Valero Energy Corp (VLO) — Q2 2025 Earnings Call Transcript

Good morning, everyone, and welcome to Valero Energy Corporation's Second Quarter 2025 Earnings Conference Call. With me today are Lane Riggs, our Chairman, CEO and President; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and COO; Rich Walsh, our Executive Vice President and General Counsel; and several other members of Valero's senior management team. If you've not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted financial metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our earnings release and filings with the SEC. Now I'll turn the call over to Lane for opening remarks.

Thank you, Homer, and good morning, everyone. We are pleased to report solid financial results for the second quarter, driven by our strong operational and commercial execution. In fact, we set a record for refining throughput rate in our U.S. Gulf Coast region in the second quarter, demonstrating the benefits of our investments in growth and optimization projects. Refining margins were supported by strong product demand against the backdrop of low product inventory globally. In particular, early July U.S. diesel inventories and days of supply are at the lowest level for the month in almost 30 years. We continue to see strong demand with our quarterly diesel sales volumes up approximately 10% over the same period last year and gasoline sales about the same as last year. On the financial side, we continue to honor our commitment to shareholder returns with a payout ratio of 52% in the second quarter. And last week, we announced a quarterly cash dividend on our common stock of $1.13 per share. On the strategic front, we continue to progress the FCC unit optimization project at St. Charles that will enable the refinery to increase the yield of high-value products, including high-octane alkylate. The project is expected to cost $230 million in startup in 2026. Looking ahead, we remain optimistic on refining fundamentals with several planned refinery closures this year and limited announced capacity additions beyond 2025. Additionally, we expect our sour crude oil differentials to widen as OPEC+ and Canada continue to increase production during the third and fourth quarters. In closing, we remain committed to maintaining our track record of commercial and operational excellence, which has been the hallmark of our strategy for over a decade. And our commitment remains underpinned by a strong balance sheet that also provides us plenty of financial flexibility. So with that, Homer, I'll hand the call back to you.

Thanks, Lane. For the second quarter of 2025, net income attributable to Valero stockholders was $714 million or $2.28 per share compared to $880 million or $2.71 per share for the second quarter of 2024. The Refining segment reported $1.3 billion of operating income for the second quarter of 2025 compared to $1.2 billion for the second quarter of 2024. Refining throughput volumes in the second quarter of 2025 averaged 2.9 million barrels per day or 92% throughput capacity utilization. Refining cash operating expenses were $4.91 per barrel in the second quarter of 2025. The Renewable Diesel segment reported an operating loss of $79 million for the second quarter of 2025 compared to operating income of $112 million for the second quarter of 2024. Renewable diesel sales volumes averaged 2.7 million gallons per day in the second quarter of 2025. The Ethanol segment reported $54 million of operating income for the second quarter of 2025 compared to $105 million for the second quarter of 2024. Ethanol production volumes averaged 4.6 million gallons per day in the second quarter of 2025. For the second quarter of 2025, G&A expenses were $220 million, net interest expense was $141 million and income tax expense was $279 million. Depreciation and amortization expense was $814 million, which includes approximately $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia Refinery by the end of April 2026. Net cash provided by operating activities was $936 million in the second quarter of 2025. Included in this amount was a $325 million unfavorable impact from working capital and $86 million of adjusted net cash used in operating activities associated with the other joint venture member's share of DGD. Excluding these items, adjusted net cash provided by operating activities was $1.3 billion in the second quarter of 2025. Regarding investing activities, we made $407 million of capital investments in the second quarter of 2025, 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 members' share of DGD and other variable interest entities, capital investments attributable to Valero were $399 million in the second quarter of 2025. Moving to financing activities. We returned $695 million to our stockholders in the second quarter of 2025, of which $354 million was paid as dividends and $341 million was for the purchase of approximately 2.6 million shares of common stock, resulting in a payout ratio of 52% for the quarter. Year-to-date, we have returned over $1.3 billion through dividends and stock buybacks for a payout ratio of 60%. And as Lane mentioned, on July 17, we announced a quarterly cash dividend on common stock of $1.13 per share. With respect to our balance sheet, we repaid the outstanding principal balance of $251 million of 2.85% senior notes that matured in April. We ended the quarter with $8.4 billion of total debt, $2.3 billion of total finance lease obligations and $4.5 billion of cash and cash equivalents. The debt-to-capitalization ratio net of cash and cash equivalents was 19% as of June 30, 2025. And we ended the quarter well capitalized with $5.3 billion of available liquidity, excluding cash. Turning to guidance. We still expect capital investments attributable to Valero for 2025 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts, regulatory compliance and joint venture investments. About $1.6 billion of that is allocated to sustaining the business and the balance to growth. For modeling our third quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.76 million to 1.81 million barrels per day; Mid-Continent at 430,000 to 450,000 barrels per day; West Coast at 240,000 to 260,000 barrels per day; and North Atlantic at 465,000 to 485,000 barrels per day. We expect refining cash operating expenses in the third quarter to be approximately $4.80 per barrel. With respect to the Renewable Diesel segment, we still expect sales volumes to be approximately 1.1 billion gallons in 2025, reflecting lower production volumes due to economics. Operating expenses in 2025 should be $0.53 per gallon, which includes $0.24 per gallon for noncash costs such as depreciation and amortization. Our Ethanol segment is expected to produce 4.6 million gallons per day in the third quarter. Operating expenses should average $0.40 per gallon, which includes $0.05 per gallon for noncash costs such as depreciation and amortization. For the third quarter, net interest expense should be about $135 million. Total depreciation and amortization expense in the third quarter should be approximately $810 million, which includes approximately $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia Refinery by the end of April 2026. We expect this incremental depreciation related to the Benicia Refinery to be included in D&A for the next three quarters, resulting in a quarterly earnings impact of approximately $0.25 per share based on current shares outstanding. For 2025, we still expect G&A expenses to be approximately $985 million. That concludes our opening remarks.

