Valero Energy Corporation (NYSE:VLO) Q3 2024 Earnings Call Transcript

Valero Energy Corporation (NYSE:VLO) Q3 2024 Earnings Call Transcript October 24, 2024

Valero Energy Corporation beats earnings expectations. Reported EPS is $1.14, expectations were $0.982.

Operator: Greetings, and welcome to Valero Energy Corp. Third Quarter 2024 Earnings Conference Call. [Operator Instructions]. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Homer Bhullar, Vice President, Investor Relations and Finance. Thank you. You may begin.

Homer Bhullar: Good morning, everyone, and welcome to Valero Energy Corporation’s Third Quarter 2024 Earnings Conference Call. With me today are Lane Riggs, our CEO and President; Jason Fraser, our Executive Vice President and CFO, and Gary Simmons, our Executive Vice President and COO; and several other members of Valero’s senior management team. If you have 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.

Lane Riggs: Thank you, Homer, and good morning, everyone. Our third quarter results reflect a period of heavy maintenance in our refining segment during a relatively weak margin environment. Our refineries operated at 90% throughput capacity utilization in line with our guidance for the quarter. Product demand across the system remained strong with our U.S. wholesale volumes exceeding 1 million barrels per day for the second consecutive quarter. On the strategic front, we remain committed to executing projects that continue to enhance the earnings capability of our business and expand our long-term competitive advantage. I’m proud to report that the Diamond Green Diesel Sustainable Aviation Fuel or SAF project is now mechanically complete and is in the process of starting up.

The project was completed on schedule and under budget and is a testament to the strength of our projects and operations teams. On the financial side, we continue to honor our commitment to shareholder returns with a strong payout ratio of 84% for the quarter and the year-to-date payout of 81%. Looking ahead, improving diesel demand against the backdrop of low light product inventories should support refining margins. Increases in OPEC plus crude supply should widen our sour crude oil differentials and further increase margins. And longer term, we expect product demand to exceed supply with the announced refinery shutdowns next year and limited capacity additions beyond 2025, supporting long-term refining fundamentals. In closing, our focus on operational excellence, capital discipline and honoring our commitment to shareholder returns have served us well and will continue to anchor our strategy going forward.

So with that, Homer, I’ll hand the call back to you.

Homer Bhullar: Thanks, Lane. For the third quarter of 2024, net income attributable to Valero stockholders was $364 million or $1.14 per share compared to $2.6 billion or $7.49 per share for the third quarter of 2023. The refining segment reported $565 million of operating income for the third quarter of 2024 compared to $3.4 billion for the third quarter of 2023. Refining throughput volumes in the third quarter of 2024 averaged 2.9 million barrels per day or 90% throughput capacity utilization. Refining cash operating expenses are $4.73 per barrel in the third quarter of 2024. Renewable Diesel segment operating income was $35 million for the third quarter of 2024 compared to $123 million for the third quarter of 2023. Renewable diesel sales volumes averaged 3.5 million gallons per day in the third quarter of 2024, which was 552,000 gallons per day higher than the third quarter of 2023.

The ethanol segment reported $153 million of operating income for the third quarter of 2024 compared to $197 million for the third quarter of 2023. Ethanol production volumes averaged 4.6 million gallons per day in the third quarter of 2024, which was 255,000 gallons per day higher than the third quarter of 2023. For the third quarter of 2024, G&A expenses were $234 million, net interest expense was $141 million, depreciation and amortization expense was $685 million and income tax expense was $96 million. The effective tax rate was 20%. Net cash provided by operating activities was $1.3 billion in the third quarter of 2024. Included in this amount was $166 million favorable change in working capital and $47 million of adjusted net cash provided by operating activities associated with the other joint venture member share of DGD.

Excluding these items, adjusted net cash provided by operating activities was $1.1 billion in the third quarter of 2024. Regarding investing activities, we made $429 million of capital investments in the third quarter of 2024, of which $338 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance and the balance was for growing the business. Excluding capital investments attributable to the other joint venture member share of DGD and other variable interest entities, capital investments attributable to Valero were $394 million in the third quarter of 2024. Moving to financing activities. We returned $907 million to our stockholders in the third quarter of 2024, of which $342 million was paid as dividends and $565 million was for the purchase of approximately 3.8 million shares of common stock, resulting in a payout ratio of 84% for the quarter.

