Marathon Petroleum Corp (MPC) — Q3 2025 Earnings Call Transcript

Welcome to Marathon Petroleum Corporation's Third Quarter 2025 Earnings Conference Call. The slides that accompany this call can be found on our website at marathonpetroleum.com under the Investor tab. Joining me on the call today are Maryann Mannen, CEO; John Quaid, CFO; and other members of the executive team. We invite you to read the safe harbor statements on Slide 2. We will be making forward-looking statements today. Actual results may differ. Factors that could cause actual results to differ are included there as well as in our SEC filings. With that, I will turn the call over to Maryann.

Thanks, Kristina, and good morning. I'd like to take a moment to recognize Mike Hennigan. At the end of the year, Mike will be stepping down as Executive Chairman. Mike's guidance has been tremendously valuable to our Board, to me and our entire leadership team. We thank him for his service as well as all of his contributions. He will be missed. In the third quarter, we delivered strong cash generation of $2.4 billion. Utilization in the quarter was 95% as we executed our planned refinery turnarounds safely and on time. Our team delivered 96% capture despite significant market-driven headwinds. Year-to-date, capture is 102%. This compares to the prior year's level of 95%. We believe this demonstrates our commitment to deliver sustainable, improving commercial performance in varying market conditions. We have generated $6 billion of operating cash flow, excluding changes in working capital, and have returned $3.2 billion to shareholders through the third quarter. Last week, we announced a 10% increase to MPC's dividend, reflecting our confidence in our business outlook. We believe that we should be able to lead in cash generation through cycles, delivering peer-leading results. In October, our blended crack was over $15 per barrel, which is seasonally strong and more than $5 per barrel or 50% higher than the same time period last year. Diesel and jet demand are up modestly across our system, while gasoline is flat to slightly lower. The product inventory draws reported last week signal strong demand. Gasoline and distillate inventory levels remain below five-year averages. Current market fundamentals are indicative of tightness in supply and supportive demand, which we believe will persist into 2026. Throughout the quarter, we completed several transactions advancing our strategic objectives and optimizing our portfolio. We sold our interest in an ethanol production joint venture. As the partner's strategic goals evolved and diverged, an opportunity came for MPC to exit the partnership at a compelling multiple. MPLX acquired a Delaware Basin sour gas treating business and the remaining 55% interest in the BANGL NGL pipeline. These transactions further MPLX's growth profile. MPLX increased its distribution this quarter, reflecting conviction in its growth outlook. We now expect to receive $2.8 billion annually from MPLX. MPLX continues to target a distribution growth rate of 12.5% over the next couple of years, which would imply annual cash distributions to MPC of over $3.5 billion. We are driving value and positioning MPC to be industry-leading in its own capital return program. With our competitive integrated refining and marketing value chains and durable midstream growth driving increasing distributions from MPLX, we believe MPC is positioned to deliver industry-leading cash generation through all parts of the cycle. Now I'll hand it over to John to discuss our financial performance.