Now that we are halfway through the summer driving season, how is refined product demand trending across your footprint? Maybe just unpack some of Lane's opening remarks about sales across your system. Are there any noticeable patterns or shifts? And additionally, what kind of signals are you observing in the export market?

Theresa, it's Gary. Overall, I'd tell you the fundamentals around refining continue to look very supportive. Total light product inventory remains below the 5-year average range, below where we were last year at this time. And demand for transportation fuels remains robust, not only here in the U.S., but also in our typical export markets. Our view is gasoline demand is relatively flat compared to last year. It looks like vehicle miles traveled are up slightly year-over-year, but probably only up enough to offset efficiency gains in the automotive fleet, not up enough to really create incremental demand. If you look at our wholesale volumes, they would also indicate flat year-over-year gasoline demand. In addition to relatively strong gasoline demand domestically, we've also seen good export demand to Latin America. And then on the supply side, the transatlantic arb to ship gasoline from Europe to the United States has been closed for much of the year. So when you combine relatively good demand with less supply coming from Europe, you would expect inventory to be a little lower than last year, and that's what we saw in the second quarter. So those factors ultimately resulted in a little stronger gasoline margin environment this year compared to last. Going forward, the transatlantic arb is marginally open. So supply seems adequate to meet demand. We're kind of getting to the end of driving season. We'll start RVP transition in some regions soon. So it's hard to see a lot of support for gasoline cracks moving forward. Absent some type of supply disruption, we'd expect gasoline cracks to follow typical seasonal patterns and remain around mid-cycle levels through the end of the year. Distillate, the story is much different, though. Where gasoline demand is expected to fall off some, we expect distillate demand to pick up. First, we'll start to get into harvest season, see agricultural demand pick up, and then we'll transition to heating oil season. Overall, diesel demand has continued to trend above last year's level, really strong demand in the first quarter due to colder weather and then increased demand for refinery-produced diesel with less imports of bio and renewable diesel. In our system, diesel sales are currently trending about 3% above last year's level. Again, while domestic demand has been good, we see a strong pull of U.S. Gulf Coast distillate into the export markets. The exports have kept inventory down near historical lows during a time where restocking typically occurs. We have seen diesel inventory gain in the last couple of weeks, but really that's just a result of an incredibly strong export market in early June. As exports got really strong, freight rates spiked, and so it closed some of those export arbs. Freight rates have come back off, so the arbs are open to export both to Latin America and Europe. With those arbs open, it's difficult to see how we get the normal build in diesel inventory that occurs in the third quarter. So diesel cracks have been strong with low inventory. We expect diesel cracks to remain strong heading into hurricane season. If we have some type of supply disruption, I think you'll see a pretty significant market reaction with inventories as low as they are.

