HF Sinclair Corporation (NYSE:DINO) Q3 2025 Earnings Call Transcript

HF Sinclair Corporation (NYSE:DINO) Q3 2025 Earnings Call Transcript October 30, 2025

HF Sinclair Corporation beats earnings expectations. Reported EPS is $2.44, expectations were $1.94.

Operator: Welcome to HF Sinclair Corporation’s Third Quarter 2025 Conference Call and Webcast. Hosting the call today is Tim Go, Chief Executive Officer of HF Sinclair. He is joined by Atanas Atanasov, Chief Financial Officer; Steven Ledbetter, EVP of Commercial; Valeria Pompa, EVP of Operations; and Matt Joyce, SVP of Lubricants and Specialties. [Operator Instructions] Please note that this conference is being recorded. It is now my pleasure to turn the floor over to Craig Biery, Vice President, Investor Relations. Craig, you may now begin.

Craig Biery: Thank you, Ellie. Good morning, everyone, and welcome to HF Sinclair Corporation’s Third Quarter 2025 Earnings Call. This morning, we issued a press release announcing results for the quarter ending September 30, 2025. If you would like a copy of the earnings press release, you may find it on our website at hfsinclair.com. Before we proceed with remarks, please note the safe harbor disclosure statement in today’s press release. In summary, it says statements made regarding management expectations, judgments or predictions are forward-looking statements. These statements are intended to be covered under the safe harbor provisions of federal security laws. There are many factors that could cause results to differ from expectations, including those noted in our SEC filings.

The call also may include discussion of non-GAAP measures. Please see the earnings press release for reconciliations to GAAP financial measures. Also, please note any time-sensitive information provided on today’s call may no longer be accurate at the time of any webcast replay or rereading of the transcript. And with that, I’ll turn the call over to Tim Go.

Timothy Go: Good morning, everyone, and thank you for joining our call. I am pleased to report that HF Sinclair’s strong third quarter results are underpinned by the measurable improvement in our operating and commercial performance, including the sequential increases in refining throughput and capture and continued reductions in operating costs. During the quarter, we returned $254 million in cash to shareholders and today announced a $0.50 quarterly dividend. We are pleased with the progress we have made on our key priorities and believe our year-to-date performance reflects the value of this strategic focus. Now let me cover our business highlights. In refining, we delivered another quarter of sequential improvements in throughput, capture and operating expenses per barrel.

Gross margin per barrel benefited from strong cracks in our regions, along with small refinery exemptions granted by the EPA. The SRE benefit in the third quarter was comprised of $115 million in lower cost of goods and $56 million in higher revenue from the commercial optimization of our RINs position. We achieved a record low operating expense of $7.12 per throughput barrel, crossing over our near-term goal of $7.25 per barrel. Throughput was our second highest quarter on record, and we are on pace to establish many new annual records for the full year. Our Marketing segment delivered record EBITDA in the quarter of $29 million and realized an adjusted gross margin of $0.11 per gallon. We are very pleased with the growth we have achieved in our marketing segment, and we continue to unlock the value of the Sinclair branded stores, providing a consistent sales channel with margin uplift for our produced fuels.

We have added 146 branded sites through third quarter ’25 with more than 130 sites with contracts signed and expected to come online over the next 6 to 12 months. During the quarter, we returned $254 million in cash to shareholders, consisting of $160 million (sic) [ $166 million ] in share repurchases and $94 million in regular dividends. Since the Sinclair acquisition in March of 2022, we have returned over $4.5 billion in cash to shareholders and have reduced our share count by over 61 million shares. As of September 30, 2025, we still have approximately $589 million remaining on our share repurchase authorization, and we remain committed to returning excess cash to shareholders while maintaining our investment-grade balance sheet. Also today, we announced that our Board of Directors declared a regular quarterly dividend of $0.50 per share payable on December 5, 2025, to holders of record on November 19, 2025.

Now I will cover some strategic updates. We believe we are well positioned to supply the growing needs on the West Coast. As I mentioned earlier, we recently completed the CARB project at our PSR refinery, which gave us the capability to produce more CARB gasoline or CARB components that we can ship to the California market. In addition to that, we are announcing a jet project at our PSR refinery this quarter that will give us the flexibility to produce more jet from diesel to supply the West Coast depending on what the market is calling for. This project will be complete and in service following the turnaround this quarter. Finally, yesterday, we announced we are evaluating a multiphase expansion of our midstream refined products footprint across PADD 4 and PADD 5.

