarter. Operating expenses should average $0.38 /gal , which includes $0.04 /gal for non-cash costs such as depreciation and amortization. For the fourth quarter, net interest expense should be about $135 million, and total depreciation and amortization expense should be approximately $700 million. Lastly, G&A expenses for 2026 are expected to be approximately $1.1 billion.
Thanks, Homer. That concludes our opening remarks. Before we open the call to questions, I would ask that you limit each turn in the Q&A to two questions. If you have more than two questions, please rejoin the queue as time permits to ensure other callers have time to ask their questions.
Thank you. Ladies and gentlemen, the floor is now open for questions. If you would like to register a question, please press star one on your telephone keypad at this time. A confirmation tone will indicate that your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up the handset before pressing the star keys. Again, that's star one to register a question at this time. Our first question is coming from Sam Margolin of Wells Fargo. Please go ahead.
Hi. Thanks for taking the question. It's a question on industry fundamentals, if we could start out, and on crude differentials, which have been pretty topical and also outsized recently. I think some of the crude differential move has been attributed to freight. If you could just talk about it for a minute and give your views on whether it is structural, what's happening with crude differentials, because there's more heavy supply coming, or if you think this is more of a cyclical condition related to some constraints and external factors.
All right, Sam. Good morning. This is Randy. Obviously, the market remains extremely volatile. We get headlines every day, every night, around events in the Middle East, and we're obviously keeping a close eye on that on global trade flows. Over the last several weeks, it does look like we are seeing sustained higher flows moving through the straits. We've seen media sources over the last couple of days indicating that the volume over the last week has been actually higher than pre-war levels. In addition to that, we've had some recent SPR releases. Overall, our indications from what we see in the market, both on spreads and trades flow, it looks like the market is pretty well supplied with oil. As you mentioned, the main story right now in the market is freight rates.
As the flow through the straits increase, the inefficient process of the ship-to-ship transferring that they're doing of crude oil in the Gulf of Oman is really tying up global shipping and to require more tankers to move the same amount of oil. This is in addition to insurance risk premiums, transshipment delays, higher bunker costs. They're all just kind of driving the freight higher. As an example of this extreme run-up in freight, the cost to move a VLCC from the Gulf Coast to Asia is now averaging around $30 - $35 /bbl . That compared with a 2025 average of around $5 /bbl . We're seeing this freight increase kind of play out in all markets around the globe and across all shipping classes, mainly on the dirty freight side.
This is causing severe dislocations in our global crude pricing as refiners seek to find barrels that are closer to home, and sellers are forced to discount barrels to account for the freight cost. Fortunately for us, the bulk of our systems in the Gulf Coast, which has access to a wide range of crude and crude qualities, is now a large exporter of crude.
Since this crude must price to export, the sharp run-up in freight costs have forced the discounts to widen in all grades. Given the U.S. Gulf Coast, some of the cheapest crude costs in the world, especially on the heavy sour. The Gulf Coast is also a freight advantage for heavy barrels out of Latin America compared with the Asian alternative, and discounts for these foreign barrels are also having to compensate for the large freight increase.
As Lane mentioned before, the Gulf Coast remains one of the most advantaged crude markets globally, and this freight run-up only further supports that. Looking ahead, our long-term outlook on crude differentials remains very constructive as incremental supply looks to be dominated by heavier and more sour barrels, especially out of Canada, Venezuela, and the Middle East, which further supports the value of our complex Gulf Coast system.
Okay, thanks. I was going to ask a follow-up on freight, but it sounds like you characterized your position fairly completely there. This follow-up is just for Homer. On the cash balance, you are carrying a lot of cash. It is an interesting position because you have a lot of optionality. Even if you are just earning a treasury rate on the cash, it is a massive number at this point. Just your thoughts on how the balance sheet is structured today, whether it is a point in time that is not necessarily meaningful over the long term or if you kind of like having this optionality with an outsized cash position structurally. Thanks.