Thanks, Maryann. Moving to third quarter highlights. Slide 4 provides a summary of our financial results. This morning, we reported third quarter adjusted net income of $3.01 per share. We delivered adjusted EBITDA of $3.2 billion and generated $2.4 billion of cash flow from operations, excluding changes in working capital. MPC returned over $900 million to shareholders during the quarter, with repurchases of $650 million and dividends of $276 million. Slide 5 shows the sequential change in adjusted EBITDA from the second to the third quarter and the reconciliation between adjusted EBITDA and our net results for the quarter. The third quarter adjusted EBITDA of $3.2 billion was largely consistent with the previous quarter. R&M segment results on Slide 6 were strong with adjusted EBITDA of $6.37 per barrel. Our refineries operated at 95% utilization, processing 2.8 million barrels of crude per day, and several of our refineries set monthly throughput records in the quarter, including Robinson in Detroit and Anacortes on the West Coast. Mid-Con margins improved sequentially but were offset by declining margins in the U.S. Gulf Coast and the West Coast. Turning to Slide 7, third quarter capture was 96%, facing challenges in the West Coast and the Gulf Coast. The difference between jet and diesel prices narrowed. We encountered lower clean product margins and inventory changes affected capture. Downtime at our Galveston Bay refinery resid hydrocracker also reduced capture by almost 2% across the entire system, significantly impacting our Gulf Coast results. Slide 8 shows our Midstream segment performance for the quarter. Segment adjusted EBITDA rose 5% year-over-year. MPLX is executing its growth strategy focused on natural gas and NGL value chains, remaining a reliable source of cash flow growth for MPC. Slide 9 presents our renewable diesel segment performance for the quarter. Our renewable diesel facilities operated at 86% utilization, demonstrating improved operational reliability. Margins were lower in the third quarter as higher diesel prices and RIN values were more than countered by increased feedstock costs. We will continue to optimize our renewable operations, utilizing their logistics and pretreatment capabilities. Slide 10 outlines the changes in our consolidated cash position for the third quarter. Operating cash flow, excluding changes in working capital, was $2.4 billion. In the third quarter, MPLX completed acquisitions exceeding $3 billion and issued debt related to these acquisitions for financing. Additionally, as we discussed last quarter, our second quarter share repurchases were influenced by the anticipated proceeds from the sale of our interest in the ethanol joint venture, which concluded in July. By the end of the quarter, MPC had nearly $900 million in cash and MPLX had about $1.8 billion in cash. Turning to guidance on Slide 11, we are presenting our fourth quarter outlook. We anticipate crude throughput volumes of 2.7 million barrels per day, reflecting 90% utilization. The Galveston Bay resid hydrocracker is expected to reach full operating capacity by the end of the month, allowing us to optimize our Gulf Coast system. Turnaround expenses are projected at approximately $420 million in the fourth quarter, primarily in the West Coast. We are completing our multiyear infrastructure improvement project at our Los Angeles refinery in the fourth quarter, with startup planned to align with the conclusion of scheduled turnaround work by the end of this month. These enhancements are designed to boost the competitiveness of our Los Angeles refinery and ensure we remain one of the most cost-effective players in the region for years ahead. Operating costs for the fourth quarter are estimated at $5.80 per barrel. Distribution costs are projected at around $1.6 billion, and corporate costs are expected to be $240 million. With that, let me return it to Maryann.

Thanks, John. We delivered a strong quarter in Refining and Marketing. Safe and reliable operations are foundational. Operational excellence is integral. The commercial team is optimizing decision-making as we leverage our value chains and capture opportunities the market presents. We are optimizing our portfolio through strategic investments. Fourth quarter refining cracks have started out stronger than seasonal averages. Current fundamentals highlight the market tightness and support our enhanced mid-cycle outlook into 2026. Our integrated value chains and geographically diversified assets position us to lead in capital allocation and offer a compelling value proposition to our shareholders. Let me turn the call back to Kristina.

Thanks, Maryann. As we open your call for questions, as a courtesy to all participants, we ask that you limit yourself to one question and a follow-up. If time permits, we will reprompt for additional questions. Shirley, could you please open the line for questions?

Maryann, congrats on the Chairmanship as well. The question I had was really around capture rates in the quarter. We've gotten so used to you putting up north of 100%, 96% felt a little softer. And I think you called out some stuff in the script a little bit about the RHU, but also some West Coast dynamics around diesel and jet. I was wondering if you could unpack that for us here.

Yes, certainly. Thank you for your question, Neil. In the quarter, we achieved a capture rate of 96%, which is down sequentially from 105% in the second quarter. The West Coast was the main factor affecting this change, contributing over 50% to the variance. We experienced a significant drop in clean product margins, about 40% in that region, and the premium of jet fuel over diesel decreased, shifting from a benefit to a drawback. Additionally, secondary product margins presented challenges. Thus, the West Coast was primarily responsible for the sequential decline in capture rates. Regarding the RHU, as mentioned by John and Mike in the last earnings call, its downtime affected our performance this quarter, along with the dynamics of jet to diesel. Year-to-date, our capture stands at 102% through the third quarter, compared to 95% in the same period last year. We believe that the sustainable changes we have implemented over the past few years will continue to benefit us. While we faced some challenges, the fourth quarter is typically our strongest, and we do not anticipate it being different from previous quarters. Now, I'll hand it over to Rick for further insights, Neil.

Yes. Neil, just a couple of comments additional to Maryann. So we are off to a good start in the fourth quarter. We've seen the jet and product margins go right back to normal levels. So that's quite encouraging. We're one month through the quarter, but signals look promising. And the other item that I'd add on 3Q specifically is we built butane inventory in 3Q, and we're heading into blending season. So as we go into 4Q now, the building of inventory hit that we took in 3Q will be a tailwind in the fourth quarter. So we look to be in really good shape here, Neil, heading into the fourth quarter.