Year-to-date, we have returned $3.7 billion to our stockholders in the form of dividends and buybacks, resulting in a payout ratio of 81%, well above our long-term minimum commitment of 40% to 50%. In fact, since the start of 2021, our total cash flows from operations have exceeded our total uses of cash over this period, including capital investments over $4 billion of debt reduction and over $18 billion returned to stockholders through dividends and share buybacks. With respect to our balance sheet, we ended the quarter with $8.4 billion of total debt, $2.5 billion of finance lease obligations and $5.2 billion of cash and cash equivalents. The debt-to-capitalization ratio, net of cash and cash equivalents was 17% as of September 30, 2024, 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 2024 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 with approximately half of the growth capital towards our low carbon fuels businesses and half towards refining projects. For modeling our fourth quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.83 million to 1.88 million barrels per day Mid-Continent at 425,000 to 445,000 barrels per day; West Coast at 230,000 to 250,000 barrels per day; and North Atlantic at 380,000 to 400,000 barrels per day.

We expect refining cash operating expenses in the fourth quarter to be approximately $4.60 per barrel. With respect to the renewable diesel segment, we still expect sales volumes to be approximately 1.2 billion gallons in 2024. Operating expenses in 2024 should be $0.45 per gallon, which includes $0.18 per gallon for noncash costs such as depreciation and amortization. Our ethanol segment is expected to produce 4.7 million gallons per day in the fourth quarter. Operating expenses should average $0.37 per gallon, which includes $0.05 per gallon for noncash costs such as depreciation and amortization. For the fourth quarter, net interest expense should be about $140 million and total depreciation and amortization expense should be approximately $690 million.

For 2024, we expect G&A expenses to be approximately $975 million. That concludes our opening remarks. Before we open the call to questions, please 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 your questions.

Q&A Session

Operator: [Operator Instructions]. Today’s first question is coming from Manav Gupta of UBS.

Manav Gupta: My first question here is, can you talk a little bit about the demand for key products and how that is trending as we are coming to a close in 2024?

Gary Simmons: Sure, Manav. This is Gary. Obviously, a much weaker refinery margin environment than we — in the third quarter than we’ve seen in the last couple of years. The interesting thing to us is it looks like the underlying market fundamentals actually improved during the third quarter and have continued to improve as we move into the fourth quarter, despite that, the improving market fundamentals, market sentiment seems to turn more negative, driving crack spreads even lower. To us in the markets where we have a presence, things look very similar to what we’ve seen in the past couple of years. Lane alluded to our sales in the third quarter through wholesale over 1 million barrels a day. We averaged 1.8 million in the third quarter, which is actually up year-over-year.

Gasoline sales were fairly flat year-over-year. Diesel sales actually increased year-over-year. Thus far in the fourth quarter, we’ve actually seen about a 40,000 barrel a day increase in sales to our wholesale channel. So it’s actually going up. You kind of compare that to get an indication of demand with some other indicators. Vehicle models traveled, were up about 1%. So that kind of matches with our numbers. Even the DOE data, although there’s a lot of noise week to week. If you look at the year-to-date demand numbers from the DOE would kind of show gasoline demand flat to slightly up. And so we think that’s kind of where we are. Again, I said diesel sales in our system up a little bit year-over-year. Again, if you look at some of the other indicators of the demand, especially the freight indices would indicate demand for diesel is a little bit softer compare that to the DOE numbers in the year-to-date DOE numbers, which show diesel demand down close to 100,000 barrels a day, I think we think that’s pretty close.

Some of that gap in diesel demand has been made up by an increase in jet fuel demand, about half of that. So net-net, I think in the U.S., we feel like total light products kind of flat to slightly down year-over-year. markets outside the U.S. where we have a significant market presence in Canada, the U.K., Mexico, all very similar trends. I think all three of those markets have witnessed a year-over-year growth in gasoline demand, year-over-year growth in jet demand and the decline in diesel demand. So demand looks pretty strong outside those markets. We continue to see good export demand. Gasoline exports in the third quarter, about 100,000 barrels a day typical markets, Latin America and Canada. Diesel exports in the third quarter were 260,000 barrels a day, again, kind of South America and Europe.

So we continue to see demand that looks very similar to what we’ve seen in the last couple of years in the markets where we have a strong presence.

Manav Gupta: Perfect, Gary, so my quick follow-up is, if there are no real red flags here in demand, and it’s lightly softer in U.S., but stronger outside. Why did we suddenly hit this environment where the cracks are kind of trending below mid-cycle? And is that — and do you see this as transient if the demand holds then the track should be able to get back to mid-cycle or maybe even higher?