Hey, Sam. Let me just start by reiterating what we have said throughout this year, that our initial decision to start building cash earlier this year was really around prudently managing volatility in commodity prices. The risk that we have talked about is when you have a rapid pullback in commodity prices, it is generally accompanied by a draw on working capital and a draw on cash.
In that event, we wanted to make sure that we are not constrained on our ability to return cash to shareholders, even if there is a significant draw on cash. In fact, I would say we want to make sure we are in a great position to lean into shareholder returns in that event. I n an environment that remains pretty constructive, we are comfortable where we are with respect to a payout.
We continue to pay out above 50% and continue to build cash. You touched on it, but we don't have a lot of other kind of commitments to cash. We don't have a lot of maturities over the next year plus. We have a little under $150 million that matures later this year, and a little over $500 million next year. We have plenty of flexibility, as you highlighted. Obviously, we've talked about this before, but we're not going to change our approach to capital investments just because we have a lot of cash. In short, we don't have a lot of other uses of cash.
While the volatility is probably not behind us at this point, we're in a good position to be even more aggressive with shareholder returns, especially if volatility returns, and as we ultimately move back towards our long-term cash target balance of $4 billion - $5 billion. In any event, I think whether margins and cash flow profile of our business remain strong or not, our long-term targets on cash have really not changed. Over time, all the excess cash we're accumulating will ultimately be directed towards our owners.
Thank you.
Thank you. Our next question is coming from Manav Gupta of UBS. Please go ahead.
Good morning. I actually just wanted to follow up a little. U.S. margins look very good, but what we are hearing is when you take into account some of your freight cost backwardation, some of your Asian or European peers, they are not doing as well. You are also the low-cost refiner in the world. I am just trying to understand, are we seeing a bifurcated scenario where one region of the world is at a good margin and can run much harder versus other parts of the world which are struggling to source crude, and even when it gets there, it is very expensive. Can you talk a little about those dynamics, please?
Yeah, Manav, this is Gary. I think we see the exact same thing you are staring at, which gives us high confidence that this current crack spread environment is very sustainable. When you look at some of the low complexity refining capacity in the Far East, freight costs to get crude to that refiner, and freight costs to get back into the export markets, it looks like their margins are in the $2-$3 /bbl range. In addition to the margin squeeze they are currently facing, we are also seeing natural gas prices begin to take off in those regions, which puts even a higher floor on where crack spreads need to go in order to force those refineries to continue to run at high utilization rates. I think the world needs that capacity to be running today.
Thank you. My quick follow-up here is, have you seen any signs of any kind of demand destruction, or can you generally talk about what you are seeing in both U.S. demand as well as export demand as Valero sees out there? Thank you.
Yeah, Manav, I will go through some of what we are seeing on the wholesale side. For the most part, I would say we are not seeing any signs of demand destruction at all. On the gasoline side, our U.S. wholesale network seven-day average sales are actually up 4% year-over-year. In Canada, they are flat year-over-year. In the U.K., flat year-over-year. Second quarter call, I mentioned that we were seeing some demand destruction in the U.K., but actually in the third quarter, demand recovered nicely there. G asoline demand has been very resilient to the higher prices. The export demand also very strong. You could see in all of our export markets, we are seeing a good pull from the U.S. Gulf Coast. Certainly, we have seen gasoline cracks come off a little bit.
Some of that is just seasonal as you've transitioned out of driving season, also get the swell from higher butane blending with the winter-grade gasoline specs. The underlying gasoline fundamental look very strong. We don't have a transatlantic arb to ship gasoline from Northwest Europe into PADD 1. We really don't have storage economics to begin to make summer-grade gasoline and store it, which is very constructive to the spring. I think the biggest thing when I look at the gasoline market, here we are in October out of driving season into high RVP gasoline season, and you still have backwardation in the gasoline market, which is really telling you that the prompt market is very tight gasoline supply. I think all of that's very constructive to gasoline longer term. On the distillate side, similar trends.