And what is your near to medium-term outlook for light-heavy differentials, taking into account the tailwind from incremental OPEC+ barrels coming to market, but also considering potential headwinds from AMEX production volatility, the unavailability of Venezuelan barrels, GOM crude quality issues and so on. How do you think these factors play out?

Yes. Thus far, year-to-date, I think the quality differentials have certainly been a headwind for us. We thought coming into the year, you'd see less demand with Lyondell going down, but that was kind of offset. The Venezuelan sanctions pulled about 200,000 barrels a day out of the U.S. Gulf Coast market. You had the wildfires that took about 5 million barrels of June supply off the market. But going forward, we do think things will get better. It will probably be the fourth quarter before you really see that. Canadian production has not only recovered from the wildfires but it continues to grow. Then as you mentioned, OPEC unwinding their 1.9 million barrels a day of cuts by August. Really, it appears that much of the ramp-up in the OPEC production we haven't seen on the market yet so far because there was crude oil burn in the region for seasonal power demand. As we move out of summer, more of those barrels will make their way to the market. And then early summer tensions in the Middle East also caused some countries to front-end load fuel oil purchases that they use for power demand also. Again, that will unwind fuel oil coming back off to the market. As fuel oil comes back, that will support wider differentials as well. Additionally, in the fourth quarter with turnaround activity, you should see less demand for those barrels. So all of those should really contribute to wider differentials in the fourth quarter. I think the only unknown here is really what happens with the Russian sanctions. Thus far, we haven't really seen much of an impact. But if the sanctions are effective and cut some of the Russian barrels, that would obviously be bearish for the differentials.

Team, just wanted to understand what's your outlook for the net capacity additions for the remaining part of this year and for 2026. Are you still seeing major capacity additions globally? Or do you think those things are slowing down and given the demand growth, we should be better positioned going ahead, if you could talk about that?

Yes, Manav, this is Gary. I think definitely, when we look out on the horizon, there's not a lot of new capacity coming online, and a lot of what new capacity there is, is really more geared towards petrochemical production rather than making transportation fuels. If we look at next year, it looks like just over 400,000 barrels a day of new refining capacity coming online. Initially, most consultants were forecasting around 800,000 barrels a day of total light product demand growth, which would have indicated significant tightening starting next year. With some of the economic uncertainty, especially around tariffs, forecasts have fallen off to where a lot of people are only forecasting around 400,000 barrels a day total light product demand growth. And then a lot of consultants are showing a lot of that demand growth being filled by a step change in renewable production. I'm confident we'll see tighter supply-demand balances. The question really is when does this occur? Is it next year? Or do we actually see some type of economic activity slowdown, and it isn't until 2027 that things really start to get tight? Thus far, our view is the economy has been fairly resilient. Demand for transportation fuels has remained strong. So I guess I'm a little more optimistic about the economy, and we'll have to see with all the uncertainty on renewables, whether we see a ramp-up in renewable production or not. The other big factor in all this is will we see additional refinery rationalization. Although some refinery closures have been announced, certainly, the recent announcement around the Lindsey Refinery in the U.K. was fairly unexpected. It's hard to believe there aren't others facing a similar situation with other refinery closures too. Things could really tighten up a lot faster. But the big driver here is really what happens to the economy, and you're probably in a better position to assess that than I am.

A quick follow-up is I was looking at your Gulf Coast capture. Now that's where heavy light narrowness should hit the capture the hardest, but the capture actually was over 92%. And I'm trying to understand a few dynamics, what allows you to deliver such a strong capture. And then coming back to the first question, if heavy lights do widen out, should we expect a tailwind to the Gulf Coast capture because the way your benchmark is constructed, those do not get reflected in the benchmark. So if you could talk about that.

Yes, Manav, this is Greg. So I think you hit on some of the points related to heavy light and capture. Because we do include heavy grades in our reference for the Gulf Coast. So as those move out and contract, that's picked up in the reference crack that we use. So not as big of an impact on the capture rate because it's built into the indicator margin that we use. On our performance in the second quarter, a lot of the improvement was driven by really strong operating performance coming out of the heavy maintenance we had in the first quarter. And that was really highlighted, if you remember, by Lane's comment about record quarterly throughput in that region. So good operating performance. We had strong commercial performance as well in that region, particularly on the product side, good exports, great wholesale performance in that part of our business as well. So those were the primary drivers for the Gulf Coast in the second quarter. And again, as those crude differentials widen out, to the extent that they're in the indicator that we use, it's probably not as much of a factor when you think about the capture rate relative to our indicator.

