Greetings, and welcome to the Valero Energy Corporation Second Quarter 2026 Earnings Call. At this time, participants are in listen-only mode. A question-and-answer session will follow the formal presentation.
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 am joined today by Lane Riggs, Chairman, CEO and President; Gary Simmons, Executive Vice President and COO; Richard J. Walsh, Executive Vice President and General Counsel; Harminder 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 will now turn the call over to Lane for opening remarks.
Thank you, Brian, and good morning, everyone. We are pleased to report a strong second quarter driven by exceptional operational and commercial performance across all three 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 segments 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 longstanding commitment to shareholders and, earlier this month, 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 alkylate and finished gasoline. Looking ahead, we continue to see a constructive environment for our business. Refining fundamentals remain supported by low global product inventories, limited excess refining capacity, and resilient demand for transportation fuels.
The 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 product markets. In closing, our strong results reflect the discipline and 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 will turn the call over to Harminder.
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 2026, 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’s 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’s 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.
Stockholder 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 toward 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 and are 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; and 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 3.5 million gallons per day 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 $700 million. Lastly, we expect G&A expenses this year to be approximately $960 million.
Thanks, Harminder. 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.
We will now be conducting a question-and-answer session. You may press 2 to remove yourself from the queue. Our first question comes from the line of Neil Mehta with Goldman Sachs.
Please proceed with your question.
Yes. Good morning, Lane, Homer, Gary, team. Obviously, an extraordinary quarter.
I think a lot of us remember when $4 was your mid-cycle EPS, and doing $12 in a quarter is pretty extraordinary. And that kind of—we are not quarter-to-quarter folks here—but as we think about bridging Q2 to Q3, we would just love your guys’ perspective. We just look at Gulf Coast indicators.
They are 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 deep backwardation. So can you talk about some of the moving pieces as we bridge from Q2 to Q3 and give us any color you can provide, knowing that there is a lot of quarter left?
Yes. Good morning, Neil. This is Gary.
I will 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 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, whereas 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, whereas in the second quarter it was flat to Brent.
Propylene has strengthened. Sulfur remains strong. In the second quarter, we did get a nice tailwind from jet, which we have not 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 will 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.
Hey, Gary. Follow-up, Homer, this one is probably for you. You are sitting above what we would characterize as your mid-cycle cash balance of $4 billion to $5 billion right now.
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.
Yeah. Neil, maybe I will just start by reiterating what we have said around our decision to build cash this year. It was really driven by prudently managing volatility in commodity prices.
Right? The risk we are trying to address is when you have a rapid pullback in commodity prices, particularly crude, that tends to be accompanied by a draw on working capital and cash. In that event, if there is a significant draw on cash, we just want to make sure we are not constrained in our ability to return cash to shareholders.
With that said, because of the current environment we are in, coupled with a balance sheet where we do not 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, you know, things on the refining side going into the third quarter. I am sure Eric will also speak to the constructive backdrop in our other two businesses, ethanol and renewable diesel.
And in this environment, I think building cash and shareholder returns do not have to be mutually exclusive. So I will reiterate that our long-term target on cash and leverage remains unchanged. You know, while the volatility is likely not behind us at this point, we will continue to hold a little bit more cash.
But if we see a pullback in commodity prices or lower volatility, we are in a great position to accelerate shareholder returns as we move back toward our long-term cash target of $4 billion to $5 billion. Long answer, but hopefully helpful context for you.
That is great. Thank you, Harminder.
Thank you. Our next question comes from the line of Theresa Chen with Barclays. Please proceed with your question.
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?
If so, what are your assumptions that would underpin such an outlook?
Yes, Theresa, this is Gary. And we do have a much more constructive 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 that you would get by 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 costs of carbon credits, which drive those cracks higher, as well as inflationary pressures on both OpEx and CapEx that will result in a 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.
Thank you. And also, we 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 that 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.
So as we look at that going forward, we still see D4 values higher than fat prices. And so you have that tailwind, certainly through 2026 and 2027, with the RVO as it has been set. Even with the recent drop in the last few days, it is still very positive versus historical.
So we see RD looking more positive for the rest of this year and into 2027. And then with ethanol, the main benefit is the general increase in gasoline and octane values. But on top of that, the production tax credit that we are now capturing is $0.14 year to date, probably $0.17 for the full year.
And if you look into 2027 through 2029, it is probably $0.19 a gallon. Put that in perspective with a historical mid-cycle of $0.25. That says that you are almost doubling the value of ethanol through 2029.