Our wholesale network would indicate about 2% year-over-year growth in sales, seven-day average sales. Both the U.K. system and Canadian system are showing flat year-over-year sales. The only area where we're actually seeing lower sales is home heating oil in the U.K. It is off about 10%. When you visit with our commercial teams over there, they think that's a combination of a couple of reasons. One, you've had unseasonably warm weather, and two, you've also had customers that are really trying to delay filling their tanks as long as they can. W hat that actually could tell you is you could see a surge in demand in the U.K. when you actually have cold weather hit. Export demand for diesel, also very strong, both to Latin America and Europe. For us, no indication of demand destruction.
In fact, some of the leading indicators, both GDP remaining flat and also a lot of the trucking surveys actually ticking up which would tell you that diesel demand is hanging in there very nicely.
Thank you so much.
Thank you. The next question is coming from Neil Mehta of Goldman Sachs. Please go ahead.
Thanks, guys. Maybe the first question is just on volumes. The volume guide you provided for 4Q, probably a little bit higher than what we thought. Just maybe you talk about you're running the system hard in the fourth quarter. I guess the DHT is back up too, so that should be a help as you go into the fourth quarter. Then maybe stepping back for the industry broadly, because we did run so hard in 2026, do you think 2027 is going to be a decent-sized turnaround year for the industry? Any thoughts around that?
Yeah, Neil. I'll start with the DHT. We really don't expect to have mechanical completion of the DHT till the end of the quarter or so. The DHT really isn't in the guidance. It is a light maintenance quarter for us, and so we'll run the assets hard with margins where they are. In terms of the rest of the industry and deferring of turnarounds, we've been public. We don't really defer any of our maintenance. We'll continue on our schedule for turnarounds. What you do hear from consultants is that there was about 1.5 MMbpd of refinery turnarounds globally that was deferred, which means turnaround activity is currently a little lighter than normal, and you would expect a heavier turnaround season next year.
That's helpful. Then just in terms of Q4 considerations, and maybe this is for you, Homer or Gary, but just we have average to start the quarter, the Gulf Coast indicator is up, the MidCon indicator is up as well, and just any thoughts as we think about the fourth quarter seasonally, typically things tick down, but we started off the quarter pretty strong. Any advice for us as we model out the fourth quarter?
Yeah. I think the big tailwinds for the fourth quarter, typically you get the uplift of blending butane into gasoline. In our North Atlantic system, you generally have a nice uplift after we start to make Arctic diesel that carries some premium there. Seeing some good tailwinds on the feedstock side with the heavy sours discounted and a lot of feedstock optimization opportunities. Then we are starting to see jet regrades turn positive again, which is also a tailwind. Outside of that, when you look at secondary products, it is a bit of a mix. Propylene and naphtha are off a little bit, but aromatics are up. Overall, I would say mainly tailwinds when it comes to capture rates for the fourth quarter.
Thanks, Gary.
Thank you. The next question is coming from Theresa Chen of Barclays. Please go ahead.
Morning. Gary, as we look at the very recent volatility in cracks, keeping in mind your comments about demand resiliency across your footprint, plus the floor being incrementally higher for international refiners, given high freight costs, natural gas and so on, how would you explain the recent downside volatility? Is that a result of incremental crude and products finding its way through the strait? What explains this, and how do you expect these factors to evolve over the near medium term?
Yeah, it looks like some of the downward pressure on cracks is really related to more headlines. People announcing releases from strategic reserves, lifting of Russian sanctions. Some of those types of things is what is actually driving some of the downward pressure on cracks. I think when you digest the data and you look at how much volume is actually coming out, then lifting of sanctions is more just a change in trade flows. I think we will see a recovery in cracks moving forward.