I want to spend some time discussing the return of capital. You returned $633 million in the second quarter with a payout of over 70%. Can you share your thoughts on the sustainability of capital returns and how we should be considering the buyback in the latter half of the year?

Yes, Neil, it's Homer. I mean maybe I'll just start with just the framework around buybacks, right? It's guided by a number of things. Obviously, first and foremost, we've got our stated minimum commitment to an annual payout of 40% to 50% of adjusted cash flow, right? And so you should continue to consider that as nondiscretionary. We'll honor that in any sort of environment. Then we've got our target minimum cash position of $4 billion to $5 billion, and we're right at the midpoint there. So we're not looking to build more cash, right? As a result of that, consistent with what we've been saying for quite some time, we'll continue to use all excess free cash flow to buy back shares. And as you highlighted, the second quarter resulted in a payout of 52%. Keep in mind, though, that we also used $251 million towards the notes that matured in April in addition to $325 million that was consumed by working capital, right? Looking forward, with the balance sheet where it is and discipline around capital investments, I think you can continue to expect us to maintain this posture where all excess free cash is aimed at share buybacks. Longer term, I mean, I don't know if you have the investor deck handy, but we've got a slide in there. I think it's Slide 11 that puts all of this into context, actually reflecting our actual results. So if you look at the last 10-year period through 2024, total cash flow from operations was around $61 billion, and that includes changes in working capital, which is roughly $6 billion a year. If you think about run rate CapEx, right, $2 billion to $2.5 billion, so $2.25 billion at the midpoint with $1.5 billion sustaining and then $500 million to $1 billion of growth. And layer on top, you've got $1.4 billion or so to fund the dividend, right? So $6 billion of annual cash flow from operations, $2.5 billion CapEx, $1.4 billion to dividend, that leaves over $2.3 billion for buybacks based on our actual results over the past 10 years. Hopefully, that gives you some context.

Really helpful, Homer. Just the follow-up is around DGD. Obviously, a lot of moving pieces and appears to be pretty tough, if not trough conditions. What's the path back to mid-cycle here? How do you think about the evolution of this business? And can you talk about your commitment to it?

Neil, this is Eric. You've mentioned that there’s a lot of uncertainty and lack of clarity in policies right now. The key to this situation will depend on what the EPA announces after their comment period ends on August 8. Their decisions regarding the Renewable Volume Obligation and Small Refinery Exemptions, as well as any reallocations, will influence the D4 RIN market and hopefully guide the reactions of other markets in relation to the D4 RIN. We observe that the LCFS market in California is gradually increasing following their 9% obligation increase that took effect on July 1. Europe is maintaining its mandate for a 2% SAF requirement, and Canada is moving forward with its Clean Fuel Regulation. So, long-term, there’s still significant demand in this segment. The main issue is when the prices for these credits will begin to rise. We are already noticing the D4 RIN price increasing and beginning to diverge from the D6. The critical point will be when fat prices start to adjust in response to these clarified policies. Once fat prices start to separate, we anticipate that margins for DGD will widen, leading to increased demand for DGD and renewables in the coming policy years.

I think I need to revisit Refining school because your distillate yields compared to your light sweet crude throughput are putting us in a tough spot. Can you help clarify what's happening? Margins for heating were better than gas for most of Q2. Since 2024, your light crude input has been about 10% higher, and your distillate yield has also increased significantly. It's a great outcome, but could you explain what's driving these results? I have a quick follow-up for Eric.

Yes, Doug, this is Greg. So I would tell you, it's pretty simple. We've been, for the most part, in that period in max distillate production mode. So when you think about how we're adjusting the operation, we're maximizing the yield of jet fuel and diesel fuel. So even though you've got a crude slate that might be a bit lighter, we can do some adjusting within the downstream operation to try to make sure we get all the distillate molecules into that pool that we can. And we've been pretty successful and effective at doing that in that time frame.

Sorry for the Part B here, but would I assume that that's part of the reason why your capture is doing so well?

Certainly helps it. Certainly, it helped when you've got that strong distillate crack and then you're maximizing that yield, that certainly will have a positive impact on capture.

So Eric, I wanted to follow up on the earlier question, if you don't mind, just on renewable diesel. I see if you can dumb it down for us, when you roll everything together, and you guys are obviously the lowest cost producer with the best feedstock setup. Do you see DGD net to Valero as free cash flow positive on a sustainable basis?