Yes. And then the follow-up is just on return of capital. It was a little bit lighter from a buyback perspective than, again, I think where the Street was modeling. Can you just talk about how you're thinking about the share repurchase on the go forward?

Yes, certainly. happy to do so, Neil. Thank you. No change in terms of the way that we view our primary return of capital using share buyback. As you know, essentially, what we've said and you heard, we've announced a 12.5% distribution increase at MPLX, and that brings about $2.8 billion back on the MPC side. So, our ability, as we said, given the differentiation with our midstream distribution should allow us to lead in capital returns. And you can see that on a year-to-date basis, shared those statistics there with you. No change, Neil, in our ability to continue to lead in share repurchase, no change in the way we view it. And it will be, as you know, the primary return of capital going forward.

So I'm going to start with the West Coast. We understand capture can move around a bit. It should not matter that much. But when we look at the West Coast, one big refinery has closed in your backyard. Another one will most likely close in the next three to four months. And yes, there are some product pipelines that might show up, but they might not show up for three years. So I'm just trying to understand, given the setup and the upgrade you are doing at your refinery, could we see you generate above mid-cycle margins on the West Coast for next maybe 8 or even 12 quarters? Can you talk a little bit about that?

Yes. Manav, this is Rick. So you point out some very dynamic items that are happening in the West Coast. Let's maybe walk through them one by one. So, as we look today, I think you're well aware, we're looking at a $40 crack today. And we've got one closure that's happened, one that appears that it may happen early next year. And this is just simply supply and demand. The market is efficient and the market is responding and showing you that the market is efficient. So when we look at the overall market, there's a couple of lenses I'd like you to view it from is we optimize not only the West Coast but along with the Pacific Northwest. So when we look at our system, it's no different than what we look at when we look at our Mid-Con region, which, as you know, is highly integrated, so is the West Coast and Pacific Northwest. What I mean by that, Manav, is when you look at Anacortes and you look at Kenai and you look at L.A., which we have invested in and continue to invest in as the largest, most dynamic, complex, efficient refinery in the California region, we believe we have a competitive advantage that not only exists today but will exist far into the future. And when you may back away even from L.A., Manav, and you look at Anacortes and Kenai, we're able to optimize those two refineries to fill the short that is in the San Francisco region. So all three of those assets are complementary to one another. In terms of the pipelines that are rumored to come into the region, I would say that's a big if. I would say those projects are ambitious and at earliest might be 2029. But when we look at the overall structure of the market, Manav, the incremental barrel coming into the marketplace continues to be a waterborne barrel. They have a timing and a transportation cost that we can and will beat all day long, and that does set the market and that, therefore, is an incredible incremental advantage to Marathon Petroleum, not only for the West Coast, but for the Pacific Northwest.

Manav, it's Maryann. I would like to add to Rick's thorough answer to your question. Our LAR project is scheduled to launch in the fourth quarter, aiming to meet NOx reduction emission standards while also enhancing efficiency and improving EBITDA. This project will also be advantageous for us in 2026, as it launches in the fourth quarter. This is another benefit for the West Coast.

Manav, I'd like to highlight that we have a significant advantage in feedstock on the West Coast. Comparing now to six months ago, particularly with the recent closure and another one coming in 2026, we're purchasing more local California crude than ever before, at double the amount we had previously. This feeds into why we're so committed to California; our feedstock advantage is substantial and helps us compete effectively against waterborne imports.

Perfect. My quick follow-up here is I'm going to focus a little bit on MPC dividend growth. Maryann, you provided a very detailed response to John McKay's question on the MPLX call. And as you walk through the growth pipeline of projects in MPLX, it's pretty clear that MPLX could support distribution growth of 12.5% for two or maybe even three years. Now when we couple that with the buyback and how that lowers the dividend burden, would it be fair to say that at this point, if refining cracks hold even mid-cycle or maybe slightly below mid-cycle, MPC is in a very good position to raise its dividend by 10% for the next couple of years, at least, supported by distribution from MPLX and the buyback that lowered the dividend burden?