Got it. We have seen various headlines about the Trump administration potentially working with operators to reopen U.S. refining capacity that has been idled in the last 10 years. How seriously should we take these efforts? More broadly, how do you think the supply shortage of the market would be most effectively addressed?
This is Rich Walsh. I will try to answer that one. I really think you are focusing in here on Benicia. I would just remind you that the status of that refinery is it is safely idle and has been since April, and we have no plans to restart it. When we first announced and even just before we announced the shutdown of that facility, we had lots of discussions with both the state and the federal government and private parties, and none of those efforts actually materialized anything.
It is a tough environment to operate in the West Coast, and we just do not see the potential for that. The last thing I would just remind you is that to restart that refinery, you would have to re-inventory it, you would have to restaff it, you would have to undertake a rather extensive turnaround. It is not a simple process to restart it.
Yeah. Theresa, this is Lane. I'll add to that. I think if you're thinking more broadly speaking, almost any refinery that's been shut down will take a while to start up. I t'd be very difficult for them to help the prompt situation. We haven't had a lot of imbalance from the administration with respect to starting up other refineries, but we've heard the same things you guys have, so I'm not saying that that's not occurring. I think in the idea that there's these refineries that you can just sort of walk in and flip the lights and they're going to start running is not exactly the case. W e'll just see what's happening with respect to, on a longer-term basis, how this all plays out.
Thank you.
Thank you. The next question is coming from Phillip Jungwirth of BMO Capital Markets. Please go ahead.
Yeah, thanks. Good morning. Inter-quarter, we saw a lot of Venezuela upstream investment plans announced and some pretty ambitious production growth targets set. J ust wondering where you are now on Venezuela throughput versus capacity, and just what would it take to have enough confidence to invest in increasing the ability to run more heavy crude?
Phillip, this is Randy. We continue to see pretty good availability of Venezuela crude in the Gulf Coast system, and as you mentioned, we're pretty encouraged by some of the new investments that's going on in the country to grow production moving forward. We've been for a long time, and we continue to be the largest consumer of Venezuelan crude, and in the U.S. Gulf Coast, we're the largest by far. In fact, in the third quarter, we saw the Venezuelan crude compete very favorably compared to other heavy sour alternatives. As a result, we set a new processing record for Venezuelan barrels in the Valero system during the quarter. As we moved into the fourth quarter, we've seen the economic shift some. The higher freight market has especially impacted the heavy crude market.
We've seen discounts for Canadian crude in the Gulf Coast widen to as high as $27-$30 under Brent, making the Canadian barrel much more competitive versus the Latin barrel. As we kind of touched on before, our system is very flexible. Our ability to flex between different grades is a big competitive advantage, and as we move forward, we're going to continue to look at opportunities where we can further increase consumption of those barrels.
This is Lane. I'll add to that. Definitely one of the buckets that we look at in terms of our projects or even acquisitions with respect to this sort of heavy sour position, we feel like this is an area to help us with our feedstock optimization, and we're looking for debottlenecking opportunities and other opportunities in that space to increase our exposure to be able to run heavy sour.
Okay, great. Can you hit on the outlook for DGD margins and some of the noise in 3Q, 2Q around capture, anything one-off to keep in mind there, and how you see that metric trending into the fourth quarter?
Yeah. This is Eric. I think, just as a quick refresher, 2Q had a lot of one-off, one-time benefits like IEPA recovery, as well as a lot of modeling updates and year-to-date true-ups. You had kind of an unusually high second quarter because some of the one-time benefits. You also had the benefit, and we have talked about this on previous calls, there is a lag on how feedstocks price when they come into DGD, and you combine that with the volatility that we are all seeing, creates a lot of noise in margin capture. If you look at 2Q, you had feedstocks that we had bought in 1Q that were still much cheaper than the margin indicator.
You had that advantage, and then you had, if you recall, a lot of the comments about the conflict were kind of waning. As ULSD fell, even though that is the base commodity price for DGD, it did help with some of the volatility in the positions of how carbon was specifically pricing in that quarter. 3Q, you had the exact opposite. We had the impact. Obviously, we had the outage. We had the storm in DGD 3, which forced us to run a higher percentage of foreign feedstocks that were on the water.