I think the answer to that is yes. Like I said, but it's going to take a little bit of clarity on what the EPA is going to do with RINs because the numbers they're talking about doing will put a positive tailwind into DGD's production. And so to your point, we still have the best market access, both from a feedstock standpoint, a certification of products and access to all the different markets. And it's still a low CI game. I think one of the things that everyone needs to keep in front of them is that Europe and the U.K. really only accept waste oil, low CI feedstocks, certified feedstocks. So as much as there's been a lot of talk about the support of domestic production and soybean oil and Canada's canola oil, those are not acceptable feedstocks to most of the customers that are really interested in lowering their carbon footprint. And so we're still the most advantaged from a feedstock standpoint. I think once you start to see these credit prices move, and like I said, we have seen LCFS and RIN prices moving higher, those factors and credit prices will continue to make DGD an advantaged platform. And long-term, it will be a positive cash flow into Valero.

If you can't make money, nobody can in this business. I appreciate the time.

Eric, could you provide an update on your SAF operations? It appears that things have been progressing well. Since you are about 8 or 9 months past the startup of the conversion and expansion, could you share what you've observed so far? Specifically, have there been any surprises or things that have aligned with your expectations regarding the geographic demand mix, pricing, and how the market is changing?

Yes, thank you. One significant operational discovery that pleasantly surprised us was how effectively our unit produced and blended SAF. Before we began operations, we heard from others that making and blending SAF was quite challenging, along with meeting certification requirements and logistical demands. However, with DGD's equipment, the expertise of our project start-up team, and the overall design of our project, we've demonstrated considerable capability in SAF production as well as in the transition from SAF to traditional RD. Overall, this has been a positive operational experience. The logistics and blendability are working well, and we’ve efficiently moved this product through the Valero jet fuel system. If there's any downside, it's that we anticipated greater interest in this product, particularly from airlines. The market seems to still be in a phase of exploration; however, we are witnessing increasing interest in sales, especially with mandates in the EU and the U.K. It's possible that they under-purchased in the first half of the year and may aim to meet their 2% blending target in the latter half. Therefore, we could see an uptick in sales as they approach their end-of-year compliance deadline. The demand for this market is continually growing, and so is the interest in the voluntary credits related to SAF, albeit these represent small volumes. Many are investigating this as a means to streamline their carbon offset plans by sourcing directly from DGD, indicating significant potential for growth. The project's returns are still aligning with our target thresholds, and credit prices have been favorable in supporting product production. Furthermore, despite recent changes in the reconciliation bill that equalize the benefits of SAF to RD, we still observe market premiums for SAF relative to RD from the customers’ perspective as everyone adapts to the modifications in the PTC.

Great. And then maybe a question for you, Lane. Sorry to ask, but I mean, there are reports that the California government envisions themselves kind of brokering a sale of the Benicia Refinery. Any comments or any thoughts on anything that could potentially change that would change your mind to close that asset next year?

This is Rich Walsh. First, we don't respond to speculation in media reports along those lines. And nothing has changed in our plans regarding Benicia right now. But look, there's been a lot of public discussion about reforming the market and in particular, the regulatory environment in California to head off refinery closures. I think you guys all know the CEC has been tasked with evaluating refinery capacity on behalf of the state. And I think they're working very hard to see what, if anything, they can do. And for our part, we've been in discussions with the CEC and other elected officials and policy officials regarding Benicia's future. And I think there's a genuine desire for them to avoid the refinery closure, but there's no solutions that have materialized, at least not from our perspective.

The question that as Saudi is putting more barrels in the market, I assume there's going to be more of the medium sour grade like the ever medium. I'm wondering that how you think it's going to impact on the global distillate yield as more of the medium sour is available? That's the first question.

Paul, it's Greg. Yes. So obviously, right, those grades have more distillate typically in them than some of the lighter grades. So as we see those come into the market, you would expect that to have a positive impact on distillate yield overall. And as a result, distillate production would work up a bit. I don't have a good feel for the exact numbers for that. But there's no doubt that those are grades that are more rich in distillate than most of the other crudes that we have run in their place over the last few years.

Greg, I understand it’s difficult to provide a precise figure, but do you have any insights on whether there might be a 2% increase, 5%, or anything similar that you could share?

Yes, Paul, I don't have those numbers off the top of my head. I'm sure you can contact Homer, and we can talk about that more offline. But I don't remember the numbers off the top of my head.