Gary Simmons: Yes, Manav, I would say some of this, typically on the third quarter earnings call, you tend to have a little more negative market sentiment. And there’s some reasons for that. Each year around Labor Day, you typically had some hurricane hype in the market that tends to go away as people view your out of hurricane season, you’ve gone through RVP transition, you start our RVP transition on gasoline, slowing the gasoline pool. Labor Day kind of marks the end of driving season. So you can certainly understand some negative market sentiment around gasoline. And typically, the fourth quarter and first quarter tend to be driven more by strength in the distillate cracks. I think we came into this year and although the U.S. economy has been fairly resilient.

We’ve seen some pockets of economic weakness throughout the globe, which have driven down diesel demand a little bit. And cause the pessimism around diesel cracks. If you look at where things are, though, the fundamentals look strong. We’re going into the year with very low inventories, gasoline inventory, 10 million barrels below where we were last year at this time, below the 5-year average. Some of the key things we tend to be focused on in the gasoline markets at this time of the year, market structure, market structure is backwards. So there’s no incentive to produce and store summer-grade gasoline. Typically, in the fourth quarter, the first quarter, you will have a positive transatlantic arb to ship from Europe to New York Harbor, at least on paper that arb is closed throughout the fourth quarter.

Export demand for gasoline remains strong. We’re seeing good export demand into Latin America. So things look good for gasoline. I don’t think you’re going to see any big moves in the gas crack anytime soon. But as long as inventory remains in check, you get back into driving season RVP transition, we would expect gas cracks to respond. On the distillate side, again, like gasoline, the key thing is, although we’ve seen a little bit less demand than we’d hoped for. Distillate inventories are trending toward the lows that we’ve seen the last couple of years. I think you saw economic run cuts throughout parts of the world that took some supply off the market. Here recently, we’ve had turnaround activity, decreased supply as well.

So it put us in a pretty good position heading into winter. And I think if you have some uptick in demand from heating oil demand with some colder weather, you’ll see distillate cracks respond as well.

Operator: The next question is coming from John Royall of JPMorgan.

John Royall: So my first question is on capital allocation. You were very aggressive on your buyback program in 3Q despite what’s been a downtick in cracks. You’ve been pretty clear on your framework in sort of a mid-cycle and above environment. But assuming we stay in this lower margin environment, can you talk about how your approach to returning capital may or may not change in terms of that 70s or 80s percent of CFO type range that you’ve been in? And would you use your balance sheet a little bit at lower parts of the cycle?

Jason Fraser: John, this is Jason. I’m going to ask Homer to respond to your question.

Homer Bhullar: Thanks, Jason. John. Yes, I mean, I think in this environment we’re in and with the strength of our balance sheet, you should absolutely should continue to expect us to be in our posture. As I mentioned in the opening remarks, you can go back to start of 2021. We’ve been able to fund all our uses of cash, including capital. We’ve paid down over $4 billion of debt and returned over $18 billion to shareholders over that period, all through cash flow from operations. So turning to where we are now, let me start by reiterating that the 40% to 50% is a minimum commitment, not a target. So we’re always going to honor that. As you noted, we’ve consistently been well above that despite the pullback in margins. And I think you can attribute that — attribute our ability to do that because of our low-cost profile and then disciplined use of capital.

So given the strength of our balance sheet and our cash position, I think you should rest comfortable that the 40% to 50% will continue to be a floor and all excess free cash flow will go towards buybacks.

John Royall: Great. And then my next question is just on California. We’ve gotten news of a new closure out there, which all other things equal, will be a good thing for those who remain. But there are some new legislative pressures there, and you’ve also mentioned strategic alternatives, I think, in your 10-Q. I was wondering if you could just give us an update on how you’re thinking about continuing to operate as a refinery in California and what those strategic alternatives might be.

Lane Riggs: John, this is Lane. I’ll let Rich start with the policy side, then I’ll talk about the strategic side after the answer of the question.

Richard Walsh: Okay. Yes. So it’s really unclear at this time whether when and which one of these various policies that the state keeps proposing coming out of these legislations. So we’ll just kind of have to we’ll have to kind of see how that plays out. A lot of these are driven by a lot of political rhetoric that you see coming out of the state. And I think when we see that pass from the legislature and the political arena back over to the CEC for implementation, I think you see them struggle with a lot of these ideas. There are ideas that they sound good politically, but when you start putting them into the market realities, it has the potential to make things even more costly for consumers. So the reality is that California policy has cost the state a number of refineries and including this most recent announcement.

And so you can’t have policy that impairs supply and then expected to lower prices for customers. So — and consumers. So recall, all of these regulations have a caveat in them that require the CEC to implement it only if they find that the actions will lower cost for consumers. And that’s going to be the challenge for them.

