Valero Energy Corporation (VLO) Earnings Call Transcript & Summary

Greetings, and welcome to the Valero Energy Corp. Second Quarter 2026 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Brian Donovan, Vice President of Investor Relations. Thank you. You may begin.

Good morning, everyone, and welcome to Valero Energy Corporation's Second Quarter 2026 Earnings Conference Call. I'm joined today by Lane Riggs, Chairman, CEO and President; Gary Simmons, Executive Vice President and COO; Rich Walsh, Executive Vice President and General Counsel; Homer Bhullar, Senior Vice President and CFO; as well as several other members of Valero's senior management team. If you have not yet received a copy of our earnings release, it is available on our website at investorvalero.com. Included with the release are supplemental tables providing detailed financial information for each of our business segments along with reconciliations and disclosures for any adjusted financial metrics referenced during today's call. If you have any questions after reviewing these materials, please feel free to reach out to our Investor Relations team. Before we begin, I would like to draw your attention to the forward-looking statement disclaimer included in the press release. In summary, it says that statements made in the press release and during this conference call that express the company's or management's expectations or forecasts of future events are forward-looking statements. and are intended to be covered by the safe harbor provisions under federal securities laws. Actual results may differ from those expressed or implied due to various factors, which are outlined in our earnings release and filings with the SEC. I'll now turn the call over to Lane for opening remarks.

Thank you, Brian, and good morning, everyone. We're pleased to report a strong second quarter driven by exceptional operational and commercial performance across all 3 of our business segments. While geopolitical and macroeconomic factors continue to drive volatility, our team executed extremely well adapting to changing market conditions and capturing opportunities across our refining, renewable diesel and ethanol segments. Our refineries operated safely and reliably, helping meet resilient demand for transportation fuels. Our renewable diesel and ethanol segment also performed well, supplying additional liquid fuels to the market. On the financial side, our strong balance sheet remains a hallmark of our capital allocation framework. In addition to building cash during the quarter, we continue to demonstrate our long-standing commitment to shareholders. And earlier this month, we announced a dividend of $1.20 per share. Strategically, we still expect to complete our FCC Unit optimization project at our St. Charles Refinery during the third quarter. This $230 million investment is well timed and will allow us to increase our production of high-value products including output and finished gasoline. Looking ahead, we continue to see a constructive environment for our business. Refining fundamentals remain supported by low global product inventory, limited excess refining capacity and resilient demand for transportation fuels. U.S. Gulf Coast continues to be one of the most advantaged crude sourcing regions in the world, supported by abundant domestic production and access to a diverse range of other feedstocks, including Canadian and Venezuelan crude. Our strategically positioned and highly competitive asset base is also well suited to supply constrained global products market. In closing, our strong results reflect the disciplined consistency of our operational and commercial execution. Coupled with our differentiated balance sheet. These strengths position us well and provide plenty of financial flexibility. With that, I'll turn the call over to Homer.