This initiative is designed to address the increasing supply and demand imbalances in key Western markets, particularly Nevada and multiple markets in California, resulting from announced refinery closures on the West Coast. HF Sinclair believes its geographic footprint and current infrastructure provide an advantaged position to quickly and efficiently deliver refined products where the market needs are strongest. Subject to Board and regulatory approvals, the proposed multiphased expansion projects under review are projected to enable incremental supply of up to 150,000 barrels a day of product into various West Coast markets. The first phase would increase capacity by a projected 35,000 barrels per day to move supply from our Rockies production into Nevada and is targeted to be online in 2028.

This initial phase would include expanding the Pioneer Pipeline, a jointly owned pipeline with Phillips 66 from Sinclair, Wyoming to Salt Lake City, Utah and debottlenecking our wholly owned UNEV pipeline from Salt Lake City, Utah to Las Vegas, Nevada. These projects reflect HF Sinclair’s strategic focus on asset integration and value chain optimization of our refining, midstream and marketing businesses and are examples of how we can leverage our competitive advantages and geographic footprint to support our efforts to deliver accretive long-term growth well into the future. In closing, we remain committed to advancing our strategic priorities and believe our focus on reliability, integration and optimization will drive future growth across our businesses.

Looking ahead, we are constructive on the fundamentals of each of our businesses and in particular, believe the supportive refining backdrop positions us well as we head into 2026. With that, let me turn the call over to Atanas.

Atanas Atanasov: Thank you, Tim, and good morning, everyone. Let’s begin by reviewing HF Sinclair’s financial highlights. Today, we reported third quarter net income attributable to HF Sinclair shareholders of $403 million or $2.15 per diluted share. These results reflect special items that collectively decreased net income by $56 million. Excluding these items, adjusted net income for the third quarter was $459 million or $2.44 per diluted share compared to adjusted net income of $96 million or $0.51 per diluted share for the same period in 2024. Adjusted EBITDA for the third quarter was $870 million compared to $316 million in the third quarter of 2024. In our Refining segment, third quarter adjusted EBITDA was $661 million compared to $110 million in the third quarter of 2024.

This increase was principally driven by higher adjusted refinery gross margins in both the West and Mid-Con regions, which included small refinery RINs waivers granted by the EPA. Crude oil charge averaged 639,000 barrels per day for the third quarter, our second highest quarter, primarily driven by our continued reliability efforts. Crude oil charge averaged 607,000 barrels per day for the third quarter of 2024. In our Renewables segment, excluding the lower cost or market inventory valuation adjustment charge of $20 million, we reported adjusted EBITDA of negative $13 million for the third quarter compared to $1 million for the third quarter of 2024. During the quarter, we have recognized incrementally more in value from the producer’s tax credit, and we expect to capture additional incremental value in the fourth quarter of 2025.

Total sales volumes were 57 million gallons for the third quarter of 2025 compared to 69 million gallons for the third quarter of 2024. Our Marketing segment reported EBITDA of $29 million for the third quarter compared to $22 million for the third quarter of 2024. This increase was primarily driven by higher margins and high-grading our mix of stores in the third quarter of 2025. Our Lubricants and Specialties segment bounced back from the heavy turnaround workload in 2Q and reported EBITDA of $78 million for the third quarter compared to EBITDA of $76 million for the third quarter of 2024. This increase was primarily driven by improved mix and a FIFO benefit, partially offset by an increase in operating expenses. Our Midstream segment reported EBITDA of $114 million in the third quarter compared to $111 million of adjusted EBITDA in the same period of last year.

This increase was primarily driven by lower operating expenses as we continue to integrate our midstream and refining businesses, partially offset by lower throughput volumes in the third quarter of 2025. Net cash provided by operations totaled $809 million in the third quarter, which included $31 million of turnaround spend. HF Sinclair capital expenditures totaled $121 million for the third quarter of 2025. During the quarter, HF Sinclair issued $500 million of senior notes at 5.5% due 2032 in order to redeem our remaining 5.875% notes due 2026 and 6.375% notes due 2027. This allowed us to lengthen our maturities and reduce our weighted average cost of debt. As of September 30, 2025, HF Sinclair’s cash balance was approximately $1.5 billion, and we had $2.8 billion of debt outstanding with a debt-to-cap ratio of 23% and net debt-to-cap ratio of 11%.