Foreign feedstocks do not capture PTC, so we had a lower PTC capture than the margin indicator. Then you also had a lot of noise around the D4. With the conversation about SREs and whether or not they are going to be reallocated, we saw a pretty significant drop in the D4. As those product cargos were pricing, we saw a lot of volatility impact hit that lag as well.
It is really all tied up in lag and the volatility of both ULSD and the D4. If I think about 4Q, you still have a structurally high D4 RIN. We continue to see DGD very positive from a margin standpoint. We see positive cash flow. I think the real strength of the refining segment, where Gulf Coast is the most advantaged from a feedstock availability standpoint, combined with Darling being the largest producer of domestic feedstock, PTC benefits domestic feedstock. We are pivoting into, as always, maximizing the feedstock from Darling, now maximizing vegetable oil runs, really going into this D4 short that is going to continue into 2027. Capture is a very difficult thing to predict.
Thank you. The next question is coming from John Royall of Piper Sandler. Please go ahead.
G ood morning. Thanks for taking my question. My first question is a follow-up on the demand side. I think you've mentioned that it's been relatively stable despite significantly higher prices on both gasoline and diesel. I was wondering if, you guys are in this market every day, are you surprised that we haven't seen more demand response? Maybe, do you have a view on if there is a price level where maybe we'd start to see a little more elasticity?
Yeah. I would say, especially with all the headlines about pricing, we have been surprised that you don't really see any demand response so far. In terms of a price level where you would expect some kind of demand destruction, I don't really know where that is, because most people would've predicted we would've already seen it.
Yeah, fair enough. Thank you. I guess Homer mentioned in his opener that you might be looking at some capacity growth in ethanol. I was hoping you could dig in a little on that in terms of timing and magnitude and any other color you could give there.
Sure. This is Eric. With the new PTC or benefits with the 45Z, it's encouraging really all ethanol producers to take a look at higher volumes. We are looking at mostly capacity creep. On a refinery scale, this is not significant capital. It's very quick-hitting capital. It's small capacity creep. We're continuing to pursue our carbon sequestration projects at a couple of our sites. We are hoping those are hitting somewhere between late 2027 to mid 2028. All of that will grow both ethanol volume as well as lower ethanol CI, which makes it more attractive for export. We continue to see pretty strong export demand for ethanol, and our capacity is all pointed at growing exports.
Thank you.
Thank you. The next question is coming from Matthew Blair of Tudor, Pickering, Holt. Please go ahead.
G ood morning. Thanks for the question. On the freight rates, you mentioned the benefits on the crude side in your Gulf Coast system. We have two follow-ups here. One, are these higher freight rates a headwind to your North Atlantic and West Coast refineries, or are you able to use substitute crudes? Then two, what kind of impact are the freight rates having on your net backs for your Gulf Coast products exports? Is the rate just passed through or is it pulling down the economics for U.S. product exports?
Yeah, this is Gary. For the most part, the higher freight rates actually give us an advantage into the typical export markets into Latin America. You're largely competing with European barrels into those markets, and so we have a freight advantage there. The only place that it does tend to hurt us is the exports, the diesel exports going to Europe. I would tell you what it causes is just a lot of volatility with the ARBs going open and closed. Basically, Europe is short diesel and needs it, and so when the freight rates spike, their prices have to adjust to keep those ARBs open and keep the barrels flowing.
Yeah. On the crude side, this is Randy. We do have some exposure to the higher freight, at our Pembroke refinery into the West Coast, and to a smaller extent, into Quebec City, even though that refinery is mostly supplied via pipeline. However, the benefit of the Gulf Coast impact far outweighs that. In addition, we do have a large fleet of time charter vessels, which tends to buffer some of the impact of these higher spot freight rates.