So you have got some significant structural tailwinds in both RD and ethanol, on top of the benefit that we are seeing today with just the whole world being short liquid fuels and seeing a lot of volatility.
Very helpful. Thank you.
Thank you. Our next question comes from the line of Manav Gupta with UBS. Please proceed with your question.
Congrats, guys. I think this was your highest-ever quarterly earnings. Let me know if I am wrong, but I think it was the highest.
I just had a quick question relating to refining macro, so I will ask them together. First, the number that is floating around is that there are 5 million barrels of global capacity, or 10% of the global capacity, offline between the Middle East and Russia. And I am just trying to understand what that would do to global product inventories.
And even if we open up, magically, in the next one 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? 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 is a little different. Gasoline is actually very actively participating, and it is closing the gap to diesel. I am assuming you are still in max-diesel mode.
But gasoline cracks are much stronger. So if you could talk a little bit about what is driving the relative strength in gasoline, and are the gasoline markets really that tight? If you could address those things.
Thank you.
Manav, I will try to go through those. So yes, I think we agree about 5 million barrels a day of refining capacity is offline. 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 at the start of the year.
We are 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 remain below the five-year average range through 2027, with 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 will see normalized operations in the Middle East and Asia following the reopening of the Strait.
What I would tell you is, based on 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 online. And then, as you mentioned, the Ukrainian drone attacks on Russian refining capacity are beginning to have a significant impact on the market, and I do not see those slowing down.
In terms of the relative strength of gasoline versus diesel, I think a lot of what we have 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 Latin America.
So the combination of the closed arb for import barrels from Europe and the open arb for export barrels to Latin America has net gasoline imports down about 400,000 barrels a day from where they historically are. That, combined with good domestic demand, is really what is leading to the relative strength in gasoline.
Thank you.
Thank you. Our next question comes from the line of Sam Margolin with Wells Fargo. Please proceed with your question.
Good morning. Thanks for taking the question. This question is sort of along the same capital allocation lines, but it is about growth.
You know, 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, you know, I guess there are some questions about kind of inflation that flow into that too.
Thank you.
Yes, Sam, it is Lane. What I would say is, pre-COVID, we would have been at about $1 billion in strategic spending, and that was really capped by, I would say, our project execution efficiency. Post-COVID, we have spent about $500 million on average, maybe creeping up to $700 million, a lot of which, if you look back at it, was renewable spending.
So we have sort of carried renewable spending down because, you know, the policy is not super supportive. And we are trying to let the renewable business sort of catch up with policy and some of the other things that are happening. So really, our spending is largely in refining and ethanol.
We still look for projects. We are attentive, and we are very disciplined in terms of how we look at our projects meeting our gating system. We do have, as Gary alluded to, and I think most of the industry accepts, a higher mid-cycle going forward.
But the projects we like in refining are more around two things, I would say. One is yield improvement. The other one is what I would call commercial leverage, feedstock leverage.
How can we get in a better position on things that we are potentially long and trying to get rid of, and then where we have a chronic short? You know, I think one of the examples I used in the past is the whole United States is short VGO. And so we will look through and find the projects that make sense for us to sort of improve our overall commercial leverage in that space.
We have a higher mid-cycle outlook going forward, but we are not going to lose our discipline with respect to our capital and how we are going to spend money. But with that said, Gary kind of touched on it. The higher cost of these projects also supports the higher mid-cycle as well.
So there are 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 was not improving.
E&Ps wanted to send their incremental barrels into export markets. And now that may be a little different because you have Venezuela 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 is kind of a captive barrel. Is there anything changing on the feedstock side that affects your view of crude-throughput optionality?
Well, yeah. I would just be, you know—we do not try to provide too many, I would say, strategic-specific projects. I will say we see the same thing.
We see a forward world where there is more Canadian heavy and there is more Venezuelan. That helps our current asset base. If you think about what I said earlier with respect to how I would like to improve our position with respect to VGO and maybe not quite so many naphtha-rich crudes, I would like to see projects that are sort of in that space, incrementing crude in that space for sure.
Thank you.
Thank you. Our next question comes from the line of John Royall with Piper Sandler. Please proceed with your question.
So my first question is just a follow-up on DGD margins. And specifically, looking at the July indicator, it is quite high, and it looks like, in addition to the higher diesel price and RIN prices that were kind of known and expected, you have 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 capture tailwinds there in 3Q? Just wanted to confirm that.