Let’s go through some guidance items. With respect to capital spending for full year 2025, we still expect to spend approximately $775 million in sustaining capital, including turnaround and catalysts. In addition, we expect to spend $100 million in growth capital investments across our business segments. For the fourth quarter of 2025, we expect to run between 550,000 and 590,000 barrels per day of crude oil in our Refining segment, which reflects the planned turnaround at our Puget Sound refinery. We’re now ready to take questions from the audience.

Q&A Session

Operator: [Operator Instructions] Your first question comes from the line of Manav Gupta of UBS.

Manav Gupta: Congrats on a very strong print and a big jump in buybacks. I just wanted to start on this multiphase expansion on what you’re looking to target is PADD 4 and PADD 5. Sir, there are some other projects that are also trying to do something similar. And of course, you have a strong refining footprint. So I’m trying to understand what’s your competitive edge here? Why do you feel your project would be at an advantage compared to some of these other projects that are also looking to move product somewhere in the similar direction. So if you could talk a little bit about that.

Timothy Go: Manav, thanks for the question. And let me ask Steve to jump in right away.

Steven Ledbetter: Manav, yes, we’re excited to make this announcement. We believe that we’re in a pretty strategic advantaged place, both from a production and having infrastructure already in the ground that can be debottlenecked or expanded to bring product into a growing short in PADD 5 with the announced refinery closures in California. We think we can produce the product and deliver it at a competitive rate to compete with what is going to be a short and even compete with the growing imports. Whether or not it is the sole project or complementary to the other ones, we felt it was important to come to the market and be clear that we are looking to evaluate this and expand it. And we think we’ll be successful doing that.

Timothy Go: Yes. And Manav, this is Tim. I’ll just chime in on what Steve said. We really do think this is complementary to the other 2 pipelines that were announced. The other 2, we’re talking about really barrels from the Mid-Con and from the Gulf Coast really going in the South area towards the Phoenix area. We’re really talking Rockies barrels going on the northern side into Nevada. And so we believe this is a different type of project. We think it’s mostly with our equity barrels as opposed to open-season third-party barrels. And as Steve mentioned, we’re utilizing a lot of our existing infrastructure with — that we think will be quicker and have a lower cost to implement.

Manav Gupta: Perfect sir. On refining, strong quarter improvement and further capture, I just wanted to understand your near-term or medium-term outlook for refining margins. We are seeing tremendous resilience in margins and some global capacity outages, Russia and other places. So how do you see the refining macro playing out for the next 3 to 6 months, particularly in the 2 regions you are actively involved in?

Steven Ledbetter: Yes, Manav, we are very excited and pretty bullish on what the current market environment looks like. As you mentioned, it starts at a global macro basis. And today, I think year-over-year, we’re net about 800,000 barrels a day short. When you look at the capacity closures as well as being outpaced by demand. When it comes into the U.S., supply is up, mainly in jet and diesel with gas being down, but demand of distillate is really supportive and part of that is justified by some lower RD production that is not online as a result of what’s happened with the regulatory framework. In our region specifically, gas demand has been up slightly and diesel demand has been up. And we see particularly the distillate make in jet and diesel being very supportive through the end of the fourth quarter and into first quarter.

So we’re in max diesel mode, and that’s part of the reason why our capture has continued to be improved and some of the projects that were mentioned earlier further enable us to flexibly move between the right products to meet the market demands that we see happening. So yes, we’re pretty encouraged by the overall market structure for the next 6 months or so.

Timothy Go: Yes. And Manav, just taking a step back from more of a macro standpoint, we do think that in 2026, demand growth continues to outpace supply growth. Our numbers still show that true as what we saw here in 2025, especially in distillate, we see distillate continuing to be short and why you’re seeing, for example, in our West area, distillate demand at 5-year highs. Overall, we think the market is underestimating the impact of the Russia outages. We think those are significant and will take time to come back online. We think the market is underestimating the demand impacts that lower gasoline prices are having on increasing demand, and we think that’s a positive for refining. And then we think the market is not fully appreciating the low product inventories that we continue to operate at as a result of trying to keep up with demand.

People like to talk about high utilization. I think the low product inventories is a sign that despite the high utilization, we’re still as a global balance, trying to keep up with global demand.

Manav Gupta: So I agree with everything you said on the refining metal.

Operator: The next question comes from the line of Ryan Todd of Piper Sandler.