Lane Riggs: On strategy, we’ve been consistent for over a decade, probably even longer than that in terms of our – how we manage and steward the West Coast, and it’s largely driven by California policy. We’ve minimized strategic CapEx, we make sure we maintain a really reliable operation through our maintenance CapEx, which in turn positions us as a core call option on West Coast cracks. With that said, California is increasing its regulatory pressure on the industry. So it’s really considering everything, all options are on the table.

Operator: The next question is coming from Theresa Chen of Barclays.

Theresa Chen: Can you unpack some of the earlier comments on the evolution of global product supply over the more, I guess, medium to long term, taking into account the continued ramp up facilities abroad as well as planned closures in 2025. How do you think this trend? And do you expect changes in trade flows as a result?

Gary Simmons: Yes, Theresa, I can try. So overall, when we look at 2025, we see about 1,040,000 barrels a day of new refining capacity coming online. And so far, there’s about 740,000 barrels a day of refinery closures announced. So net-net, about a 300,000 barrel a day net capacity additions. And then forecast for total light product demand we’re looking at is about an increase in 700,000 barrels a day. So for next year, really, it all comes — and it becomes about timing. When did those refineries close, when did the new capacity come online. So it gives a lot of uncertainty into next year. Even the demand side is a little uncertain. A lot of the economic stimulus in China, how long does it take to come into effect? But we see tightening balances through next year.

And then when you get past next year, you kind of have a fairly extended period where when you look at net capacity additions, and total product demand growth, there’s a pretty good gap there. So we see an extended period with tighter and tighter balances around the refining margins.

Theresa Chen: Helpful. And then turning to the renewables front. Would you be able to provide an update on how the SaaS unit is operating following its recent in-service and any other commercial discussions to broaden this offering as well as your views on the subsidy prices.

Eric Fisher: Yes, I’d say — this is Eric, Theresa. The SaaS startup looks great. As we said in the call, the project finished ahead of schedule from our original timing that we had for 1Q of next year and it finished under budget. So project execution for Valero once again demonstrates its exceptional ability to beat expectations. And then you expect that performance as we go into full operations. So, so far, startup looks very good. I don’t think we have any doubt it’s going to meet its design capability. And commercially, we’re seeing a lot of interest and continued contracting of the product, both from a SBK standpoint, as well as a blended SaaS standpoint. And I don’t know, Gary, if you wanted to comment on any of that.

Gary Simmons: No, I’m not going to go into a lot of details, but there’s been some press releases with some of the airlines, Southwest, JetBlue about contracts that we’ve signed. In addition to that, we’re dealing with freight carriers. There’s been an announcement with DHL. So I’m not going to go into a lot of the commercial details there. But when we made the decision to fund the project, we said we expected it to exceed our minimum return threshold of after tax, 25%, still confident with the contracts we have in place and the volumes sold that we’ll do that.

Operator: The next question is coming from Doug Leggate of Wolfe Research.

Douglas Leggate: Appreciate you take my questions guys. Gary, I wonder if I could go back to the balances question. I know it’s an imperfect an imprecise assessment that we’re all trying to make here. But I wanted to use Valero as an example. I look back, your — obviously, your mechanical availability has been one of the hallmarks of the investment case. 2018 3rd quarter, 99%, ’19, 94%. Pre-COVID ’22, 95%, 95% last year. My point is that, you guys have obviously got a lot of upside to your potential utilization. And the same is probably true then of anyone who’s cutting runs at this point, Singapore or whatever. So when you think about supply additions, what are you assuming for the response of a potentially oversupplied market raising utilization in some of those more challenged refineries. And I guess what I’m getting at is it not reasonable to assume we need around the refinery closures before we get back to that above mid-cycle that you were talking about.

Gary Simmons: Yes. We look at historic refinery utilization rates and we look at the balances and kind of assume it’s going to be in line with historic utilization rates. However, I do think you can see a lot of refining capacity in the world that’s underwater, some of that is in need of a lot of capital investment. And so I think you will see additional refinery closures as well.

Douglas Leggate: Okay. So I guess to be — is that something you have any insight to? Or are you guessing.

Gary Simmons: No, we can’t name refineries that would close, but you can kind of see that refiners that are under pressure, some in Europe, some in the Far East. And our expectation is you’ll see some additional announced closures coming.

Douglas Leggate: Got it. Okay. Well, on the topic as my follow-up, if you don’t mind, and that’s going back to your comments about California. I mean, obviously, we’ve had ABX too, I guess, is it the title of it the inventory question. And it seems that when Phillips 66 shut down Rodeo, there was an equal and opposite impact from imports that seem to offset any potential tightness in the West Coast. So I guess as you look at your portfolio overall, and particularly the West Coast, how do you see the cost competitiveness? It’s the only asset in the only area in your portfolio that lost money this year this past quarter. Any color you can give on how you’re thinking about portfolio adjustments going forward?