The answer to that is yes. Over the last few years, we've taken out more than 50% of the equity through our share buyback initiative. For the last three years, we've raised the MPC dividend by 10% annually, and before that, it was raised by 30%. As you pointed out, we remain committed to using our share buyback as a key strategy to return capital to our shareholders, which will continue to reduce our share count. This is supported by our mid-cycle environment, and we believe it makes the dividend opportunity possible for the next several years at MPC. Additionally, we anticipate a couple more years of 12.5% growth as we achieve mid-single-digit growth. Both of these factors should be very supportive.

Maryann, congrats from me as well. Please pass our best regards on to Mr. Hennigan as he officially moves into retirement. I have two quick ones, hopefully. Can you address the CapEx specifically for refining relative to the guidance you gave at the beginning of the year? It seems you're running a little hot. I'm just wondering if something is changing there or if it was cadence or if there's some other explanation as to why we should or should not be paying attention to that. And my follow-up is a simple one. I want to hark back to the balance sheet and buybacks and just get your simple perspective. Obviously, we've had extraordinary share performance from MPC. One could argue elevated valuations certainly elevated margins for the time being, and a slowdown in the buyback, I believe the slowest in the fourth quarter of 2021, I think, might be weighing on your shares today. So my question is simply, are you prepared to lean on your balance sheet to buy back your shares?

So, Doug, let me try to address some of those, and then I'll pass it to John to give you a little more color. I think we've probably said this before, but at the risk of maybe repeating, no one quarter or for that matter, any one given month is meant to be indicative of the way that we view share buyback. And frankly, if you look consistent with what we've shared, we are comfortable with roughly $1 billion on our balance sheet. Last quarter, for a lot of reasons, we ended lower than that. And you know we delivered strong share buyback performance. So, again, no one quarter should be indicative of how we view that. We remain committed to using share buyback as the element of return of capital, and we'll consistently do that. As I shared earlier, the benefit of that growing distribution from MPLX two years now at 12.5% and growing should also be supportive for us to be able to lead in the return of capital. I think the other part of your question was, would we use our balance sheet? In other words, would we take on debt? And we don't see taking on debt at MPC to buy back stock as something that we would do. Having said that, we do believe that our margin delivery will allow us to continue to lead in share repurchases. I'm going to pass the question back to John, and he can give you some color on capital, and then I'll follow up.

Doug, so yes, certainly looking at capital, I think what you're seeing there is as we're looking across our value chains and where we're positioned, we're finding really good opportunities to drive investments, whether it's operationally or commercially to drive reliability, drive mix and yields and really drive margin and capture. So I think that's partly what you're seeing in the numbers this year. And maybe I'll turn it back to Maryann because I know she had a comment to follow up there as well.

Yes, thanks. And thanks, John. The one thing that I wanted to be clear, we have not given guidance yet for 2026. And as you know, consistent with the way that we always have, we'll provide you full-year guidance. But I think as you are thinking about planning, you should assume that 2026 capital will be below 2025. And we'll give you incremental color on the next quarter call, but you should assume capital will be below 2025.

Maybe we could drill into this jet to diesel dynamic because it seems like it was pretty influential. And you said it's normalized now. But if you just look at the shape of sort of what underlying crack spreads did for the quarter, it was volatile, right? There were a few like sort of big pulses higher and then it came in. I mean how much of the, I guess, abnormal jet to diesel relationship in the quarter would you attribute to kind of unusual volatility across the array of commodities versus something more structural or any other macro effect you want to call out?

Sam, it's Rick. So we have not seen a volatility between the jet, diesel differential to this extent. I can tell you throughout the length of my career, Sam, it was unprecedented. And I really think it was a combo of inventory and supply driven. We did have some inventory switches on the diesel side and then jet took the opposite position, and it just caused an imbalance for the better part of a month, 1.5 months, and it's certainly corrected itself, but we do not see it structural whatsoever.

Okay. That's helpful. And then maybe taking a step back, just to the macro because nobody has asked about demand yet given all the moving parts of the quarter. But what's interesting about this environment is that a lot of indicators that normally correlate to demand don't look that strong. Consumer sentiment is very low. PMIs are basically below 50 everywhere. And yet refining margins are still very high. And so I guess this is a question about kind of the conditions you're seeing today and what that means for kind of what a real mid-cycle margin environment looks like. It looks very much like the mid-cycle might be lifting higher based on kind of long-term capacity trends and indicators today, but would love your perspective on that.