Ryan Todd: Maybe one starting out on small refinery exemptions. So just I guess a point of clarification on the quarter. So you had — there was $115 million benefit and was it a $56 million benefit? Are those incremental to each other? Or — how do we think about the clarifying of that? And then maybe at a higher level, I mean, can you talk about your view on the process from here given the guidance provided by the EPA earlier? How does this compare versus the process historically? And does this change your confidence on the ability to capture exemptions going forward?

Timothy Go: Yes, Ryan, this is Tim. Let me take a shot at it. So yes, the third quarter impact that we — that I mentioned in my prepared remarks, $115 million that are — you can say are basically directly a result of the granting of the SREs by the EPA. That impacts cost of sales and roughly translates to, call it, $0.47 in EPS. The $56 million is additive to that. It goes into cost of revenue. And what I consider that is more of an indirect benefit of basically buying and selling RINs in the marketplace based on our RINs position at the time. So this is more trading benefits associated with our RINs position and what we think our RINs positions will need to be in the future. We don’t disclose kind of what our strategy is or what we do.

But in the third quarter, we had $56 million associated with that, which translates to about $0.23 on an EPS basis. First — second of all, let me just say, we appreciate the White House and the EPA taking actions to recognize that small refineries face hardship and granting the SREs under the RFS program. As you know, there was a large backlog for many years that this administration took action on. Following discussions with the DOE and the EPA, we actually believe that the SREs that we submitted could be more. And so we added new and supplemental information and submitted or resubmitted applications for 5 refineries in our portfolio for the 2023 and 2024 years. So that’s Woods Cross, Parko, Casper, Tulsa and Artesia. So going forward, we believe we have 5 small refineries that were exempted from the RFS in the past, and we believe qualifying for SREs going forward.

And while we can’t quantify future outcomes or probabilities, we do believe we have considerable upside on a future run rate basis.

Ryan Todd: Good. Maybe a shift on refining margin capture. On the surface, it seems like you’ve gone from a number of — the industry went from a number of slight headwinds in the third quarter to what might be modest tailwinds in the fourth quarter, whether it’s from slightly widening crude differentials, lower crude backwardation, addition of butane blending, et cetera. You’re a month into the quarter, any thoughts on how you see the various trends in the market potentially driving margin capture in the quarter?

Steven Ledbetter: Yes. This is Steve. I’ll take that one. I think we don’t see a ton of help in terms of light to heavy differential widening. We do see some step-up in Q4. And as we’ve always talked about that we see towards the end of ’26, the differentials coming back into play. And we were very backwardated in the quarter. That looks to be flattening out. So the roll, which is very impactful for us, seems to be in a better position. And then I think, ultimately, we have a good make and mix of our distillate components over gasoline. And so as the jet and the diesel cracks remain strong relative to some of the macro elements that we’ve talked about, low inventories, an uptick on a colder winter, some of the geopolitical concerns that we have internationally.

Those all look good for us into the fourth quarter. And we look to go swell the gasoline pool with our butane blending that we have in the pipe. So overall, our Q4 looks for us to be more bullish than maybe we’ve seen in the past, and we’ll look to take advantage of that and have a good strong run for Q4.

Timothy Go: And Ryan, this is Tim. What I would just say is we’re pleased with the progress we’re making on capture. It’s all the things Steve talks about, we’re on pace for record jet production, premium, all the product mix opportunities that he’s talked about in the past. And that’s despite the headwinds that we’re seeing on not just roll, but on crude diffs in general. And so with the outlook that we have that crude diff should widen, WCS, WTI in particular, next year, we do think there’s some upside to continued improvement in capture.

Operator: Question comes from the line of Doug Leggate of Wolfe Research.

Douglas George Blyth Leggate: I’m sorry to beat up on this SRE issue. But just to be clear, so I’m curious, why didn’t you break out the $115 million and the $56 million as nonrecurring? I’m assuming they were in your realized margins? Or can you explain where they show up in the numbers?

Atanas Atanasov: Yes. Doug, this is Atanas. So the $115 million, which is the bulk of the impact shows in our — as a benefit to our cost of sales. And the reason that’s the case is because we had taken that expense in the past. So the company incurred those expenses recognized them in our previous EBITDA, lowered our EBITDA. And so we appropriately have captured those in our current EBITDA as an offset to that. The remaining $56 million is revenue, and it results from optimizing our RINs strategy. So that’s somewhat different than the reimbursement of what I call prior expenses. And therefore, that $115 million goes in our cost of sales as credit.

