Valero Energy Corporation

Greetings and welcome to Valero Energy Corp. Third Quarter 2024 earnings conference call. At this time, all participants are on a listen-only mode. A question and answer session will follow the formal presentation. If anyone requires operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Homer Bowler, Vice President, Investor Relations and Finance. Thank you. You may begin.

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 Frazier, our Executive Vice President and CFO, 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 of the SEC. Now I'll turn the call over to Lane for opening remarks.

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 90% throughput capacity utilization in line with our guidance for the quarter. Product demand across the system remains strong with our U.S. wholesale volume 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 SAFT, 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 strengths 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 a -to-date payout of 81%. Looking ahead, improving diesel demand against a backdrop of low-light product inventories should support refining margins. Increases in OPEC plus crude supplies should widen our sour crude oil differentials and further increase margins. In 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 has served us well and will continue to anchor our strategy going forward. So with that, Homer, I'll hand the call back to you.

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, GNA 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 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 $3.5 million 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 return 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 financing 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 to 1.88 million barrels per day, Mid-Continent at 425 to 445,000 barrels per day, West Coast at 230 to 250,000 barrels per day, and North Atlantic at 380 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 45 cents per gallon, which includes 18 cents per gallon for non-cash 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 37 cents per gallon, which includes 5 cents per gallon for non-cash 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 GNAEI 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 their questions.

Thank you. The floor is now open for questions. If you would like to ask a question, please press star one on your telephone keypad at this time. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up the handset before pressing the star keys. Again, that's star one to register a question at this time. Today's first question is coming from Manav Gupta of UBS. Please go ahead.

Good morning, Manav. Good

morning.

Good morning, sir. 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?

Sure, Manav. This is Gary. Obviously, a much weaker refinery margin environment than we know 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 sees 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 the past couple of years. Lane alluded to our sales in the third quarter through wholesale over a million barrels a day. We averaged a million eight in the third quarter, which is 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 through our wholesale channel. So it's actually gone up. You kind of compare that to get an indication of demand with some other indicators. You know, vehicle models traveled are up about 1 percent, 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 demand, especially the freight indices would indicate, you know, demand for diesel is a little bit softer. Compare that to the DOE numbers. And in the year to day DOE numbers would show diesel demand down, you know, 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, you know, 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, you know, 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 a 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 the last couple years in the markets where we have a strong presence.

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

Yeah, Manav, I would say, you know, 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 -of-hurricane season. You've gone through RVP transition, you start RVP transition on gasoline, swelling 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 the strength and the distillate cracks. I think we came into this year, and although, you know, the U.S. economy has been fairly resilient, you know, we've seen some pockets of economic weakness throughout the globe, which has driven down diesel demand a little bit and caused the pessimism around, you know, diesel cracks. If you look at where things are, though, you know, 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 five-year average. Some of the key things we tend to be focused on in the gasoline markets at this time of year, market structure. Market structure is backward, so there's no incentive to produce and store summer grade gasoline. Typically, in the fourth quarter, the first quarter, you'll 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. You know, we're seeing good export demand in the Latin America. So things look good for gasoline. I don't think, you know, you're going to see any big moves in the gas crack anytime soon, but, you know, as long as inventory remains in check, you get back into driving season, the RVP transition, and we would expect gas cracks to respond. On the distillate side, again, you know, 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 know, 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, you know, if you have some uptick in demand from heating oil demand with some colder weather, you'll see distillate cracks respond as well.

Thank you so much for taking my questions.

Thank you. The next question is coming from John Royal of JP Morgan. Please go ahead.

Hi. Good morning. Thanks for taking my question. So my first question is on capital allocation. You were very aggressive on your buyback program in 3Q, despite, you know, what's been a down break 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?

Good morning, John. This is Jason. I'm going to ask Homer to respond to your question.

Thanks, Jason. Hey, John. Yeah, 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 percent 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 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 comfortable that the 40 to 50 percent will continue to be a floor and all excess free cash flow will go towards buybacks.

Great. Thanks for the cover there. And then my next question is just on California. We've gotten news of a new closure out there, which all other things equal would 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 10Q. I was wondering if you could just give us an update on how you're thinking about continuing to operate as a refiner in California and what those strategic alternatives might be.