Thank you, Lane. For the second quarter of 2026, net income attributable to Valero stockholders was $3.7 billion or $12.62 per share compared to $714 million or $2.28 per share for the second quarter of 2025. Excluding the adjustments shown in the earnings release tables, adjusted net income attributable to Valero stockholders for the second quarter of 2026 was $3.7 billion or $12.54 per share. The refining segment reported $4.5 billion of operating income for the second quarter of 2026 compared to $1.3 billion for the second quarter of 2025. Adjusted operating income for the second quarter of 2026 was $4.4 billion. Refining throughput volumes in the second quarter of 2026 averaged 3 million barrels per day. Refining cash operating expenses were $4.70 per barrel in the second quarter of 2026. The renewable diesel segment reported operating income of $717 million for the second quarter of compared to an operating loss of $79 million for the second quarter of 2025. Renewable Diesel segment sales volumes averaged 3.8 million gallons per day for the second quarter of 2026. The ethanol segment reported $318 million of operating income for the second quarter of 2026 compared to $54 million for the second quarter of 2025. Ethanol production volumes averaged 4.7 million gallons per day in the second quarter of 2026. G&A expenses were $233 million for the second quarter of 2026. Depreciation and amortization expense was [ $737 million ] for the second quarter of 2026, which includes approximately $33 million of incremental depreciation expense related to ceasing refining operations at our Benicia Refinery. Net interest expense was $145 million and income tax expense was $1.1 billion for the second quarter of 2026. The effective tax rate was 21%. Net cash provided by operating activities was $5.6 billion in the second quarter of 2026. Included in this amount was a $706 million favorable impact from working capital and $389 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 $4.5 billion in the second quarter of 2026. Regarding investing activities, we made $350 million of capital investments in the second quarter of 2026, of which $290 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 $346 million in the second quarter of 2026. Moving to financing activities. We remain committed to our disciplined capital allocation framework. Shareholder cash returns totaled $2.6 billion in the second quarter of 2026, resulting in a payout ratio of 59% for the quarter. And as Lane mentioned earlier, we announced a quarterly cash dividend on common stock of $1.20 per share on July 16. Turning to the balance sheet. We ended the quarter with $9.1 billion of total debt, $2.2 billion of total finance lease obligations and $7.9 billion of cash and cash equivalents. The debt-to-capitalization ratio, net of cash and cash equivalents was 11% as of June 30, 2026, reflecting a cash build of $2.1 billion during the quarter. Consistent with our prior messaging, we built cash above the high end of our long-term $4 billion to $5 billion cash target to preserve optionality in a volatile market environment while also exceeding our minimum payout commitment. And earlier this month, we repaid the $100 million outstanding principal balance of our 7.65% notes that matured on July 1. An additional $572 million of maturities due later this year will be repaid using cash held from debt we proactively issued in the first quarter. Overall, 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 $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 towards growth projects. Repairs to the Port Arthur DHT unit are expected to be completed and the unit returned to service by year-end. Total repair costs are estimated to be $250 million included in our updated guidance for sustaining CapEx. 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. On the growth side, our projects are focused primarily on shorter cycle optimization investments that enhance crude and product optionality across our refining system as well as efficiency and rate expansion projects within our ethanol plants. Collectively, these projects should strengthen the earnings capacity of our existing asset base. For modeling our third quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.78 million to 1.83 million barrels per day; Mid-Continent at 460,000 to 480,000 barrels per day; West Coast at 110,000 to 120,000 barrels per day; North Atlantic at 450,000 to 470,000 barrels per day. We expect refining cash operating expenses in the third quarter to be approximately $4.75 per barrel. For the renewable diesel segment, we expect sales volumes of approximately 335 million gallons in the third quarter. Operating expenses should be $0.49 per gallon, including $0.21 per gallon for noncash costs such as depreciation and amortization. Our ethanol segment is expected to produce 4.8 million gallons per day in the third quarter. Operating expenses should average $0.39 per gallon, which includes $0.04 per gallon for noncash costs such as depreciation and amortization. For the third quarter, net interest expense should be about $140 million. Total depreciation and amortization expense in the third quarter should be approximately $700 million. Lastly, we expect G&A expenses this year to be approximately $960 million.

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 2 questions. If you have more than 2 questions, please rejoin the queue as time permits to ensure other callers have time to ask their questions.

[Operator Instructions] Our first question comes from the line of Neil Mehta with Goldman Sachs.

Obviously, an extraordinary quarter. I think a lot of us remember when $4 your mid-cycle EPS and doing $12 in a quarter is pretty extraordinary. And the kind of -- we're not quarter-to-quarter folks here, but as we think about bridging 2Q to 3Q, we just love your guys' perspective. We just look at Gulf Coast indicators, they're up from $30 to $41 on your database. But the shape of the oil curve is probably more favorable with dated Brent versus your month 1 Brent no longer being in such a steep backwardation. So can you just talk about some of the moving pieces as we bridge from 2Q to 3Q? And give us any color you can provide, knowing that there's a lot of quarter left.

Neil, this is Gary. I'll try to go through it. Still early in the quarter, but to us, both margins and capture rates look constructive relative to the second quarter. As you mentioned, really, the biggest tailwind in the quarter is really around feedstocks. The market structure thus far is resulting in an improvement in delivered crude costs relative to the benchmarks. Thus far, Randy's team has done a really good job of purchasing several grades of crude at discounts to the benchmarks where in the second quarter, a lot of the physical grades were being traded at significant premiums to the screen. Naphtha is at a premium to Brent, which in the second quarter was flat to Brent. Propylene has strengthened, sulfur remains strong. In the second quarter, we did get a nice tailwind from Jet, which we haven't seen in the third quarter. But we do now have an open arb to export Jet to Europe. And as we transition to winter-grade diesel specs, I suspect we'll start to see jet strengthen as we move throughout the quarter. So really, the margin environment thus far is stronger than what we saw in the second quarter. And based on what we know today, we should see an improvement in capture rates as well.