Timothy Go: And Doug, this is Tim. What I would just say is we don’t view this as a onetime event. We view this as we will be assuming the SREs continue to be in the RFS legislation that we will be entitled to this. And as I mentioned in my earlier remarks, even more of an impact than what we’ve seen today. So we don’t think it’s a onetime event.

Douglas George Blyth Leggate: No, I completely understand and completely agree with that. I guess — sorry, Tim, maybe I’m being thick as a rock here, but can you just clarify, is this the single quarter impact? Or is this a cumulative recovery of the SREs for all prior years?

Atanas Atanasov: Yes. This is cumulative based on the exemptions that we were granted.

Douglas George Blyth Leggate: But taken in the third quarter?

Atanas Atanasov: That’s correct.

Timothy Go: Yes. And I would just say that — Doug, the $115 million, which we talked about in terms of cost of sales is the cumulative impact of the SREs that are being granted. The $56 million is just related to specific actions that were taken in the trading markets in the third quarter that attribute to revenue and which we consider — we don’t talk about the buying and selling of crude or our crude inventory positions or our product inventory positions quarter-by-quarter. And we think that $56 million for SREs fits into that same category for RINs. We just normal course of buying and selling of RINs in the course of the quarter based on our overall annual strategy. So that’s how we view that. That’s why we break out the 2 separately.

Douglas George Blyth Leggate: Okay. That’s really helpful. So the $0.47 is a bit that’s nonrecurring then basically, if you want to call it that.

Timothy Go: You can call it that, depending on what your view of future SREs are, the $0.23 associated with the $56 million of revenue, we just think is ordinary course of business.

Douglas George Blyth Leggate: Great stuff. I’m sorry to have labored that. My follow-up is hopefully a quick one. Your capital spending run rate looks light relative to your full year guide. I guess, can you just reiterate for us what do you see as your sustaining capital for the total business, including turnarounds?

Atanas Atanasov: Yes. First of all, Doug, to the first part of your question, this is just timing of CapEx spend. So we still stand by the guidance that we indicated in our prepared remarks. With respect on a sustaining basis, on a go-forward basis, we see probably about $100 million of benefit on a go-forward basis relative to what we have said so far, but we’ll give more specifics later in the year.

Timothy Go: Yes. Doug, we’re not ready to give guidance yet. We’ll do that in December like we normally do. But just like we said on previous calls, we believe that we have now passed our catch-up maintenance period in our overall turnaround process. Even — we think we peaked in 2024, 2025 from a refining standpoint is actually lower on overall CapEx, but it’s kind of masked a little bit because we had a larger lubes turnaround, if you remember, earlier this year. So we do think looking forward into 2026 that we’ll see that substantial reduction in overall CapEx. We’ve talked about that before in terms of order of magnitude. Atanas is kind of giving you a ballpark, and then we’ll come out with further guidance when we put the final numbers out in December.

Operator: Your next question comes from the line of Phillip Jungwirth of BMO.

Phillip Jungwirth: Can you talk about how you look to finance these pipeline expansion projects? Any difference between the first phase and if you ultimately go through the other phases? And we normally think of these as like 5, 6x build multiple projects. Is that at least within the ballpark of what you’re thinking of?

Steven Ledbetter: Yes. Phillip, Steve. We always like to say let’s understand the project and the economics of the project and then figure out how we finance it. And we think we have multiple ways to do that, whether that’s due to liquidity on our balance sheet. We have some joint venture partner options and some extensions of that. But we’re not in a position to talk about how we’re going to go put the capital to work to make these things happen. If and when we get to FID, which we are not at FID. Again, this is evaluating a multiphase expansion to go get to those Western markets.

Timothy Go: Yes. And Phillip, this is Tim. While we need to make those decisions when the time is appropriate, we do think that the overall cost is significantly lower than the costs that at least are rumored or circulated to be on those other 2 lines.

Phillip Jungwirth: Okay. Great. And then could you touch on specifically Medicine Bow pipeline review just because this currently serves the Denver market, which is a good market for you. What would be the rationale for the reversal, recognizing this isn’t in the first phase of projects you’re evaluating?

Steven Ledbetter: Yes. So as you know, there’s an expansion that is coming to the Denver market to be online in Q3 ’26. And that pulls barrels out of the Mid-Con. We supply some of that. We also supply some of that from the Rockies. And so that goes down our Medicine Bow pipeline mainly. That 35,000 a day that gets into the Denver market is going to be less value once the expansion comes on bringing more barrels into Denver, which is why we are planning to go make this first phase happen, which is up to 35,000 barrels a day to move those barrels that we’re getting into Denver West into higher graded markets. So depending on what happens, the timing of that, as we mentioned, we believe Phase 1 could come on in 2028. But that’s really just to manage the overall value of that market.