Hey, John, this is Wayne. I'll let Rich start with the—at this time, you know, whether, when, and which one of these various policies that the state keeps proposing, you know, coming out of these legislations. So we'll just kind of have to see how that plays out. You know, a lot of these are driven by a lot of political rhetoric that, you see, you know, coming out of the state. And, you know, 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. You know, they're ideas that, you know, they sound good politically, but when you start putting them into the market realities, you know, it has the consumers. So, you know, the reality is that, you know, California policy has cost the state a number of refineries and, you know, including this most recent announcement. And so you can't have policy that impairs supply and then expect it to lower prices for customers and consumers. So, you know, recall all of these regulations have a caveat in them that require the CEC to implement only if they find that the actions will lower costs for consumers. And that's going to be the challenge for them.

So. And on strategy, you know, we've been consistent for over a decade, probably even longer than that, in terms of how we manage and steward the West Coast. And it's largely driven by California policy. We've minimized strategic capex. We've made sure we maintain a really reliable operation through our maintenance capex, which in turn positions us as a potential for a call option on West Coast cracks. You know, with that said, California's increasing its regulatory pressure on the industry. So, you know, it's really considering everything and all options are on the table.

So. Thank

you. Thank you. The next question is coming from Teresa Chan of Barclays. Please go ahead.

Good morning. 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 of facilities abroad as well as planned closures in 2025? How do you think this trends and do you expect changes in trade flows as a result?

Yeah, Teresa, I can try, you know, so overall, when we look at 2025, we see about a million forty thousand barrels a day of new refining capacity coming online. And so far, there's about seven hundred and forty thousand barrels a day of refinery closures announced. So, you know, net net about a three hundred thousand barrel a day net capacity additions and then forecast for total light product demand we're looking at is about an increase in seven hundred thousand barrels a day. So for next year, really, it all comes and, you know, when do those refineries close? When did the new capacity come online? So it gives a lot of uncertainty to next year. Even the demand side is a little uncertain. You know, 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 with tighter and tighter balances around the refining margins.

Helpful. Thank you. And then turning to the renewables front, would you be able to provide an update on how the SAS unit is operating following its recent in-service and, you know, any other commercial discussions to broaden this offering as well as your views on the subsidy prices? Thank

you. Yeah, this is Eric, Teresa. The SAP startup looks great. You know, as we said in the call, the project finished ahead of schedule from our original timing that we had for one queue 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 operation. So, so far, startup looks very good. I don't think we have any doubts it's going to meet its design capability. And commercially, we're seeing a lot of interest in continued contracting of the product, both from a SBK standpoint, as well as a blended staff standpoint. I don't know, Gary, if you wanted to comment on any of

that. No, I'm not going to go into a lot of details, but there's been some press releases, you know, with some of the airlines, Southwest, JetBlue, about contracts that we signed. In addition to that, we're dealing with freight carriers. There's been an announcement with DHL. So, you know, 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 the contract is 25%. Still confident with the contracts we have in place and the volume sold that we'll do that.

Thank you.

Thank you. The next question is coming from Doug Leggett of Wolf Research. Please go ahead.

Thank you. I appreciate you taking my questions, guys. Gary, I wonder if I could go back to the question. I know it's an imperfect and imprecise assessment that we're all trying to make here, but I wanted to use Valero as an example. I look back, obviously, your mechanical availability has been one of the hallmarks of the investment case. 2018, third quarter, 99%, 1994% pre-COVID, 22%, 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 and I guess what I'm getting at is, is it not reasonable to assume we need to run around the refinery closures before we get back to that above mid-cycle that you were talking about?

Yeah, 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 investment. And so I think you will see additional refinery closures as well.

Okay, so I guess to be, is that something you have any insight to or are you guessing?

No, we can't name refiners 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. Okay,

well on that topic is 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 2.1, 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, you know, impact from imports that seems 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 as the only asset and 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?

Hey, Doug is laying, I sort of alluded to it before, it's clearly our highest cost structure operation. Historically, they have been challenged with respect to cost accrued. So if you think about OPEC, the regulatory environment, and the supply situation in the West Coast, you know, it's always just a challenge. And so 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.