Yes, Sam. Let me begin by saying we believe we have some of the best indicators in the United States due to the breadth and depth of our refining and marketing business. Each day, we receive demand signals. While there are numerous surveys available, we rely on hard facts and feel quite optimistic about what we are observing both now and in the future. Looking at the broader picture, global demand continues to rise, with organizations like the IEA and OPEC consistently revising their global demand forecasts upwards by several hundred thousand barrels a day. Closer to home, in terms of diesel and jet fuel, we are experiencing modest growth, which we noticed in the third quarter and are seeing again at the start of the fourth quarter. Gasoline demand varies by region, but overall it appears to be flat or slightly lower than the previous year, which we interpret as a very positive signal. As you know, we are focusing on diesel production due to the favorable diesel crack spread, and we are observing strong demand not only in over-the-road transportation but also in container shipping and during harvest season. We are receiving many positive signals that make us very optimistic about the near term. Additionally, if I look a bit further out, we are witnessing some disruptions in certain regions causing crack spreads to widen more than usual. For example, there are operational challenges on the West Coast along with some facility closures. In the Mid-Continent area, we are seeing unusually high crack spreads for this time of year due to these disruptions. To me, this illustrates how tight the market is from a U.S. perspective. On a global scale, incidents like drone attacks are impacting the market, with a recent article I read about a Russian refinery being targeted causing turmoil, particularly for diesel. We are successfully exporting diesel to Europe as the Russian product export landscape has been significantly disrupted, which benefits U.S. refiners like us with strong export capabilities from the Gulf Coast.

Maryann or maybe this is for John. You guys have mentioned that the third quarter, one of the impacts on the margin capture is on butane inventory build. Can you give us some idea how big is that impact, whether it is in the dollar per barrel or percent of capture rate? Secondly, I want to go back into California. With the new pipeline proposal and all that, we know that, I mean, not all of them probably will be materialized, but I suppose that at least one may be materialized. And so how you guys will position yourself? And also that I think Rick has said that you believe the main import avenue is going to be waterborne. Will MPC be an active and aggressive player in that market and already organized a range of imports coming in given your L.A. logistics that you will be able to easily bring imports?

Paul, it's John. I'll start with the inventory question you had on capture. Rick mentioned earlier that there were several inventory changes that affected capture. One that Rick pointed out is expected every season as we prepare LPGs for blending season. We also built up some VGO ahead of FCC turnarounds, which bridged the quarter, along with some other factors as well, Paul. When you add all those up, it results in a significant effect on capture from one quarter to the next.

John, can you quantify? Is it around 3%, 4%, or 1%, and can you provide any additional details?

Yes, it's probably closer to 3% to 5%, Paul.

Paul, it's Rick. Let me address the pipeline question. As you've noted, there are several announcements pending. If one of them proceeds, particularly from the Mid-Con, it would be very beneficial for us. Experts estimate that between 100,000 to 200,000 barrels per day could be produced from the Mid-Con. We currently process about 800,000 barrels per day at our four plants sourced from that region, so we would significantly benefit from those additional barrels. However, I want to emphasize that this is contingent on several factors, including the yet-to-be-determined tariff for a new pipeline that would span approximately 1,000 miles across multiple states, and potentially involve different governmental administrations. This introduces uncertainty regarding costs and the feasibility of the project. But if a pipeline does emerge from the Mid-Con, we view it positively. Regarding the waterborne market, we have a solid competitive edge with our assets in L.A. and the Pacific Northwest. That said, if we identify a trading opportunity in the waterborne market, we will evaluate it as we do with other markets. However, I would note that our primary focus remains on maximizing the value from our fully integrated operations between the West Coast and Pacific Northwest.

Okay. So if I interpret you correctly, it means that you do not have planned to be a consistent and active importer of product into California market?

Paul, I wouldn't tell you if I was or wasn't, but it's a nice try, Paul, but I won't tell you that. We look at every opportunity to make money.

You're welcome, Paul. Maybe just one last wrap on the capture question, just to be sure. As you know, over the last several quarters, one of the things that we've been trying to do is continue to provide color on the things that are sustainable, which Rick and his team are working on to provide that sustainable excellence in terms of our commercial performance. And the lion's share of that change that we talked about this particular quarter was really market-driven. That's the volatility I talked about the jet versus diesel, the clean product margins, et cetera. And then as you know, as a result of that volatility, then the secondary product headwinds can be significant for us. And you know that they are obviously largely not within our control as well. The one that was, and that's where we've shared with you the progress was the Gulf Coast part of that, and that was the downtime that we experienced on our RHU and Mike shared with you the intent to bring that back up and obviously expect to have that operational for much of the fourth quarter. That would be the piece that I would tell you was sort of ours. But largely, when you look at the change quarter-over-quarter, it was largely market-driven for all of the reasons that I shared. I hope that's helpful for you as well.