I think it’s going to be a bit more oversupplied later in the year. So that addresses that first situation. Longer term, in the various phases of the project to move up to 150,000 barrels a day, we would reverse Med Bow and potentially expand it to go get more product out of a lot of equity production in our Mid-Con to move those barrels into PADD 5, both Nevada and eventually into California.

Timothy Go: Yes. And Phillip, today, Medicine Bow is primarily moving equity barrels of ours, and we anticipate that continuing even through past the expansion.

Operator: Your next question comes from the line of Paul Cheng of Scotiabank.

Paul Cheng: I think you sort of answered that question. But in the first phase of your proposed midstream expansion or upgrade over there, the 35,000 barrels per day, should we assume that it’s all going to come from your equity barrel? And so that from that standpoint, the first phase at least is going to be a goal because you don’t need other people to come in? Or that do I get it wrong?

Steven Ledbetter: No, Paul, I think the question was is the first phase all equity barrels. I would say a good portion of that would be equity barrels. Again, we will follow all the requirements that are laid out from the Interstate Commerce Act and the Federal Energy Regulatory Commission to make fair available for all. But a good portion of those barrels from origin point to destination point would be equity barrels.

Paul Cheng: Yes. I guess my point is that should we assume that the Phase 1 regardless what’s the open season outcome is a goal because that you will be sufficient of an anchor shipper that you actually don’t need other people?

Steven Ledbetter: Yes. I think that is a fair assumption. Again, we have not taken FID. We anticipate an FID decision by midyear 2026. And we do believe that we have enough equity production given the dynamics that I just mentioned to go support this project.

Paul Cheng: Right. And what kind of tariff that we should assume?

Steven Ledbetter: Sorry, can you repeat the question there, Paul?

Paul Cheng: What kind of tariff that we should assume? What is the proposed tariff?

Steven Ledbetter: Yes. So again, we’re not commenting on tariff structure at this point. Once we get closer to take an FID, we’ll come back to the market with more definitive set of potential guidance items and economics.

Timothy Go: Yes. But we do think, Paul, that we haven’t calculated tariff yet, as you know, but we do think that the overall cost and timing of what we’re proposing can be quicker and more efficient than what others have announced just because of the existing infrastructure we have. And then on the equity barrel comment, the Pioneer Pipeline, as we talked about, is a joint venture between us and Phillips 66. And so while we can’t speak for them, we would expect them to probably have some equity barrels to put on the line as well.

Paul Cheng: Okay. And the second question maybe is that you can share with us that how is the lubricant market looks? And also that — I know that you guys have continued to look for the bolt-on acquisition over there. How is that market condition also looks?

Matt Joyce: Paul, it’s Matt Joyce. The market is continuing to perform at a pretty healthy rate. You’ve seen our quarterly performance. We returned to a historic run rate, and we were really pleased with that. And the teams continue to execute on our strategy of forward integrating our base stocks into finished and specialty products, and you’re seeing the benefit of a diverse portfolio that we serve with our customer base today. Looking forward, we’re just continuing to manage and watch any sort of tariff upheaval that we may have. We’ve seen some slowdowns in forestry in Canada. But on the long of it, we’re pretty confident that fourth quarter will be in and around our traditional run rates.

Paul Cheng: How about on the M&A market and…

Matt Joyce: With regards to the M&A — yes, we don’t have anything to speak about today, but we continue to explore options and opportunities that are interesting to us and help us build on our portfolio and build on our competencies and in particular, in the U.S. markets where we’re looking to continue to grow at a nice pace.

Timothy Go: Yes, Paul, I would just say, overall, we’ve talked about our lube strategy. We want to grow our finished business. We want to reduce our base oil length, and we want to rerate this business to a higher trading multiple based on the specialty business. We think what Matt and his team are doing is executing that strategy. We think there are opportunities to do some inorganic bolt-ons that will help us accelerate that strategy. And we think, as we’ve talked about, we’ve been a consolidator in this space in the past, and we think there’s opportunities for us to continue that opportunity.

Paul Cheng: Tim, I don’t know if you can comment on that. But one of the major integrated oil company, they’ve been trying to sell their lubricant business and the media rumor is that they have been in some difficulty to get the price they want. Does it signal the valuation multiple on that business has changed? Previously, we all generally assume 10 to 12x EBITDA. Have you seen in the marketplace that, that valuation has changed?