Yes, that is absolutely right. What you are seeing on the feedstock side is the current policy favors domestic feedstocks first over foreign feedstocks. Soybeans and agriculture in general continue to be above expectations in terms of crop yields, and that is globally, not just in the U.S. So you see length in corn, and you see length in soybeans.
And U.S. policy, with this high D4, is somewhat eliminating the benefits of what usually are the low-CI waste feedstocks being advantaged over vegetable oils. The U.S. is becoming largely indifferent, just looking for volume to fill the D4 obligation. Externally in the world, the rest of the world is still driven by 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 with feedstocks. I think one of the challenges we will see—a headwind going into the rest of this 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 is LCFS or D4s, exceed where feedstock prices have been.
Great. Thanks, Eric. 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 Venezuelan crude you are able to run in your system today. And if you could also talk about the availability of Mexican grades. I think there has been an effort there to curb exports of crude.
So just wondering what the market for Mexican crude looks like today.
Yes. So we will start with Venezuela. I mean, this is Randy, by the way.
Yeah, and we continue to see pretty good availability out of Venezuela on the heavy crude supply, and we are pretty encouraged by the growth that we are seeing both in supply and exports out of the country. I think if you look kind of over history, we have 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-acid 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. And that caused us to kind of pivot to more Venezuelan crude.
And we would expect to see processing rates of Venezuelan heavy crude in the coming months that exceed our historical maximum. And down in Mexico, you know, right now, their exports are down compared to last year, mainly due to higher refinery runs with the startup of Dos Bocas. But we do see that as pretty volatile month to month.
So as the refining system runs higher, their exports are obviously lower. So we see that trend likely continuing going forward.
Thank you.
Thank you. Our next question comes from the line of Joe Laetsch with Morgan Stanley. Please proceed with your question.
Great. Thanks. Good morning, and thanks for taking my questions.
So I wanted to dig in on some of the regions. Starting with the West Coast, can you just talk about what you are seeing from a local crude pricing and availability standpoint? It looked like a good quarter for the West Coast and Wilmington.
So maybe you could just talk about how that asset is performing and competitiveness a bit 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 will 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.
This has been exacerbated by the idling of the San Pablo Bay Pipeline, which moves crude into the Bay Area, forcing more of these domestic barrels to clear to refineries in L.A. And with these logistics bottlenecks, we have seen prices for California crude weaken considerably, and we have been working with our Wilmington refinery to increase processing rates of these barrels and anticipate near-record levels of these crudes in the coming months.
Yes. And on the Gulf Coast, I would say really the tailwinds in the quarter that improved our capture rates—the first one was jet fuel. If you look at the second quarter of last year, our jet yield was 7%.
This year, we ramped that up to 12%, which increased our yield by close to 100,000 barrels a day. That was really supportive of capture rates. In addition to that, as I have talked about, we see a really strong export market, and so those premiums in the export market also helped our capture rates as well.
Great. Thanks, Randy. Thanks, Gary.
And then could you just talk a bit about the impact of policy changes that we have seen recently? So in the past, you have 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?
Well, whether it is extended or not, I do not have a lot of insight. I will tell you that I think that has been critical to keeping PADD 1 and PADD 5 supplied. In PADD 5, we saw the barrels coming from the Far East disappear.
And so we certainly were moving barrels from our Corpus Christi refinery to PADD 5 to keep that market supplied. Also, with the transatlantic arb closed to send gasoline from Europe to PADD 1, the Jones Act waiver has been very critical to keeping PADD 1 supplied as well.
Great. Thank you.
Thank you. Our next question comes from the line of Doug Leggate with Wolfe Research. Please proceed with your question.
Good morning, guys. Thanks for having me on. I seem to recall having a discussion with Homer about net debt zero not so long ago, and it seemed unrealistic.
So extraordinary times, indeed. My question now—I have got two things I wanted to bring up, if you do not mind. First of all, we are just sitting here watching extraordinary margins.
We do not know what the duration is. But you have got practically no net debt. I think you are kind of signaling a preparedness to be patient with building cash.
Why is a rebalancing of dividends and buybacks not an appropriate thing to consider if you believe mid-cycle should be higher going forward?
Hey, Doug. It is Harminder. I mean, I think ultimately this comes down to a discretionary use of cash, right?
Or really, it is discretionary use of excess cash. There is always going to be an underlying element of share repurchases and dividends to meet our minimum commitment of the 50% that we have laid out for our owners. Right?