Great. Thank you. Do you have any insights on the refining situation in Russia? Do you have any estimates on how much capacity is down and how long it might take to bring that capacity up? What are you thinking on potentially Russia diesel exports picking up here? Thank you.
Yeah. This is Gary. I think that the data we see shows that on a three-month average basis, compared to a 2024 equivalent period of time, there was about 1.4 MMbpd of refining capacity offline in Russia. S till significant. Most consultants estimate that it will take quite a long time to get that capacity back. I can't really give you a duration.
On the diesel exports, I think if you look at the volume that was announced, it kind of puts it at July levels of where Russian diesel exports would be, which is still 600,000-700,000 bbl/day below where Russia was last year at this time. I t's not a significant volume. As we've always stated, really, the sanctions or lifting of sanctions just result in change of trade flows, not really incremental supply coming onto or off of the market.
Thank you.
Thank you. Our next question is coming from Joe Laetsch of Morgan Stanley. Please go ahead.
Thanks. Good morning, team, and thanks for taking my questions. I wanted to just ask on St. Charles. Following the completion of the FCC work during the third quarter, could you just talk about how that unit is performing relative to expectations, and then maybe what kind of improvement should we expect in product yields or capture rates as we move into the fourth quarter and beyond? Then maybe more broadly beyond St. Charles, can you talk about where you're seeing the greatest signals and opportunities to deploy future growth CapEx?
Sure. I'll start with the St. Charles project. The project came online, and despite the fact that it wasn't fully operational during the third quarter, the EBITDA generated in the third quarter actually exceeded our FID for the project, so it's performing very well. As Lane mentioned, a lot of the project is really to fully utilize the alkylation capacity that we have there. Typically you would see the greatest benefits from that during gasoline season. We would expect more of a benefit in the second and third quarter than what you would see in the fourth quarter and first quarter.
Yeah. I'll add to it. This is Lane. In terms of projects that we like, it really is feedstock flexibility. If you think pre, I'm going to say Ukraine invasion, a lot of the shore up to the barrels are required to fill out U.S. refining capacity with VGO and other intermediates coming from that part of the world. Consequently, as we went through the summer there, even though we had wide margins, there were times when you had to go out and buy spot in VGO, actually your FCC margins were low.
One of the buckets that we see opportunity in is to make our system a little more resilient, is to not be quite so dependent on the VGO out there, so find ways to increase VGO production. I said earlier, we're optimistic about Venezuela and the Canadian sort of build-out for heavy sour. We'll look at ways to debottleneck our heavy sour capability.
Great. Thank you, that's helpful. Then just given the significant cash generation that we've seen and excess cash building on the balance sheet, can you just talk about how you're thinking about potential M&A opportunities here across refining renewable fuels and ethanol?
I'll start. Like every earnings call, we look at everything that comes on the market. We in particular like our Gulf Coast system. We've been unapologetic about that. We think it has the most flexibility, and we add the most value when we can actually optimize in our system. W e continue to look for opportunities in terms of on that. We also like the ethanol business. We'll continue to look at the ethanol business. A gain, we're going to be very adhered to our disciplined approach to capital. Even though we're sitting on a lot of cash, we're not going to change our approach in terms of our hurdle rates and our return metrics and how we think about the capital allocation framework that we use and that we've been using for the last 10 years.
Yep. That all makes sense. Thank you very much.
Thank you. Our next question is coming from Doug Leggate of Wolfe Research. Please go ahead.
G ood morning, guys. Hopefully you can hear me okay?
Hi, Doug.
Hi, guys. I got a couple of questions on reliability and the elevated refinery runs you guys have been able to deliver, not just for Valero, but I guess for the industry. Clearly maximizing exposure to the current environment is you're showing the market leading by example. What does this mean for the maintenance cycle, the reliability of your system, and more importantly, the reliability of the industry's capacity to run at these elevated levels. Do you see any risk of unplanned downtime, I guess, as we think about 2027 going forward? I know it's a generic question, but I'm just curious on your views.