Timothy Go: Paul, we obviously can’t comment on specifics because we don’t know what’s going on. I think you’re probably referencing the Castrol process that has been in the news. All I can say is that we are quite different, our business than the Castrol business. Castrol is a much more global business focused primarily around passenger cars, where our business is much more North American-based and focused on the industrial side of the business. So I don’t think I can comment on any of the other kind of speculations around the process they’re going through, Paul. But what I can tell you is that we believe our business, again, with our strategy is a strong industrial base business and that we can continue to grow it and increase its trading multiple by growing the finished side of the business and reducing the base oil length.

Operator: Your next question comes from the line of Matthew Blair of TPH.

Matthew Blair: Could I circle back to the comment that you resubmitted SRE applications for, I think it was 5 refineries. Parko, Tulsa and Artesia are all well above 75 a day. So could you talk about how these refineries will be eligible? And I guess, going forward, would you plan to run these refineries at much lower utilization to be below 75 a day?

Timothy Go: Yes, Matthew, let me just clarify on that. The Parko refinery, as you know, is actually can run higher than the 75,000 barrels a day, but it’s close. And so yes, I think we would take that into consideration each year as we think about overall margins and overall product demand, and we’d factor that into our decision in terms of whether to run above a certain amount or not. The Tulsa and the Artesia refineries, as you know, are actually 2 separate refineries that are — that we tend to report as one, but are actually 2 physically separate refineries. And there are other refineries, as you may know, that received small refinery exemptions that operate in a similar fashion. And so that’s what we’re talking about on those 2 refineries.

Matthew Blair: Okay. Okay. Because you’re right, because Tulsa was a combination of — I think it was like a Sunoco and some other plant. Okay. That’s helpful. And then I think it’s interesting you’re making investments in the Puget Sound refinery at the same time that there’s a lot of proposals for more product headed to PADD 5. Could you talk about where Puget Sound would stand on the cost curve in terms of getting product into California? And I guess, what gives you confidence that these are going to be good long-term investments?

Steven Ledbetter: Yes, Matt, this is Steve. As we’ve been watching the market dynamics in PADD 5 play out for quite a while. There’s a good amount of jet that is imported today into California and PADD 5. And our — one of our advantages of the Puget Sound refinery is our dock capability and access. So these projects are intended to provide flexibility to meet the demands of whatever is happening in the marketplace, including making CARB gas or the unfinished components that go into CARB gas, and we’ve been successful in improving that, and you’re seeing that in our capture on the West. That’s partially attributable to that. And then moving this next project to be able to swing barrels from diesel to jet. We believe that, that jet short will continue and growth will continue of that overall transport fuel stream.

And so that gives us the availability to either place barrels in the local Puget Sound market or export them, getting them into California, but also into other markets that we found success into LatAm, et cetera. So this is really about product flexibility, which gives us a competitive advantage as the market dynamic plays out. And we’re seeing the signs, and we’re putting the capital to work — small capital to work to go make these adjustments that are very accretive for us in the long run.

Timothy Go: Yes. And Matthew, this is Tim. I’ll just emphasize a couple of things that Steve said. These are small projects. They fit within the guidance that we’ve been talking about in terms of our growth capital that we guide to each year. And so we’re not talking significant the CapEx required. And it’s really about flexibility, as Steve mentioned. This gives us the flexibility. For example, the jet project that I mentioned, it gives us the flexibility to make jet or diesel depending on what the market is calling for and depending on whether the arb to California is open or not, right? So we — it’s going to give us flexibility to take more advantage of the different dynamics and the different arbs that are open at the time.

The CARB gasoline project is the same way, just gives us the flexibility to take advantage of that. And quite honestly, this pipeline project that we’re talking about, it’s really all about flexibility. It’s going to give us the ability to move barrels from the Rockies over to Nevada or not, just depending on what the market looks like.

Operator: Your next question comes from the line of Neil Mehta of Goldman Sachs.

Neil Mehta: One tactical question, one strategic. Just tactically, the Q4 guide, the $550 million to $590 million of crude charges, lower than it’s been in a while. And I think you cited the turnaround at Puget Sound. Anything else that we should be thinking about there? Or is there some conservatism there?

Steven Ledbetter: Neil, this is Steve. The guidance reflects our planned turnaround at a large refinery in Puget Sound, as you know, that started very late in September. But in addition, we were — we pushed out a few small maintenance elements into a lower margin environment in Q4 to take advantage of the market in the higher margin environment in Q3. So the combination of those 2 get us to this $550 to $590 crude guidance, nothing more to it than that.