All right, we'll keep watching, guys. Thanks for taking my question. I appreciate it.

Thank you. The next question is coming from Roger Reed of Wells Fargo. Please go ahead.

Yeah, thanks. Good morning. I'm going to come back and hammer the California question as well. In the most recent, you know, 10-K and 10-Q you've put out, you've highlighted issues with, California from an asset value or an ongoing concern kind of question. With Phillips 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, you know, sort of, does it invite more political interference and how would that work?

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, you know, what are the regulatory programs that California puts forward? You know, a lot of these programs are announced. I mean, the initial one, the margin cap was announced almost two years ago and they've still been collecting information and studying the market. I mean, I think one of the realities is there's, you know, the market's incredibly efficient until you interfere with it. And I think that California is, I think, starting to realize that, you know, the more they interfere, the worse the situation gets. And so that's, I think, the challenge there. So I think, you know, 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, you know, we just have to react to that. And, you know, what others do, that's their decision. You know, we have great assets out there and we have great people operating them. So I think we like our position.

I appreciate that, Rich. You're more of an optimist than me because I don't really believe they quite grasp all the impacts of their 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, two months' worth. Is there anything you're seeing that, you know, 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?

I think both gasoline and diesel, we saw a little bit of demand softness and it's picked up as the year's gone on. I mentioned over the last two weeks we've actually seen a surge. So in the last two weeks we have about a 5% -over-year increase in diesel demand, you know, kind of consistent with your comments. I think you're seeing some of that in Europe as well. You know, you can see the 211 in Europe has gone up two or three dollars in the last few weeks, kind of indicating that some of that topping capacity, the diesel from some of that hydro-skimming topping capacity is needed to supply the market as things are getting tight heading into winter. Great, thank you.

Thank you. The next question is coming from Paul Chang of Scotiabank. Please go ahead.

Hey guys, good morning. I have to apologize first. I want to ask one question on California also. I think Gary and Ling, 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 capital outlay requirement, maybe a major turnaround before that they're being pushed to make a hot decision. Just curious that in your Beninshire refinery, can you share that, what that may be the timeline, say at what point that will be the next major capital outlay that you need to put that you will have to make a decision or that more likely that will make you trying to have a decision, whether that is a viable ongoing business or not. Is there any timeline you can share?

Yeah, hey Paul, this is Ling. Sorry for that. It's a good try. We don't normally provide outlooks with respect to our turnaround activity, but your premise is correct. I mean, clearly, not only is the cost structure out there higher, the cost of doing turnaround out there significantly higher, so it weighs any big outlay on turnaround in the west coast. The way you think about assets going forward, and any other asset really in the world for that matter, is largely driven by the next big capital outlay. But in terms of guidance on when we're going to do our next turnaround, in the journal Paul, we just don't do that.

Okay, I understand. Europe or that you're involved in the margin capture phenomenon. And it's interesting because in Europe, the market condition is quite fairly difficult. So if the strong margin capture is really driven by your cubectity refinery, or that is Europe is also doing, we're just trying to help us understand, I mean, over the past two or three years, quite frankly, that your law of Atlantic oftentimes surprises us on the upside. So trying to understand what's going on there.

Hey Paul, it's Greg. So a couple 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 costs for that region. Sometimes it's Pembroke, 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 were 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's at in putting that together. And we performed pretty well relative to that reference.

Okay. And okay. I think I should obey the two question rules. So that's it for me.

We appreciate that, buddy. Thank you.

The next question is coming from Gina in Southbury, a bank of America. Please go ahead.

Hi, good morning. You referenced the growing OPEC supply next year. This primarily benefits Valero and heavy sour diffs, 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?

Yeah. 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 Lyandell shuts down, it takes some demand away as well. So all those things should be positive in terms of quality discounts.

Okay, great. I'll leave it there. Thank you.

Thank you. The next question is coming from Joe Latch of Morgan Stanley. Please go ahead.

Great. Thanks. Good morning and thanks for taking my questions. So I wanted to go back to the RD side and it continues to be a tougher margin environment for the industry. Overall, the recent demand 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?