Beyond that, you know, you are looking at basically alternative uses of capital when you are looking at our broader capital allocation framework. And Lane obviously talked about the discipline we are going to have around growth investments, right, with a minimum return threshold. Acquisitions, we have talked about.
You know, they have to have good strategic value. Right? And so, you know, let me rule out that part of our capital allocation framework where we are not going to all of a sudden do growth or acquisitions just because we are flush with cash.
That has obviously worked really well for us, and it is evident when you look at our long-term return on invested capital or return on equity. It is well north of 15%. Right?
And so keep in mind that includes all sustaining capital, not just growth capital. So that tells you our growth projects have actually returned well in excess of that. So absent those uses, we are clearly not just going to have cash sit on our balance sheet, you know, given, as you highlighted, our already low net leverage.
Now, you know, we have talked about this, and I recognize that at a higher share price, accretion from buybacks is lower. But as we have demonstrated over the last decade, our disciplined approach has worked well, and we have had a return on share repurchases that is in excess of 20%. And, you know, even at a higher share price, buybacks are a better use of cash than the alternatives I have talked about, especially given the fact that we are talking about excess cash here.
On the dividend, obviously, we want to make sure, most importantly, that it is sustainable through the cycle. We also look at our dividend yield relative to our closest peers, and, you know, I think we are competitive there. And then we do want to show some, you know, some level of annual growth, but we are going to be prudent around that annual growth, again because we want to make sure that it is sustainable through the cycle.
So I think you can expect our actions to be consistent with all of that.
That is all very fair, and I appreciate the answer. My follow-up real quick—I hope maybe Gary could opine on this—but look, a month ago, diesel prices, gas oil prices in mid-June, were about 35% to 40% below where they are today. There are obviously—we all know what has been going on in the Middle East.
But then we got a Russian export ban, and then I am not actually quite sure where things stand right now, but we also then got a cessation of the restart of Chinese exports of products. One of your peers the other day talked about the black swan or the wildcard of if China came back into the market. So, Gary, I wonder if you could just walk through what your intelligence is telling us on those two dynamics because they seem to be pretty impactful to this near-term margin strength that we have seen just in the last couple of weeks.
Yes, Doug. I will start with China. We do not have a lot of insight into what is going on in China.
But what we can tell you is, despite the fact that they have raised their export quotas, our traders are not really seeing Chinese barrels leave the region. So we are not seeing a surge in Chinese exports. In terms of diesel prices, I think you alluded to Ukraine and its impact on Russian exports, and that certainly had an impact, as some locations in South America that were pulling Russian diesel have come to the U.S. Gulf Coast to pull diesel, which has caused prices to escalate.
I think the other thing that has happened is earlier in the year, you just saw such deep backwardation in the diesel market that it made export arbs difficult. We had high freight and steep backwardation, which made exports more challenging. And you had buyers who were wanting to sit on the market with the hopes they were going to be able to buy their resupply cheaper in the future.
As we get closer to heating oil season again, I think you see the buyers starting to come back into the market, realizing they need to buy in order to get inventories back in place before heating oil season hits. The combination of that with the further disruption in Russia is really what has caused the strength in diesel prices.
Great color, Gary. Thanks so much.
Thank you. Our next question comes from the line of Phillip Jungwirth with BMO Capital Markets. Please proceed with your question.
Thanks. Good morning. First-half turnaround CapEx ran about $374 million, which is pretty low relative to the $1 billion per year you have been averaging over 2025 and 2024.
I mean, it also looks like 3Q throughput guidance is going to be a bit higher than historical utilization. I know you talk about future turnarounds, but is there an ability to push some of these out? And then just what is driving the lower first-half spend to help frame a go-forward run rate?
Yeah. So I will start. You know, really no thought on our part in terms of delaying our maintenance.
We have a fairly steady spend on turnaround activity, and that will continue. We found that it really is important to execution to keep those dates kind of set. So nothing different there.
And in terms of the timing of spend, I think our guidance in terms of our CapEx will hold, and it may be a little lighter or heavier from one quarter to the next.
Okay. Great. And then there has been a lot of focus on mid-cycle cracks, historical averages.
I wanted to ask about it more from the standpoint of just how much above a 10-year average crack do you see the industry really needing to invest in meaningful capacity growth? Being a bit facetious here, but roughly how much above historical mid-cycle do you think is needed to support investment in a new refinery?