Neil Mehta: Okay. And there any early thoughts on ’26 turnarounds as we think about next year?

Valeria Pompa: This is Valeria. So our turnaround guidance will be coming out generally, as we said before, we are through the peak and continue — we’ve continued to level out our turnaround costs and our turnaround events. So next year, guidance will be coming out soon. I would expect lower — anticipate lower cost and fewer turnarounds.

Neil Mehta: Okay. Perfect, Valeria. And then the follow-up, Tim, just on return of capital, a very nice number this quarter. You’ve talked about in ’26 and beyond, you want to get to dividends plus buybacks being 50% or higher of net income. So just talk about how you’re thinking about return of capital levels on the go forward.

Atanas Atanasov: Neil, this is Atanas. Thanks for your question. With respect to our payout ratio, really that 50%, we look at it as a minimum payout ratio, which we’ve exceeded consistently over the years, including this year. And our priority remains to — shareholder return of capital remains a priority for us. And what does that translate into? Any excess cash flow that we generate over and above our nondiscretionary spend, which is our dividend, our commitments to safety and reliability, highly accretive organic growth. Anything over and above that, our target is to return to the shareholders.

Timothy Go: Yes. And Neil, I’ll just chime in with what Atanas said. We evaluate inorganic opportunities to grow. We evaluate these organic growth projects that we just talked about against our other options of returning cash to shareholders and look and choose to see what is the best decision for the business long term. So we’re factoring all that in as we do our capital allocation strategy. But I will just point to our historical practice of returning cash to shareholders. And if you look back over the last 3 or 4 years, we’ve been 16% in ’22, 12% cash returns in ’23, 16% cash returns in ’24, and we’re 11% here in the third quarter, 7% year-to-date in 2025. And so I think our track record of returning cash to shareholders is strong.

Operator: Your next question comes from the line of Jason Gabelman of TD Cowen.

Jason Gabelman: Yes. I’m going to pick up on that last question, and I understand the kind of framework about returning cash to shareholders. But if I look year-to-date, it does seem like cash has built approaching $1 billion and debt has remained, I guess, somewhat stable. So it seems like there’s been some build of excess cash. So should we expect a catch-up where more of that excess cash is returned? Or are you looking to stockpile cash for another reason? Or is there something else going on there?

Atanas Atanasov: This is Atanas. Thanks for your question. We’re not looking to stockpile cash and if you look at our — increase in our cash balance, really a lot of the build occurred in the third quarter, which is a very strong quarter. Our goal is to return our excess cash to shareholders. We don’t guide with respect to timing, but expect more to come in terms of capital returns.

Jason Gabelman: Okay. And then my other question is on the SRE topic, which I know has been hit a few times. But I just want to ask a couple of clarifying questions. First, can you break out the margin benefit to each one of your regions so we get a picture of what the underlying margin was for the quarter, excluding the SRE benefit? And then to be clear, do you have now excess RINs on the balance sheet that you can sell back into the market? Or does that kind of $50 million or so that you mentioned get you into a place that you’d want to be to manage your RIN exposure moving forward?

Timothy Go: Yes. Jason, this is Tim. I appreciate both of those questions that you’re asking, but we don’t provide that level of detail for either of those questions. So SRE breakdown across the regions or by plant, we’ve just never done that in the past, and we don’t believe we — it’s in our best interest to do that going forward. And then we’ve never talked about our RINs position, whether we’re RINs long or RINs short and — just from the very beginning. And while we talked about it, whether to disclose that or not, we decided it’s still in our best interest not to disclose that.

Operator: I’d like to hand the call back to Tim Go for final remarks.

Timothy Go: Thank you, Ellie. Before we close, I want to point out that our business is much different from just a few years ago, not just in acquired assets like with the Puget Sound Refinery, Sinclair, HEP, but it’s also different in culture and performance. All of these are proof points that our strategy is working and enabling us to generate free cash and deliver strong shareholder returns. Looking ahead, we are constructive on the fundamentals of each of our businesses, including our renewable diesel business. And as always, our priorities remain the same to; one, improve our reliability; two, integrate and optimize our portfolio of assets; and three, return excess cash to our shareholders. Thank you for joining our call. Have a great day.

Operator: This does conclude today’s teleconference. Please disconnect your lines at this time, and have a wonderful day.