Follow-up, Homer, this one probably for you. I just -- you're sitting above what I would characterize as your mid-cycle cash balance of $4 billion to $5 billion right now. So how are you thinking about deploying it, whether to hold back excess cash or to continue to shrink the share count. Any perspective would be great.

Yes, Neil, maybe I'll just start reiterating what we've said around our decision to build cash this year was really driven around prudently managing our volatility in commodity prices, right? So the risk that we're trying to address is when you have a rapid pullback in commodity prices, particularly crude, you tend to -- that tends to be accompanied by a draw on working capital and cash. And in that event, if there's a significant draw on cash, we just want to make sure we're not constrained on our ability to return cash to shareholders. But that said, because of the current environment we're in, coupled with the balance sheet where we don't really have any need or pressure to further lower leverage we can pay out well above our target of 50% and build cash at the same time. I mean Gary obviously talked about things on the refining side going to the third quarter. I'm sure Eric will also speak to a constructive backdrop for our other 2 businesses, ethanol and renewable diesel. And in this environment, I think building cash and shareholder returns don't have to be mutually exclusive. So I'll reiterate that our long-term target on cash and leverage remains unchanged. While the volatility is likely not behind us at this point, we'll continue to hold a little bit more cash. But if we see a pullback in commodity prices or lower volatility, we're in a great position to accelerate shareholder returns as we move back towards our long-term cash target of $4 billion to $5 billion. Long answer, but hopefully helpful context for you.

Our next question comes from the line of Theresa Chen with Barclays.

Over the last several years, repeated geopolitical disruptions have highlighted just how tight global refining capacity remains post pandemic even with meaningful capacity additions in emerging markets. And each successive disruption appears to have produced a larger-than-expected margin response, most recently following events in the Middle East. Do you believe that the industry has structurally shifted to a higher mid-cycle refining margin environment? And if so, what are your assumptions that would underpin such an outlook?

Yes, Theresa, this is Gary. And we do have a much more bullish view of a future mid-cycle than what you would calculate using historic margins. The primary basis for that view is that when we look at the mid-cycle using -- that you would get calculating historic margins, product crack spreads were largely set by cracking margins in Northwest Europe. And as supply and demand balances have tightened, it appears that refinery crack spreads are now really being set by hydroskimming margins in Northwest Europe. So based on future demand projections as well as planned capacity additions, we believe hydroskimming margins will continue to set product crack spreads moving forward, which will result in higher crack spreads. Additionally, that hydroskimming capacity is subject to rising cost of carbon credits which drives those cracks higher as well as inflationary pressures on both OpEx and CapEx that will result in the higher floor on refinery cracks. Finally, we also see a much more bullish outlook on crude quality discounts going forward compared to history especially for heavy sour crude, which also has a very positive impact on our future mid-cycle view as well.

And also appreciate the really impressive results in the renewable fuel segments. If we could get an update on your outlook for unit margins and profitability on a go-forward basis here, both near and long term, that would be great.

Yes, Theresa, this is Eric. I think if we start with DGD and renewable diesel, you see the -- it benefited from the same volatility that benefited liquid fuels in general. But the underlying benefit that you saw in 2Q is the fact that the RVO and the D4 RIN increased at a rate far quicker than fat prices. And so as we look at that going forward, we still see values higher than fat prices. And so you have that tailwind, certainly through '26 and '27 with the RVO as it has been set. Even with the recent drop in the last few days, it's still very positive versus historical. So we see RD looks more positive for the rest of this year and into '27. And then with ethanol, same benefit with the general increase in gasoline and octane values. But on top of that, the production tax credit that we are now capturing it's $0.14 year-to-date probably $0.17 for the full year. And if you look into '27 through '29, it's probably $0.19 a gallon. You put that in perspective with the historical mid-cycle of $0.25, that says that you're almost doubling the value of ethanol through 2029. So you've got some significant structural tailwinds in both RD and ethanol on top of the benefit that we're seeing today with just the whole world in short of the fuels and seeing a lot of volatility.

Our next question comes from the line of Manav Gupta with UBS.

Congrats, guys, I think this was your highest ever quarterly earnings. Let me know if I'm wrong, but I think it was the highest. I just had a quick question on what -- kind of relating to refining macro. So I'll ask them together. First, the number that is floating around is that there's 5 million barrels of global capacity or 10% of the global capacity, which is offline between Middle East as well as Russia. And I'm just trying to understand what would that do to the global product inventories. And even if we open up magically in the next 1 month, how long do you think it would actually take to replenish some of this global product inventory, which has been depleted in a major way because of the extended shutdown that we are having. And my second question here is when we look at the Russia-Ukraine conflict when it started, diesel moved up, gasoline really did not participate. This time it's a little different. Gasoline is actually very actively participating and it's closing the gap to diesel. I'm assuming you're still in max diesel mode, but gasoline cracks are much stronger. So if you could talk a little bit about what's driving the relative strength in gasoline? And are the gasoline markets really that tight if you could address those things.