But this is Lane. I think it's important to consider the markets where diesel is being supplied and the specifications, such as high cetane or ultra-low sulfur diesel. In a global context, you need to assess whether there is available capacity for the premium markets versus how the increasing production of sour and heavy grades of diesel may simply end up in the marine market. This is something to keep in mind when thinking about it.

Okay. Great. The second question, I think, is for Eric. Eric, I mean, with the PTC and everything that is more in favor of domestic production and also keeping in the local market, I assume. So is that still economic for us to export RD from DGD? I know that previously you guys export quite a lot to Europe. So are those still economic or is the economic now saying that it's going to be majority of the RD production will be staying local?

Yes, I believe that the markets in Canada, the EU, the U.K., and California remain appealing for foreign feedstocks. The issue we face is that much of this is still driven by news trends. As the EPA discusses its actions regarding the RIN, we observe that most fat prices are aligned with the D4 RIN. Although fat prices have risen, credit prices are gradually increasing but have not yet diverged to account for the effects of various policy changes, such as the lower PTC, half RIN in the RVO, and the tariffs imposed on foreign feedstocks. Eventually, these markets will need to adjust. As policies are finalized, we will see a necessary reflection of foreign feedstock prices compared to domestic prices to continue meeting demand in those markets. As I mentioned earlier, it's still focused on low CI, and many customers prefer not to use vegetable oil as their feedstock. While we anticipate an increase in the RIN and support for vegetable feedstocks, the LCFS markets will still prioritize low CI feedstocks. Therefore, adjustments in the market will be required. We are beginning to see some price movements, but it may take time for credit prices to rise due to the existing credit banks for both RINs and LCFS. As those banks are gradually depleted, credit prices will increase, leading to a disconnection between foreign and domestic feedstocks. Both need to separate from the D4 RIN for production to increase, especially for many vegetable oil biodiesel producers; if soybean oil and the D4 RIN remain linked, margins will be insufficient. The actions from the EPA regarding RVO and SREs will ultimately set the stage for when we see increases in biodiesel and renewable diesel production.

Eric, can we confirm what percentage of your DGD, RD is currently exported to Europe and Canada?

Yes. We're not going to share that level of detail, Paul, but we are the largest exporter and really one of the largest producers of SAF. And so we're definitely maxing out what we can sell into those markets. But yes, that will always shift around based on feedstock prices and credit prices.

Can you hear me?

We can hear you, yes.

We've had good high levels of throughput in U.S. refining this year despite the shutdowns. Can you just talk a little bit about that? It's been fairly steady and very high. And I just wondered what the components of that were as well as the outlook for the second half in your view, perhaps ignoring hurricane risk and stuff, but just the general turnaround outlook for the second half. And the follow-up is a very interesting moment in history with the U.S. becoming a net exporter to Nigeria. Could you just talk a little bit about the impact of Nigerian refining on Atlantic Basin markets? Interesting stuff.

Paul, it's Greg. I think I'll address the first question. Could you please repeat your inquiry? What specific aspect are you inquiring about?

The system is going to shut down at Lyondell, and we've observed $17.5 million of throughputs in U.S. refining, which seems quite high. This number has remained very steady. It's a positive development, but I'm curious why it's holding so high from both your viewpoint and the industry's perspective. Additionally, I'm interested in the second half turnarounds and whether we can maintain this level of throughput.

Right. Okay. Yes, I think throughput has been real strong, particularly in the Gulf Coast, probably a good indication of people coming out of turnaround and running well. One of the things we look at a lot of times is it's been a relatively mild summer weather-wise, which a lot of times, as you get hotter and hotter, you start to hit some limitations operationally at lower rates. And so we haven't seen that. I think you've been able to see the industry hold at pretty strong performance. Obviously, not a lot of things have been breaking. So that keeps utilization up. And as we get to later parts of the summer, we'll see if warmer weather starts to creep in and we start to see some of those rates tail off. As far as turnarounds in the third quarter, it's always hard to see where the industry goes. I don't think we have any unique insight into that relative to what you can read elsewhere. But it looks like today, turnarounds are probably pegged to be a little bit below average. What we typically see, though, as we get closer, more work starts to get known and identified in the plant. So we'll see where that ultimately lands. And I think probably you want to take the other half, Gary?