In terms of a new refinery, that number I do not have in front of me. You know, if you look at what the cost of some of this new capacity has been, it is very, very high. In terms of what we think it needs to be, I go back to this: I think we feel like hydroskimming capacity in Northwest Europe is needed to run in order to balance demand in the market.
And so mid-cycle margins will have to be sufficient to incentivize hydroskimming capacity in Europe to run.
Thanks.
Thank you. Our next question comes from the line of Paul Sankey with Sankey Research. Please proceed with your question.
Good morning, all. Homer, I appreciate that you are a CFO with a major problem of too much cash. If I could just ask a couple of questions, which are maybe more industry-oriented.
The first—you mentioned that feedstocks have been really a big driver between high product prices and feedstocks, I guess. And I was just wondering—one major impact has obviously been the SPR drawdown, which has fallen now from nearly 1.4 million barrels a day to more like 500,000. I just wondered—and I know this is not a Valero-specific issue, more of an industry observation—what your understanding is about how the SPR will continue to draw down from here.
And secondly, again, on the kind of industry observation note, and I know you will not comment on this either, Valero-specifically, the refineries in the U.S. obviously have been running exceptionally well, also with a surprisingly high jet fuel yield. I was just wondering what your expectations are for turnaround season for the industry, if we are going to have to start shutting stuff down more aggressively as we head into winter in a tight diesel market. Thanks.
Paul, it is Randy. I will start on the SPR question. I think back in March, when Trump announced the release, it was 172 million barrels from the U.S. SPR.
And we believe what has been committed and contracted so far is more like 130 million. So of that volume, we think there are around 40 million barrels left under that allocation. You know, there has been a lot of discussion on what actually constitutes a minimum.
There have been some numbers thrown around, whether it is 300 million or whether it is 70 million. 300 million sounds a bit high. 70 million sounds a little low to us, but right now, it is difficult for us to say kind of what the minimum volume may be that they can draw this thing down to.
Yeah. Not a lot of insight on the turnaround activity. You know, what we do see from the consultant data we have, it would show a little bit lighter turnaround season as we head into fall than is typical this year and a little heavier turnaround season next year.
Got it. Thanks.
Thank you. Our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt & Company. Please proceed with your question.
Thanks, and good morning. Do you see the RIN market short this year? And if so, could you talk about the implications for your various businesses?
If that were the case, it seems like RD profitability could be quite robust in the back half of the year. But then from the refining side, is there any concern that you would not be able to procure enough RINs to meet compliance in 2026?
Hey, this is Eric. So I will answer the first part. We do see the RIN market short, with the bank being hit somewhere between the end of this year and sometime in the middle of next year, given the pace we are at.
Everyone is looking at the June numbers, thinking, wow, those are exceptionally high. We should have no problem meeting it. Maybe.
What we see is you still had a lot of players that did not produce D4s in 1Q, waiting on the RVO release, which came out in April. So 2026, in particular, is going to be a low-production year versus the obligation, which means you will draw the bank. And so we see that as structurally keeping the D4 RIN high.
Yeah. Hi. This is Lane.
I think the only thing I would add is we have our own view on if and when the bank runs out. And obviously, the RIN is inside the crack. I do not think anybody knows what happens if it goes unfeasible, and it could.
I mean, at some point here, with the way the RVO is and the amount of production, that is a concern.
Got it. I mean, the only thing I would add is some of this is going to be driven, at least on the policy side, by the impact on consumers, right? So if you think about the way we think about it, the RIN is in the crack, and that ultimately gets pushed on to consumers.
And so it really becomes an affordability issue. Right? And so when and if the EPA takes action will really probably be driven by how much this actually impacts consumers.
Otherwise, I mean, we are well-positioned on it.
Sounds good. And then I think you mentioned that you are working on some ethanol expansions. Can you share any sort of numbers around that, either like percentage capacity growth or the million-gallon expansion number?
And then on the RD side, are you also looking at, like, small debottlenecking projects or any sort of RD expansions? Thank you.
Yes. So ethanol, we are looking at small debottlenecking projects to the extent of 100 million to 200 million gallons a year. That should all hit within the next year or two.
RD is a different outlook. I think given this constant conversation about where policy is going to be and how predictable policy is or is not right now, there is not a lot of intent on expanding anything in RD.
Great. Thank you.
Thank you. Our next question comes from the line of Connor Fitzpatrick with Bank of America. Please proceed with your question.