Yeah. As I mentioned, we haven't really changed anything in terms of our philosophy on maintenance and taking our turnarounds. They're going as planned. I don't think you would expect to see anything different in terms of our reliability. If you do believe the consultant data that says 1.5 million barrels of refinery turnarounds were deferred, it does lead you to believe that there could be some unreliability there and a heavier maintenance season next year.
I guess we're hearing a couple of worries emerging from Europe in particular, which is why I asked the question, but I appreciate your perspective. My follow-up is, we've obviously got a massive reset in market expectations of mid-cycle. I'm curious if you can offer any thoughts on how this might impact your view on how you return cash to investors. I'm thinking specifically about if we really are in a higher mid-cycle environment, how would your dividend policy shift relative to, let's say, your share buyback policy? I'll leave it there. Thanks.
Hi Doug, it's Homer. I think we look at both the dividend and share repurchases as a component of our total shareholder return. We do have a higher mid-cycle view for all the reasons that Gary, Randy, and Lane mentioned, but we still operate in a cyclical industry. You're asking about dividend, I think I'll add, in theory, a higher mid-cycle increases your debt capacity too, but we're not obviously levering up.
Much like our balance sheet, we want to make sure our dividend is durable, both in good times and bad. The dividend's obviously a permanent commitment we've made which we will use and have used the balance sheet to defend as we did during the pandemic. That wasn't too long ago where our ability and willingness to pay the dividend was challenged. T he dividend is a one-way ratchet.
We want to make sure we have some ratable element to dividend growth through cycle. Also we look at dividend yield in the context of our closest peers, and we're kind of right in between both. With all this in mind, we're going to be more ratable on dividend growth, but obviously ensuring a predictable and attractive total return is a key aspect of our value proposition to our owners, and we'll continue to round out that total payout with share repurchases as a more efficient and flexible means on delivering on that promise over the long term.
Very clear, Homer. Thanks, guys. I appreciate it.
Yeah.
Thank you. Our next question is coming from Jason Gabelman of TD Cowen. Please go ahead.
Hi. I just wanted to go back and revisit the demand destruction discussion for a second because we have seen diesel prices in New York Harbor having a tough time really sustained over $5 /gal or around $200 /bbl as crude continues to trend higher. I t does seem like maybe at that level, there is some destruction or for whatever reason, it's difficult for diesel prices to move higher. As crude moves higher, there's potential for some compression in the diesel margin. Is that a risk you see going forward relative to where cracks are right now on the diesel side?
Yeah, I think that's a fair characterization. We've always felt like one of the things that's benefited refiners during this conflict is the fact that crude really hasn't gotten as expensive as what it could have gone. If for some reason crude runs up, I do think that it could cause some compression of refinery cracks.
Yeah. Thanks. My follow-up is just quickly on the M&A comment. You obviously mentioned you'd want to grow in the Gulf Coast if an asset became available, which makes sense. T he North Atlantic, the Quebec market, there's a couple of private assets up there. Those refining margins have been strong. There's probably some synergies within the business. Is that another region you would look to consolidate if there were assets that became available and made sense to you?
Yeah, this is Lane. It's another region that we like. I f something came available and, again, it met our investment criteria, which again, we want to be disciplined, and we want to make sure the thing makes sense for the entire economic cycle and not just sort of get romanced by the prompt situation. I t's a region that we feel like we have a really good position in, and if we could add to it and increase our flexibility and our ability to trade around it and create shareholder value, we'd certainly be interested in it.
Great. Thanks for the answers, guys.
Thank you. This brings us to the end of today's question-and-answer session. I would like to turn the floor back over to Mr. Donovan for closing comments.
Yeah, we appreciate everyone joining us today. As always, feel free to contact the investor relations team if you have any additional questions. Have a great day.
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