Building off of Rick's comments about how Mid-Con product margins would likely improve if Kinder and Phillips 66 pipeline gets built. Is the same true for PADD 4 if Dyno project goes through considering that you do also have a Salt Lake facility and given the relatively low CapEx and minimal looping that, that would require, would that also improve netbacks for you in that region?

That one is a little tougher to call, Theresa. This is Rick, by the way. But I would tell you where we see our significant advantage in Salt Lake City is we are the largest refiner in Salt Lake, and we have a significant feedstock advantage with the amount of black and yellow wax we run in that region. And so regardless if something comes in and/or out of that region, the project that you're referencing is of such de minimis volumes, we don't see it affecting us really negatively. And so we really like where our assets at because of the reasons I've mentioned and our ability to clear our product to other areas of the country, i.e., Vegas, Arizona, et cetera.

Understood. And on the light heavy outlook, what are your expectations on how those differentials evolve from here? What do you think are the key drivers and keeping the geopolitical instability and general macro volatility in mind?

Yes. Up until now, Theresa, I would tell you that TMX has been the key driver. I would say most have been projecting the differentials to get wider, but increased Far East demand through TMX pipeline has really kept Canadian inventories low and differentials tighter than expected. However, as Far East demand appears to be waning, we believe this could provide some relief to those differentials. So we expect sour differentials to widen slightly in Q1 on incremental OPEC production and incremental Canadian production, especially as we enter the diluent blending season and production grows. The one area that I would like to point out is we've certainly seen depressed ASCI prices as grades are under pressure due to more challenging export environments, both within the U.S. and China. So we believe this is extremely positive. As you know, we're a big player in the ASCI market. We have a ton of exposure of our barrels priced against an ASCI benchmark. And just as a reference, ASCI prices are $2 weaker than earlier in the year, and the forward curve is one of the weaker 4Q, 1Q ASCI curves that I've seen and we've seen in the last five years as offshore production continues to be quite bullish. So we're quite bullish on the AI as we're seeing that not only in current ASCI markets, but in the future forward curve. I hope that helps answer your question.

I wanted to start on the West Coast. It's been a heavier turnaround year in that region, and it seems like that's going to continue into 4Q. So just wondering what's driving that? And then more broadly, it looks like turnaround spend is going to be a bit higher than what you had previously guided to. So wondering if that's related to what's specifically going on in the West Coast? And then I have a follow-up.

On the West Coast, we're currently running the refinery, but both our FCC and alky units are down due to a scheduled turnaround that began in the third quarter. We're also preparing for the project that Maryann mentioned, which is set to kick off in the coming weeks. This puts us in a strong position to take advantage of opportunities in the West Coast. As for the turnaround costs, some have increased, especially at LAR GBR, mainly due to growth and ER projects focused on reliability. This will enhance our ability to capitalize on opportunities in both the West Coast and the Gulf Coast.

And Jason, it's John. I might just kind of add on to Mike's comments. So certainly, you're seeing the number, you can add the fourth quarter to get to a number for the year. But as we look to '26, that's a number we see coming down. And after '26, we see that trend continuing as well, just to give you a little bit of a forward look.

Great. And my follow-up is maybe just on margin capture. And your indicators don't include some regions that were really strong in 2Q and 3Q, the Pacific Northwest and the Rockies. And I suppose some had thought that strength would offset some of the headwinds that you had mentioned. So can you just talk about your ability the past couple of quarters to capture the strength in the Pacific Northwest and the Rockies? Has that driven that distribution cost number higher, which came in above estimates? Or do you feel like your system is kind of well situated at this point to capture those dislocations in the market?