Manav, I'll try to go through those. So yes, I think we agreed about 5 million barrels a day of refining capacity is off-line. When we look at the consultant data that we subscribe to, it would show that globally total light product inventories are down about 150 million barrels from where they were to start the year. We're about 130 million barrels below where they would normally be at this time of year. Their data would suggest that if the conflict were to end today, global inventories remained below the 5-year average range through 2027. Gasoline recovering fastest, followed by diesel and then jet. These projections do assume that you see suppressed global demand for clean products this year as a result of higher prices and that we'll see normalized operations in the Middle East and Asia following the reopening of the Strait. What I would tell you is what I see today, I think it takes longer to recover than those projections. I think some of the refining capacity, especially in the Middle East, sustained damage and will take a longer time to come back on. And then as you mentioned, the Ukranian drone attacks on Russian refining capacity are beginning to have a significant impact on the market, and I don't see those slowing down. In terms of the relative strength of gasoline relative to diesel, I think a lot of what we've seen on gasoline is that normally, you see a flow of gasoline from Europe to the United States. And with the strength in Europe, the transatlantic arb to ship gasoline from Europe to the U.S. is closed. In addition to that, we see good export demand for gasoline in the Latin America. So the combination of the closed arb import barrels from Europe open-arb export barrels of Latin America has a net gasoline import that's down about 400,000 barrels a day from where it historically is. So that, combined with a good domestic demand is really what's leading to the relative strength in gasoline.

Our next question comes from the line of Sam Margolin with Wells Fargo.

This question is sort of along the same capital allocation lines, but it's about growth. I do think the market has accepted the fact that refineries represent a bottleneck in the energy complex right now? And that seems pretty clear. And so the question is just how are you thinking about growth opportunities within that? And I guess there's some questions about kind of inflation that flow into that, too.

Yes, Sam, it's Lane. What I would say is post-COVID we were -- we would had been at about $1 billion post-COVID on strategic spending. And that was really capped by, I would say, our project execution efficiency. Post COVID, we've been about $0.5 billion on average, maybe creep up to $0.7 billion, a lot of which -- if you look back at it was renewable spend. So we sort of carry renewable spend down because the sort of policy isn't super supportive and we're trying to let the renewable business sort of catch up with policy and some of the other things that are happening. So really our spend largely in refining and ethanol. We still look for projects. We're attentive and we're very disciplined in terms of how we look at our projects, meet our gating system. We do have, as Gary alluded to, and I think most of the industry accepts higher mid-cycle going forward. But we -- the projects we like in refining obviously, are more around 2 things, I would say. One is yield improvement. The other one is, I would call it, commercial leverage feedstock leverage, how can we get in a better position things that were potentially long and trying to get rid of those and then where we have a chronic short -- I think it's one of the examples I used in the past the whole United States is short of VGO and so we're trying -- we'll look through and find the projects that make sense for us to sort of improve our overall commercial leverage in that space. We have higher -- like I said, we have a higher mid-cycle look going forward for that. But we're not going to lose our discipline with respect to our capital and how we're going to spend money. But with that said, Gary kind of touched it the higher cost of these projects also puts sort of a lower -- it supports the higher mid-cycle as well. There's a lot of things here supporting a higher mid-cycle in refining.

Okay. And then this is just a follow-up. I think one of the limiting factors on maybe crude throughput capacity growth in the past decade, is that crude availability wasn't necessarily improving. E&Ps wanted to send their incremental barrel into export markets. And now that may be a little different because you have Venezuela that's growing volumes into the U.S. and then Canada, a lot of Canadian producers seem to want to be in growth mode too, and that's kind of a captive barrel. Is there anything changing on the feedstock side that affects your view of crude throughput optionality? SP999

Well, yes. I would just be -- we don't try to provide too much, I would say, strategic specific projects. I will say we see the same thing. We see that -- we see a forward world, whether it's more Canadian heavy, there's more Venezuelan. That helped our current asset base. If you think about what I said earlier with respect to the -- how I would like to improve our position with respect to BGO and maybe not quite so much naphtha-rich crudes, that's -- I'd like to see projects sort of in that incrementing crude in that space for sure.