Sure. This is Eric. It looks like a lot of good tailwinds start in 2025. So California intends to approve their LCFS modifications November 8th 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 UK starting their fit for 55, which starts the SAF mandate of 2% in that region. We're watching the Canadian BC 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 Blender's tax credit to the production tax credit does create a lot of tailwind for us because that will switch from a dollar 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 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 renewable 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 blender's tax credit goes away, BD will be significantly underwater without an adjustment to the RIN. 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 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.

Great. Thanks for all of the detail there. I just wanted to ask on the NAFTA side specifically, exports out of the Gulf Coast have been strong 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 NAFTA here?

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

Great. Thank you all.

Thank you. The next question is coming from Brian Todd of Piper Sandler. Please go ahead.

Maybe what I know, Lane, I know how much you love to talk about the concept of capture rate, but it 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 the absolute 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 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?

Yeah, Ryan, this is Lane. I'm fortunate to hand this off to Greg.

Hey, 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 that related to PETCAM, so things like propylene and naphtha. And Gary just talked about it. As we're seeing PETCAM start to improve, you'd expect those values to improve as well, and that's going to have some positive impact on capture.

Great, thanks. 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 leading to 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 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?

Yeah, 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 five 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 Jan 1 compliance. And I think in the US, the IRA clearly favors SAF 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 on this policy guidance.

Okay, thanks, Eric.

Thank you. The next question is coming from Neil Mehta of Goldman Sachs. Please go ahead.

Yeah, good morning, Lain and team. The first question is just around operating expenses. It's always been a hallmark of Valera's, 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.

Hey, Neil, it's Greg. So, you know, 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, you know, it looks like those prices will move back towards kind of a middle of the cycle kind of range here. At least that's what folks are thinking. But that's been helpful. Inflation's made it a bit harder. We've seen 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.

Yeah, understood on the energy side. And then the other one is on just on the Port Arthur Coker. I think when you FID'd it, you talked about 325 and then you talked about it actually run rating closer to $400 million. How do you think, 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?

Yeah, Neil, you know, I think we still see that project giving us the returns consistent with what we showed at FID. 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. Thank you.

Appreciate it.

Thank you. The next question is coming from Matthew Blair of TPH. Please go ahead.

Thanks and good morning. If I've heard correctly, I think the 4.7 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 export opportunities or maybe there's a lag we should be thinking about on ethanol indicator?

Yes, 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 US ethanol, especially a lot of our ISCC qualified ethanol in Europe. We also see that because of US corn being the most attractive feedstock in the US with the largest carryout and one of the largest harvests we've ever seen, it is giving a lot of opportunity for ethanol exports. So that's what we're seeing is 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 SAF mandate beginning in 2025. So we've grown our capacity in anticipation of a lot of this expanded interest globally in ethanol.

Sounds good. Then there's been more chatter lately about just increasing global tariffs and exports are a big part of the outlet for US refiners. So when you hear about the potential for blanket increases in tariffs, what do you think? Is that a concern going forward?

This

is Rich Walsh. I'll take an effort to add that. When you look at those tariffs, a lot of times they're really focused around manufactured goods and 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. So I don't know that we see any concerns on that.

Great. Thank you.

Thank you. The next question is coming from Jason Gabelman of TD Cowan. Please go ahead.

Hey, morning. Thanks for taking my questions. 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?

Yeah, this is Jason. I'll be glad to share some of our thoughts about cash. And our targeted cash balance would depend on the environment we're in. But in a normalized environment, we like to keep a cash balance between $4 to $5 billion as a guideline. And as you know, cash can 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 without leaning on the balance sheet. But to answer your question more directly, yeah, 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. That's a big factor in coming up with a $4 billion number.

Great. Thanks for that color. And then the other, just on the market, we've noticed pretty strong product exports for gasoline and diesel out of the US. And it's coming as cracks have fallen a bit here the past month. And so it seems like prices are needing to fall to clear the US market and keep US 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 US on product exports rather than a pull from international sources on those products?

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, below the five-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.

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 US Gulf Coast?

Yes, we are.

Okay. Great. Thank you.

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

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.

Thank you. 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.