Jason, it's John. I'll start with distribution costs and then turn it over to Rick to talk about kind of those regional cracks as you noted. So again, just to take a step back, right, this is our cost that we look at to kind of get our product to markets across all our refinery systems, again, a little bit of a different convention for us. Certainly, like you said, the number is a little bit higher than our guidance, but that really reflects commercial decisions Rick's team is making every day about products, which markets we go to and where we see the most margin opportunities. Some of those might have higher distribution costs, if you will, but we're going after relatively higher margin. The only other thing I would offer, again, that can move quarter-to-quarter based on those decisions. But if you look at it on a barrel sold basis versus our normal throughput basis, you look year-to-date, this year, year-to-date last year, it's pretty much the same number, but it can move quarter-to-quarter, but it reflects those commercial decisions Rick and his team are making. And I'll turn it over to Rick to talk about kind of your regional question.

Yes, Jason, the situation regarding the regions is quite fluid. Focusing on California, particularly in the third quarter, there has been significant variation between San Francisco and Los Angeles. We can shift some of our Anacortes product to San Francisco to support that market. However, we have observed considerable fluctuations between the Pacific Northwest and California, which I divide into San Francisco and L.A. In any given quarter, one region may perform better than the other, making it challenging to predict consistently. In fact, during the third quarter, the Pacific Northwest lagged behind certain parts of California, negatively impacting our margin pull-through. It's a dynamic situation, and we strive to optimize our approach to capitalize on the highest margin opportunities in the region.

Could you give your thoughts on the RD market going forward? Given these losses, are you considering shutting your California RD asset? And do you have any explanation on why D4 RINs aren't at stronger levels now on our supply/demand? It looks like D4 is in shortage this year. We see a lot of companies operating at pretty low utilization, implementing economic run cuts, and yet the D4 market still seems pretty depressed. So if you have any thoughts on that, that would be great.

Yes. So maybe just a couple of comments, and then I'll pass it to John to give you some of the specifics to your questions with respect to our renewable diesel segment. As you know, in the very beginning of the year, one of the things that we said was in terms of operation, the only investment that we were considering was anything to ensure reliability, and that really hasn't changed. As you know, there's been a tremendous amount of backdrop as we think about the regulatory environment that continues to ebb and flow, still decisions that are pending with respect to how resolution will happen, et cetera. So it is a place where we are ensuring that our operations are running as efficiently as possible, but there's certainly some headwinds when we look at margins, feedstock, et cetera. And as we went out to work on this project, we felt like we had some very favorable, I'll call it, metrics with respect to this project when we look at its location, we look at the center of demand, logistics, et cetera. Feedstock was a place where we felt strongly that we wanted to further optimize as well. So very small part of the portfolio. We're ensuring that we can run it as efficiently as possible, but you don't really see us putting capital to work in this space. But let me pass it to John, and he can answer some of the specifics for you.

Matthew, it's John. Maybe just building off some of Maryann's comments, and I'm sure you've heard similar comments from some of our peers. On some of those regulatory items, there's probably more unknowns than knowns right now. Lots of things need to play out there. We're looking at that D4 RIN just like you are as well as maybe LCFS credits, and you could kind of go down the stack there. Certainly seeing margins improve some in the fourth quarter, but it really feels like we got to get into 2026 before we're going to get some clarity there. As Maryann noted, we're going to work on driving the most value out of the assets we have given where we are in Martinez and what we can do there. So we'll keep focused on that. But I think there's just a lot of uncertainty. You're seeing other players come out of the market, and we'll just have to keep an eye on it as we go into 2026.

Great. And then maybe just to expand the conversation on crude dips. You talked about favorable dynamics on WCS and ASCI. We're also seeing wider moves in areas like ANS, Bakken, and Syncrude so far in the fourth quarter. So I guess, fair to say that this would be an additional tailwind on capture this quarter. And do you have any sort of insights on what's pushing these other grades wider as well?

Yes. Matthew, it's Rick. So I'll start with ANS. That is the one that is the most logical to explain because when you look at the TMX barrels that have entered the market there and the closures, the demand for ANS has gone down significantly. So the differential has had to widen out to compete. And then we're seeing stronger than what we would have expected Bakken production and Syncrude production. So quite nice tailwinds, both from a production perspective in those two fields that is driving those differentials wider for us.

And Matthew, it's John. I wanted to add that when we consider modeling, our blended crack numbers and market metrics account for the dips in those figures. So when we capture data, it reflects more than the current situation. This can indeed enhance margins, but it won't serve as a tailwind for capture. Our approach differs somewhat from that of some peers regarding their indicators, and I wanted to highlight that.

The Gulf Coast and Mid-Con are expecting to run a higher percentage of sweet crude in the fourth quarter than they have in prior quarters. Just given what should be increased availability of crude, I was hoping you could talk through the planned crude slate and also just what you're seeing in the market as far as sourcing more advantaged barrels.