Lane Riggs: Doug, it’s Lane. I sort of alluded to it before. It’s clearly our highest cost structure operation. Historically, they had been challenged with respect to cost of crude. So if you think about OpEx the regulatory environment and the supply situation in the West Coast, it’s – it’s always a challenge. And so – and it’s very different than maybe some of the other areas that we operate. And again, what we’ve historically done is try to position the assets to be a call option for when things get out of balance because the supply chain is so long. So with respect to these regulations, we’ll just have to see what they actually finally try to do. But clearly, the California regulatory environment is putting pressure on operators out there and how they might think about going forward with their operations.

Operator: The next question is coming from Roger Read of Wells Fargo.

Roger Read: Yes. I want to come back and hammer the California question as well. In the most recent 10-K and 10-Q, you put out — you’ve highlighted issues with California from an asset value or an ongoing concern kind of question. With Philips closing down their unit or announcing the closure of their unit, California obviously hypersensitive about the price of fuels to consumers regardless of what their policy may do. Does it impact your ability, you think, going forward, if you have to make a hard decision on a California refining unit that someone else went first. I mean sort of — does it invite more political interference? And how would that work?

Richard Walsh: I mean, I don’t know that, that really factors into our thinking necessarily. I mean I think what we would be looking at is what are the regulatory programs that California puts forward. A lot of these programs were announced. I mean the initial one, the margin cap was announced almost 2 years ago, and they’ve still been collecting information and studying the market. I mean I think one of the realities is there’s the market is incredibly efficient until you interfere with it. And I think the California is, I think, starting to realize that as the more they interfere, the worse the situation gets. And so that’s, I think the challenge there. So I think we have to wait and see what they’re going to do and what they decide. I mean, it’s their choice, and then we just have to react to that. And what others do, that’s their decision. We have great assets out there, and we have great people operating them. So I think we like our position.

Roger Read: Appreciate that. Rich, you’re more of an optimist than me because I don’t really believe they quite grasp all the impacts of policies in terms of the outcomes. The follow-up question, I’d just like to ask, probably to Gary, diesel demand does look like it’s starting to improve here in the U.S., the last kind of, let’s call it, 2 months worth — is there anything you’re seeing that in terms of DOE information, is there anything you’re seeing as you look at that in a more short-term basis versus like your full year commentary on demand?

Gary Simmons: I think both gasoline and diesel, we saw a little bit of demand softness, and it’s picked up as the year has gone on. I mentioned over the last 2 weeks, we’ve actually seen a surge. So in the last 2 weeks, we have about a 5% year-over-year increase in diesel demand kind of consistent with your comments. I think you’re seeing some of that in Europe as well. You can see the 211 in Europe has gone up $2 or $3 in the last few weeks, kind of indicating that some of that topping capacity, the diesel from some of that hydroskimming topping capacity is ’eeded to supply the market as things are getting tight heading into winter.

Operator: The next question is coming from Paul Cheng of Scotiabank.

Paul Cheng: I apologize. First I want to add — one question is on California also. I think Gary and Lane. Historically, that refiner doesn’t just shut down the refinery just because they’re not making money. But typically, we wait until there’s a substantial CapEx outlay requirement, maybe a major turn on before that they’re being pushed to make a hard decision. Just curious that in your Benicia refinery, can you share that what that may be the time line, say, at what point that will be the next major capital data you need to put that you will have to make a decision or that more likely than we’ll make you trying to have a decision whether that is a viable ongoing business or not. Is there any you can say?

Lane Riggs: Yes. Paul, this is Lane. Sorry for that. So good try. We don’t normally provide outlooks with respect to our turnaround activity. But your premise is correct. I mean clearly, not only the cost structure out there is higher the cost turnarounds out there is significantly higher. And so it weighs any big outlay on turnarounds in the West Coast is in the way you think about assets going forward, it will — and any other asset really in the world for that matter, it’s largely driven by the next big capital outlay. But in terms of guidance on — and we’re going to do our next turnaround, we — as a general policy, we just don’t do that.

Paul Cheng: Okay. Understand. And Europe [indiscernible] the margin capture is phenomenal. And it’s interesting because I mean Europe, the market condition quite very difficult. So if the strong margin capture is really driven by your [indiscernible] refinery? Or that is — I mean, Europe is also doing well. Just trying to help us understand — I mean, over the past 2 or 3 years, quite [indiscernible] and then take often time surprised us on the upside. So trying to understand what’s going on there.