Yes. In Nigeria, there has been significant media attention on the difficulties the Dangote Refinery has faced in operating their resid FCC. They are currently running WTI and continue to market atmospheric tower bottoms, indicating that the resid FCC is not functioning properly. As a result, they are likely pushing towards the lightest feedstock available since they lack the capability for resid destruction. Once they resolve the issues with the resid FCC, we would expect them to shift towards a heavier feedstock and utilize more Nigerian crude grades.

So they're still sucking in gasoline then?

Yes.

Doug Leggate got me thinking about the school of refining. I think it's the school of refining hard knocks, right?

You mentioned in the earlier commentary, gasoline demand being flat despite vehicle mileage being up. Not a new story here, but wondering if there's been any shift in your medium-term outlook for efficiency gains in light vehicle fleet, given consumer preference or government policy incentives. And any reason we could see a slowdown in gains here?

I think it's definitely a potential. You should see less EV penetration than what we have been seeing. Overall, though, the bigger impact in our models has always been kind of the impact of the CAFE standards and vehicles becoming more efficient. And we don't see that changing drastically going forward.

Okay. Great. And then we're all familiar with the affordability conversation in California and the state's tone towards shifting to ensure supply. I know you just have Pembroke in the U.K., but wondering what does the affordability or supply conversation looks like here or in broader Europe, given we continue to see closures here too. And you mentioned the Lindsey bankruptcy earlier. Really just trying to think about it in terms of the competitive dynamic, given I know you don't have a huge footprint here.

The U.K. is a net importer of diesel, so the closure of the Lindsey Refinery likely won't have a significant impact because diesel prices are primarily determined by import parity. However, it seems that Lindsey produced around 50,000 barrels a day of gasoline, with approximately 60% of that supply remaining in the U.K. For our Pembroke asset, some of our most profitable barrels are those sold in the local market. As Lindsey exits, we plan to fill that gap, which will reduce the availability of exports to markets like California.

Eric, I want to revisit the results from RD in the second quarter. Although they faced challenges, there was an improvement compared to the previous quarter. Can you elaborate on the factors contributing to this? I understand the indicator was lower, but it seems that was balanced out by a higher recognition of the PTC and the ongoing increase in SAF sales. I would appreciate your insights on this.

In the first quarter, we experienced a few outages on DGD 1 and DGD 2 due to catalyst changes. This resulted in improved volume during the second quarter. Additionally, we had a full quarter of PTC capture on eligible feedstocks compared to the first quarter, where we adjusted our operations to start capturing PTC around mid-February, resulting in only about half a quarter of capture. The second quarter benefited from full PTC capture for the eligible feedstocks and our SAF, leading to significantly increased income. However, we are still adapting to the changing tariffs, but we see ongoing improvement from quarter to quarter. As credit prices continue to rise, I am optimistic that we will maintain this positive trend into the third quarter and throughout the rest of the year.

Great. And then with the passage of the tax bill a couple of weeks ago, can you talk to any benefits to Valero that we should be mindful of, anything around bonus depreciation?

Yes. Joe, it's Homer. So the reinstatement of full expensing should lower our overall cash tax liability in earlier years versus the typical makers depreciation schedule. So growth CapEx should definitely be eligible for bonus depreciation. A lot of our sustaining CapEx should also be eligible with the exception of turnaround capital, which we already expensed. The magnitude of the benefit obviously depends on our CapEx going forward, but that would be one, at least from a tax standpoint, benefit. Rich can talk about some of the other stuff.

Yes, the federal EV tax credits are being eliminated, and there are also limitations on the CAFE penalty for vehicles. This allows manufacturers to focus on meeting consumer demands, which typically lean towards larger vehicles, placing internal combustion engines on a more equal playing field with electric vehicles. Consequently, there will be less pressure to reduce fuel economy, and we anticipate that this legislation will lead to positive outcomes in the coming years.

We saw the results in the North Atlantic were pretty strong and definitely better than our expectations. I think capture moved up quarter-over-quarter despite tighter Syncrude dips and the Pembroke turnaround. So could you talk about what helped you out in the North Atlantic in Q2?

Yes, this is Greg. We experienced a significant amount of maintenance in the second quarter, which affected our throughput. This is reflected in the lower throughput figures for the quarter, though capture remained relatively stable. Additionally, as we mentioned concerning the Gulf Coast, we saw very strong commercial margins and contributions in that area, which resulted in consistent performance compared to the previous quarter.

Turnaround in Quebec, right?

Turnaround was in Quebec. Yes, Pembroke ran well, actually, kind of it's a theme for our system. Our operations really was strong across the system, including North Atlantic.