Our next question comes from the line of John Royall with Piper Sandler.

So my first question is just a follow-up on DGD margins and specifically looking at the July indicator, it's quite high. And it looks like, in addition to the higher diesel price and RIN prices that were kind of known and expected. You've also seen a tick down in feedstock costs as well. And maybe you could talk about the dynamics kind of driving feedstock costs lower and how you expect that to trend for the rest of 3Q. And just to confirm, when feedstock prices are coming down, we should expect to capture headwind there in 3Q. Just wanted to confirm that.

Yes, that's absolutely right. What you're seeing on the feedstock side is the current policy favors domestic feedstocks first over foreign feedstocks. Soybeans and ag in general continues to be -- have above expectations in terms of crop yields, and that's globally, not just in the U.S. So that you see length in corn, you see length in soybeans and the U.S. policy with this high D4 is somewhat eliminating the benefits of what usually is the low CI waste feedstocks being advantaged over veg oils. The U.S. is becoming largely indifferent, just looking for just volume to fill the D4 obligation. Externally in the world, the rest of the world is still driven on low carbon pathways and feedstocks. And so you still see soybean oil is not the preferred feedstock for a lot of the compliance volume that goes into Canada and Europe. So in general, the world is well supplied feedstocks. I think one of the challenges we'll see will be a headwind going into the rest of the year is how the new tariffs are going to affect some of this. But in general, you see the demand for liquids and the values associated, whether it's LCFS or D4s exceeds where feedstock prices have been.

Great. And then my next question is on the crude slate on the Gulf Coast. And just wondering if you could give us some color on how much Venezuela you able to run in your system today. And if you could also talk about the availability of Mexican grades, I think there's been an effort there to curb exports of crude. So just wondering what the market for Mexican crude looks like today.

Yes. So I'll start with Venezuela. I mean -- this is Randy, by the way. Yes, we continue to see pretty good availability out of Venezuela on the heavy crude supply, and we're pretty encouraged by the growth that we're seeing both in supply and exports out of the country. I think if you look kind of over history, we've been the largest U.S. consumer of Venezuelan crude over the last several years, and we expect that to continue going forward. Our ability to process very high volumes of this heavy high asset crude is a key competitive advantage for our system. But as always, we always compare this against other alternatives, including Canadian heavy. If you kind of look at June, we saw Canadian crude prices rise quite a bit due to weather and flooding issues up in Canada. That caused us to kind of pivot to more Venezuela. And we'd expect to see processing rates of Venezuelan heavy crude in the coming months that exceed our historical maximum. And down in Mexico, right now, their exports have -- they are down compared to last year, mainly due to higher refinery runs at the start of the dose focus. But we do see this pretty volatile month-to-month that -- so as the refining system runs higher, their exports are obviously lower. So we see that trend likely continuing going forward.

Our next question comes from the line of Joe Laetsch with Morgan Stanley.

So I wanted to dig in on some of the regions. And starting with the West Coast. Can you just talk about what you're seeing from a local crude pricing and availability standpoint? It looked like a good quarter for the West Coast in Wilmington. So maybe you just how that asset is performing and competitiveness of it currently relative to the rest of the portfolio. And then on the Gulf Coast, that was also stronger than we had modeled despite some of the downtime at Port Arthur. Just your perspective on both the West Coast and the Gulf Coast would be helpful.

Joe, this is Randy. I'll touch on the crude side. Obviously, the combination of the refinery closures and recent production rate increases on some of the California domestic crude has left the market pretty well supplied. That's been exacerbated by the idling of the San Pablo pipeline. It moves crude into the Bay Area, forcing more of these domestic barrels are clear to the refineries in L.A. With these logistic bottlenecks, we have seen prices for California crude weakened considerably, and we've been working with our Wilmington refinery to increase processing rates of these barrels and anticipate any record levels of these crudes in the coming months.

On the Gulf Coast, I would say really the tailwinds in the quarter that improved our capture rates, really, the first one was jet fuel. If you look in the second quarter of last year, our jet yield was 9%. Second quarter this year, we ramped that up to 12%, almost increased our yet yield by close to 100,000 barrels a day, which was really supportive of capture rates. In addition to that, as I've talked about, we see a real strong export market. And so those premiums into the export market also helped our capture rates as well.

Great. And then could you just talk a bit about the impact of policy changes that we've seen recently. So in the past, you've talked about using the Jones Act to move some product from the Gulf Coast to the West Coast and other areas of the U.S. Would you expect this to continue to be extended?