Greg Bram : Paul, it’s Greg. So a couple of things that impacted the North Atlantic in the third quarter: One, we had some very good results from the commercial team that helped contribute; And then the second thing, you talked about Quebec, but really crude cost for that region. Sometimes it’s Quebec, sometimes it’s Pembrook but crude costs were fairly favorable. Some of that was some of the Canadian grades coming into Quebec. Some of that was just the relative value of the grades we’re running versus dated Brent. And so while that market might have been challenged, remember that the capture is relative to kind of a market-based reference crack. And so we take into account where the market is at and putting that together, and we performed pretty well relative to that reference.

Operator: The next question is coming from Jean Salisbury of Bank of America Merrill Lynch.

Jean Salisbury: You referenced the growing OPEC supply next year. This primarily benefits Valero and heavy sour crude, but I believe also in some of the high sulfur intermediate margins. that you consume as feedstocks. Can you just go over the different ways that increasing OPEC supply could manifest in different markets and your exposure there?

Gary Simmons: Yes. So we see several bright spots in terms of supply fundamentals around heavy sour crude. Obviously, OPEC, 180,000 barrels a day on the market starting in December. Seasonally, we expect Canadian production to ramp up as well. We think Canadian production could hit record highs over the winter. Then you have continued Venezuelan production growth, and this time of year, you get to where you’re past the period of time in the Middle East where they’re burning fuel oil for power generation. So all that puts more barrels on the market. If you get into the first quarter and Lyondell shuts down, it takes some demand as way as well. So those things should be positive in terms of quality discounts.

Operator: The next question is coming from Joe Laetsch of Morgan Stanley.

Joe Laetsch: So I wanted to go back to the RD side, and it continues to be a tougher margin environment for the industry overall to margins recently. As we look towards 2025, could you just talk to how you’re thinking about the moving pieces around credits, including RINs, LCFS prices as well as feedstock costs as it relates to profitability?

Eric Fisher: Sure. This is Eric. The — it looks like a lot of good tailwinds start in 2025. So California intends to approve their LCFS modifications November 8, with the intent of starting that Jan 1, that should tighten the credit bank through 2025 and increase LCFS prices. You’ve got that. You’ve got Europe and U.K. starting their fit for 55 which starts the SAF mandate of 2% in that region. We’re watching the Canadian B.C. election very closely to see what they do with the CFR, but nationally, that will still be in play in 2025. And all these obligations naturally ratchet as you go into next year. And then lastly, the IRA with the switch from the blenders tax credit to the production tax credit does create a lot of tailwind for us because that will switch from $1 for everyone to a CI base where we’re the most advantaged and it does not allow importers to qualify for the credit.

So if you look at those two benefits of the IRA, that is a good tailwind for DGD. Those things are all on paper that’s waiting for a lot of policy clarification between now and the end of the year. But the one thing we look at is that is the policy intent of all those programs. And most of those take legislative action to change. And so that, we think, will be difficult and that means those policies will probably go forward as designed at least initially. So we’re all waiting on seeing how that develops in the next couple of months. I think the whole renewables segment is all asking for this guidance to be given so that we can move forward with plans. But all of that looks pretty constructive. On the feedstock side, we’ve mostly seen prices equilibrate.

There was previously a lot of advantage in foreign feedstocks. We’ve seen that largely equilibrate. We’ve seen the market really level out a lot of the price lag we’ve talked about for the last several months has evened out. So I think what you’re seeing is the world is recognizing that waste oils are still the most advantaged. Our partnership with Darling still gives us the most advantaged access to domestic feedstock and some of their foreign feedstock that they now produce out of South America and Europe, all of that looks advantaged. And as we see vegetable oil and BD are going to be marginal going forward, and that will set a floor in this whole space. So as the blenders tax credit goes away, BD will be significantly underwater without an adjustment to the RINs. So the last piece that I think is positive is the expectation that RINs will have to go up to offset the loss that BD and vegetable oil RD takes as we migrate to the PTC.

So that — there’s a lot of expectation that RINs will increase. That won’t happen overnight, but if that does, it is a significant tailwind to DGD and RD.

Joe Laetsch: Great. there. And then I just wanted to ask on the naphtha side, specifically, exports out of the Gulf Coast has been strong in the past couple of months, which I think has been supportive of margins. What are you seeing on your side? And how are you thinking about the outlook for naphtha here?