Sounds good. And then the RVO proposal, it has this potential SRE reallocation where the larger refineries would have to essentially pay for the SREs granted to the smaller refineries. It seems like it could be an extra hundreds of millions for Valero if that goes through. So I guess, one, how likely do you think that proposal would be to actually be in the final proposal? And then two, it's generally accepted that the RVO is passed along in the crack. Do you think that the extra reallocation costs would also be passed along in the crack as well?

Yes. This is Rich Walsh. Let me take an effort to respond to that. I think without getting too deep into this, I think you need to understand the SREs were originally coming out of an exemption that was expired in 2011. And following that expiration, the Department of Energy was obligated to look at whether or not these SREs were necessary because the RFS was creating disproportionate harm or impact to the small refiners and the DOE concluded that it was not impacting small refiners. So today, what we're talking about is extensions from a 2011 exemption, and it requires that these small refiners show a unique and disproportionate economic harm caused by the RFS itself. And like what you're alluding to here, in today's market, the RIN obligation is equally applied across the whole sector, and it's embedded in all the refinery margins. So I think EPA and DOE have repeatedly confirmed this with their own analysis. So while the EPA can't categorically deny all SREs, I believe it's going to be really challenging for these small refiners to make their legal case for the is uniquely harming them. So my thought process is that you're not going to see a lot of SREs be granted by EPA or at least if you do, you're going to see a lot of legal challenges to that. And in terms of the RVO, I mean, remember that the RVO came out and right after it came out, there were a whole bunch of changes that happened. We had tariffs. We had restrictions on foreign feedstocks, RINs for foreign imports having to be cut in half. So I think you're going to see a lot of comments coming in, in the proposed process. And I think EPA is going to have to look really hard at the RVO and have to think about what they got to do to revise it to make it realistic. And so I think those are the things that will kind of play out.

I wanted to go back to the commentary that you provided on the distillate outlook, and I appreciate all of the discussion around North American dynamics. But it seems like some of the output from other regions is a bit lower. And I wanted to get your thoughts on to the extent that that's transitory in nature, things like lower net exports out of Spain because of the power outages. It seems like Middle East diesel exports are down a lot. Not sure if that is structural or not. So just wondering if you could provide your thoughts on things going on in other parts of the world.

Yes, Jason, this is Gary. I think, obviously, the strength in diesel is due to low inventories. In July, we've been trending at historic low-type inventories. And I would say a lot of that really started late last year. Late last year, we had a relatively weak refinery margin environment. Based on where inventories were, I would say that the margin environment was too weak. And that led to lower refinery utilization, which limited diesel inventories from restocking as they typically do. Then we had a colder winter, which raised heating oil demand and further depleted inventory heading into the first quarter. We have had some refinery shutdowns and then some of the new capacity that has come online has really struggled to come up to full rate. So I think supply-demand balances are certainly tighter than expectations based on projected net capacity additions. A shift we've had in 2024, as jet demand increased, it's incentivized refiners to produce jet, which has come at the expense of diesel. In general, one of the things we've been talking about is refiners are running lighter crude diets. That was exacerbated by the Venezuelan sanctions and Canadian wildfires. So with tight quality differentials, the incentive to run lighter crudes results in lower distillate yields. And then another factor here is with the poor renewable and biodiesel margins, they've resulted in lower production of those products, which has increased the demand for conventional diesel as well. So I think all those factors have come into play where we are on the low inventories today.

Okay. And then my other one, I'm going to ask something else that's already been asked, but a bit more specific on the crude quality differentials that you expect to widen out with OPEC adding barrels. And I guess there's been some reporting recently that China wants to stockpile crude inventories in the back half of the year and OPEC tends to price things more attractively to Asian markets than to U.S. markets. So how much of these Middle East barrels do you think will flow to North America and really influence crude quality dips in the back half of the year?

Well, Jason, I can't say we have a lot of insight into what's going on in China. So I don't know their plans in terms of restocking inventory. I can tell you that we really haven't been buying much crude from historic partners in the Middle East for quite some time, but we have reengaged with them. So the fact that they're reengaging with us tells me that they plan on some of the production making its way to the U.S. So I'm confident we will see some of those barrels.

Thank you, Donna. Appreciate everyone joining us today. As always, please feel free to contact the IR team if you have any additional questions. Thanks again, and have a great day, everyone.