Hi, everybody. Thanks for taking my question. As mentioned earlier on the call, the RIN market is pretty short.
It is somewhat hard to get it to balance on paper just from domestic capacity. There might be some additional utilization to come from biodiesel and renewable diesel facilities. But probably the biggest swing source of supply from here is exports and imports into the U.S. So I was just wondering, what do you think is the biggest source of change for supply going forward?
In the event that we do balance the market soon, where do you think those incremental gallons will come from? Thanks.
Yes, this is Eric. I think one of the challenges that is different than previously is, before, you would have seen foreign imports pick up more quickly when you had the $1 blender’s tax credit. And so foreign imports came in to capture that dollar, and that was the tax benefit that was in place prior to last year.
What is different now with this RVO- and RIN-driven system is you have to be registered to generate RINs. And so a lot of these foreign importers are not registered to generate RINs. And so that will take an administrative step to do that.
You also have the elimination of all tax credit benefits for foreign imports. So the production tax credit does not give any benefit to imports. And with the recent announcements of additional tariffs, it just makes that hurdle more difficult.
So you have no tax benefit on foreign imports, plus this issue of it being RIN-driven now, not tax-driven. And so it is a different—think of it as a pathway—in order for foreign imports to get in. They eventually will because that will be needed to satisfy this RVO, but that is, I think, the main reason why we have not seen foreign imports pick up as rapidly as everyone expected.
Thanks. That is helpful.
Thank you. Our next question comes from the line of Jason Gabelman with TD Cowen. Please proceed with your question.
Yes. Hey, thanks for taking my questions. I want to start on Russia, and obviously, the disruptions there are benefiting the global product prices that we are seeing.
If I recall, the last time this happened in 2022 and 2023, Russian refineries came back, I think, a bit more quickly than what the market had anticipated. So do you have any sense of the extent of damage at these Russian plants and if they are going to be able to come back relatively quickly once the bombing stops, or if they will be down for an extended period of time?
Yes, Jason, this is Gary. The only thing I can tell you is, as you know, currently about 1.7 million to 1.9 million barrels a day of Russian capacity is offline. If you look at the trend from May to June to July, it has gotten progressively worse, not better.
And then what you hear is that Ukraine is now targeting critical pieces of equipment, whereas before they were targeting tanks. And so you can understand that, you know, you have a tank fire and you can recover quickly. However, if they are taking out pieces of critical equipment, it could take a lot longer.
So at least from what we read—we do not have any direct insight into this—but it would seem like it takes longer rather than shorter for them to recover.
Okay. Got it. My follow-up is on U.S. policy.
And the administration has done a number of things to try and reduce the cost that consumers are paying at the pump: Jones Act waivers, RVP waivers. Are there other kinds of levers that the administration has and, you know, anything incremental that you are hearing from them on a potential product export quota or ban? Thanks.
This is Richard. I will make an effort at answering that. I mean, we share the administration’s goal of trying to keep fuel affordable for Americans.
And as you guys know, there are a lot of issues impacting fuel prices right now. So we work with the administration closely to ensure that they understand the market dynamics and the impacts of all the various policy options they might be considering and make sure they are well understood. And we believe they are looking for the ones that are really viable and work.
And the Jones Act that you highlighted is actually a really critical one. I mean, that is, you know, a pretty strong Jones Act waiver commitment here from the administration, and it has kept the West Coast and the East Coast wet. And I think it has really maximized U.S. refining capacity out of the Gulf and allowed that to be shared with the other regions.
So I think that has probably been one of the most critical ones. There are other things that we are concerned about. There are the issues with the RVO and where the EPA will settle in on that.
There are a number of tax and tariff issues that have been kind of in place, particularly taxes on renewable feedstocks, where changes would certainly help to get more and quicker feedstocks in. The RVO is going to drive a lot of the price of gasoline. It already has.
And then these uplifts in cracks that are caused by these SREs and the misallocation and misalignment that come out of that are a problem. And so we are, you know, trying to make sure that they understand that those are not helping lower the price of fuel because they are increasing the price of fuel. And so we work with them closely, and I think they have a good, strong understanding, and they do want energy dominance.
Thanks for that. We have reached the end of the question-and-answer session. And therefore, we would like to turn the call back over to Mr. Donovan for closing remarks.
Yes. I just want to thank everyone for joining us today. And as always, feel free to contact our IR team if you have any questions.
Have a wonderful day.
Thank you. This concludes today’s conference. You may disconnect your lines at this time.
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