Gary Simmons: Yes. So I think there’s a couple of things driving the relative strength in naphtha. Some of that is with the economic run cuts of some of the hydroskimmers, you see less naphtha in the market. So U.S. Gulf Coast supply has had a step in for that. But we’re also seeing a bit of a pickup for petrochemical demand for naphtha, which looks to be improving. And so that’s also creating some of the export opportunities. So we expect it to continue.

Operator: The next question is coming from Ryan Todd of Piper Sandler.

Ryan Todd: Maybe what I know — Lane, I know how much you love to talk about the concept of capture rate, but has been — for the entire sector, it’s kind of been steadily declining over the last 18 months. And some of that obviously is just that level of margins coming down. But can you maybe talk about some of the things that have been headwinds? And then what needs to happen to see improvements on that? And is it is it absolute margins, wider crude differentials, crude backwardation, secondary product pricing improvement. Any signs of encouragement as you look into the fourth quarter of 2025 in terms of maybe improvements in margin capture.

Lane Riggs: Yes. Ryan, it’s Lane. I fortunately I get to hand this off to Greg.

Greg Bram : Ryan, so I think you noted most of the key factors, and we’ve talked about some of them already. Crude market backwardation certainly has been a bit persistent and strong here, particularly late in 2024 that’s certainly a factor. In fact, I think if you look back in early 2023, we’re actually in contango. So there’s no doubt that continuing on an ongoing basis is not something you would necessarily expect. So seeing improvement there will help capture. Thinking about us, in particular, we’ve talked about heavy maintenance a number of quarters here recently. So that’s definitely a factor more in some regions than others. I mean, there’s always going to be some maintenance in our system industry as well. So I think there have been some heavier periods though that have had some impact.

And then you mentioned secondary products. I think the ones that really come to mind there are those related to pet chem, so things like propylene and naphtha. And Gary just talked about it. As we’re seeing pet chem start to improve expect those values to improve as well, and that’s going to have some positive impact on capture.

Ryan Todd: Great. And then maybe one follow-up on some of your earlier comments on sustainable aviation fuel. As we think about — I mean the message over the last couple of years late into this, I think there was clearly an expectation that the market — the SAF market was going to be undersupplied which was going to be good for you guys. There’s been a lot of moving pieces in that. Do you still view the market over the next 12 to 24 months as undersupplied? And then as you think about you’re probably one of the few domestic producers that can qualify to sell into Europe. How do you think about the potential optionality of being able to sell into Europe versus kind of domestic markets and pricing here?

Eric Fisher: Yes, this is Eric. I think our view is consistent that the market is physically undersupplied, given the ramp in mandates that is occurring over the next year to 5 years. You’re absolutely correct. Europe will be the most attractive market, and we do have capability of supplying into that market. That will be one of our primary outlets as we start up. But I think the policies are always, as I mentioned before, we’re waiting for a lot of clarification there. The mandate in Europe is very clear how that will be implemented is waiting on a lot of clarity on guidance for import codes and what duties are affecting it, all these kind of details that make – finishing the contract difficult, but we see that as all solvable between now and the end of the year for January 1 compliance.

And I think in the U.S., the IRA clearly favors staff over RD from a credit standpoint. Again, we’re waiting for clarity on that and as well as a lot of our customers and blenders are waiting for clarity so that we can get the contract language perfected. But all of that is moving forward, and we’re confident that’s going to get solved contractually especially once we get clarity on this policy guidance.

Operator: The next question is coming from Neil Mehta of Goldman Sachs.

Neil Mehta: The first question is just around operating expenses. It’s always been a hallmark of Valero is your ability to keep that OpEx low per barrel. Just your perspective on how some of those moving pieces as we move into the next couple of years and how you’re thinking about it even geographically as well.

Greg Bram : Neil, it’s Greg. So we keep those expenses under control. It’s one of the things we focus on every day. A couple of parts, I think, that are probably notable. Energy costs have been low natural gas driving that. That’s been a help. And so it looks like those prices will move back towards kind of middle of the cycle kind of range here, at least that’s what folks are thinking, but that’s been helpful. Inflation has made it a bit harder. We’ve seen the effects of that on both maintenance costs, catalyst chemicals, those kinds of things. We work hard with our partners to try to make sure we keep those costs competitive. And so as inflation moderates, we’d expect to see some of that improve as well. Those are probably the two biggest parts to think about and really the things we focus on every day.

Neil Mehta: Yes. Yes. Understood on the energy side. And then the other one is on just on the Port Arthur coker. I think when you FID-ed, you talked about $325 million of EBITDA. And then you talked about it actually run rating closer to $400 million. How do you think — as you think about that project specifically about, one, the current economics and then how those economics could evolve as you think about the path back to mid-cycle?

Greg Bram : Yes, Neil, I think we still see that project giving us the returns consistent with what we showed at FID. The current market is a little different than where we started. We got real good benefits earlier this year when we did the turnaround on the old coker and we expected to see some strong value there. So I don’t think anything has changed in our view. And then again, obviously, that project is hinged on being able to run a lot of heavy sour crude and upgraded to light products. And so as those sour differentials move around, that’s going to give us a chance to capture some more value.

Operator: The next question is coming from Matthew Blair of TPH.

Matthew Blair: If I heard correctly, I think the $4.7 million ethanol volume guidance for Q4 might be an all-time record. And just coming at a time when ethanol margins are really crumbling on paper. So could you help us reconcile that? Is that a function of increasing net export opportunities or maybe there’s the lag we should be thinking about on the ethanol indicator?

Eric Fisher: Yes, it’s Eric. We have increased our ethanol production capability this year. Most of this year has been pretty positive for that expanded capability. We have also expanded our export markets. Again, talking about policy, there’s interest in U.S. ethanol, especially a lot of our ISCC qualified ethanol in Europe. We also see that because of U.S. corn being the most attractive feedstock in the U.S. with the largest carryout, one of the largest harvest we’ve ever seen, it is giving a lot of opportunity for ethanol exports. So that’s what we’re seeing as increased demand. We’re seeing new markets for E10 in the world, and we see Brazil is increasing its ethanol mandate as well as the SaaS mandate beginning in ’25. So we’ve grown our capacity in anticipation of a lot of this expanded interest globally in ethanol.

Matthew Blair: Sounds good. And then there’s been more chatter lately about just increasing global tariffs and exports are a big part of the outlet for U.S. refiners. So when you hear about the potential for just [indiscernible] increases in tariffs, what do you think, is that a concern going forward?

Richard Walsh: This is Rich Walsh. I’ll take an effort to add that. I mean, when you look at those tariffs, a lot of times, they’re really focused around manufactured goods. Most countries don’t want to increase their cost of energy that they’re trying to take in. So when you think about targets for tariffs, they normally don’t really wrap around energy. And so I don’t know that we see the concerns on that.

Operator: The next question is coming from Jason Gabelman of TD Cowen.

Jason Gabelman: I wanted to circle back on the financial framework, and you provided some helpful comments about the return of capital metrics being a firm target. And I’m wondering how you think about using the balance sheet in a downturn. You have this $4 billion kind of target for cash for the balance sheet. Is that what you want headed into a downturn so you could lean on the balance sheet a bit more should the market weaken?

Jason Fraser: Yes. This is Jason. I’ll be glad to share some of our thoughts about cash. And our targeted cash balance will depend on the environment we’re in, but in a normalized environment, we like to keep a cash balance between $4 billion to $5 billion as a guideline. And as you know, cash to move around a lot in any quarter due to things like working capital, but we’re not going to hoard cash. So I think directionally, you should expect our cash balance to trend down a little from here. I’d also like to note, if it wasn’t for the positive impact from working capital this quarter, we would have drawn cash by over $200 million. We also had strong buybacks for the quarter of $565 million without leaning on the balance sheet.

But to answer your question more directly, yes, you’re right, that $4 billion gives us a lot more room and flexibility in the downturn to continue our approach to buybacks. So I think that’s correct. It’s a big factor in coming out with a $4 billion number.

Jason Gabelman: Great. And then the other just on the market. We’ve noticed a pretty strong product exports for gasoline and diesel, out of the U.S., and it’s coming as fracs have fallen a bit here the past months. And so it seems like prices are needing to fall to clear the U.S. market and keep U.S. inventories kind of at healthy levels. Is that a fair interpretation of what’s going on in the market where there’s kind of a push from the U.S. on product exports rather than a pull from international sources on those products?

Gary Simmons: Well, it’s a good question. It would appear that what you’re saying is correct. But in the face of that, gasoline inventories are really pretty low. We’re $10 million below where we were last year. You are below the 5-year average. So the inventories wouldn’t indicate a need to push. It would almost seem like it’s more of a pull, and we’re getting an export premium, and that’s why the barrels are flowing.

Jason Gabelman: Okay. And when you say you’re getting an export premium, you’re able to sell to international markets at a higher price than what you’re selling at on, say, the U.S. Gulf Coast?

Gary Simmons: Yes, we are.

Operator: Thank you. At this time, I would like to turn the floor back over to Mr. Bhullar for closing comments.

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

Operator: Ladies and gentlemen, this concludes today’s event. You may disconnect your lines or log off at this time, and enjoy the rest of your day.