Yes. Phillip, it's Rick. So from a sweet perspective, GBR really sits right at the mouth of incredible amounts of sweet discounted crude. So we're highly advantaged to run it at GBR. And then at Garyville specifically, we will toggle between sweet and sour depending on the price and the economics. I will tell you, we're starting to see a few more looks at what we see as Iraqi barrels that are becoming more promising and getting a slight hint that we might lean into those a little bit more so. But generally, the increased sweet and the amount of sweet you're seeing is just because of where we're logistically set up and the toolkit for Garyville is really well positioned to run a lot of sweet barrels. In addition to that, we do run, I think, as you know, a lot of Canadian heavy barrels that we feed into the RHU that are highly discounted as well, and we see that discount becoming slightly larger in the coming quarter. I hope that helps you, Phillip.

Yes. No, that's helpful. And then when you look at the need for waterborne refined product imports into California, can you touch on available dock space just to bring volumes in? I know you're utilizing some of this through your other refineries. But from an industry's perspective, how much of dock space do you view as utilized? And is that at all a bottleneck to future supply as additional refineries close?

Phillip, you've identified something that certainly is a deterrent and headwind for waterborne imports. Even prior to imports needing to go up significantly because of the recent announced closures and one to come, the docks have always been the wildcard on the West Coast. And the reason is you have fog, you have delays, you have unexpected waterborne incidents that are far less ratable than having a refinery in the state. So when we look at not only the docks, but when we look at weather concerns, when we look at high freight rates today, which is also causing the arb to be where it's at and cracks to be where it's at, we see all of these as significant tailwinds for us.

I have a couple of follow-up questions. Regarding renewable diesel, there's still a lot of uncertainty surrounding various policies, especially regarding the treatment of foreign feedstocks. How might this affect your access to or strategy for feedstock at Martinez if you continue to encounter penalties? Also, on the renewable diesel side, are you currently at a steady run rate for monetization or booking of PTC credits, or is there still some fluctuation in that area?

Yes, Ryan, thanks for the question. So really on foreign feedstock, that is still being debated. But as we know right now, there is a potential for a 50% limitation on that from foreign feedstocks. As I mentioned earlier, one of the things that we were really focused on was ensuring that we could optimize our feedstock when we ran our initial economics on the Martinez project. We were looking at largely a soybean-only feedstock. And then as we did our transaction with Neste and had access to other foreign feedstocks as well as other local advantaged feedstocks, we saw that as a benefit and actually improved the economics of the project. Today, I think we can largely source and have benefit with our partner, Neste and our access. So we don't see this as necessarily being significantly limiting to us. I think the question longer-term is what does the administration do and whether or not that 50% stays in place and would have obviously broader market impact or whether or not they are able to delay the implementation of that as they are resolving the RVO issue and also other elements associated with go forward as well as the historical review of that. So, for us, less of an impact, but it will be obviously a market-driven decision as they decide how they're going to implement that 50% foreign feedstock.

And then Ryan, it's John. Just to add on to that, as Maryann mentioned, we have really strong logistics, not just water for international shipping, but also rail offload for domestic deliveries coming in at Martinez. This positions us well to adapt to market changes. Regarding the 45Z question, as a reminder, we made some adjustments to our structures back in April, which significantly increased our credits. We are still pursuing a few smaller opportunities, including one from Q1 that we haven't given up on, but for the most part, you are currently seeing the impact of the production tax credit in the numbers.

Great. Maybe one CapEx or a question overall on the overall business. I appreciate the provided details in the release on many of the projects that you have going on, either on the refining or the midstream side. Can you talk about some of the macro opportunity set that has you leaning in a little more here in the near term into some of the project spend, particularly on the midstream side? And then should we see that trend back towards a more normal level as we look out a couple of years?

Yes, Ryan, thank you. Our growth opportunities in the midstream sector are primarily focused on the Permian, where we aim to expand our natural gas and NGL value chain. Recently, we made a capital investment to acquire a sour gas treating asset, which we consider significant due to its location in what we believe to be some of the highest quality rock in the Permian's Delaware Basin, specifically in Lea County. As producers explore this area, they will encounter sour gas with high H2S and CO2 levels, which necessitates specific treatment for further processing. This new asset is adjacent to and complements our existing operations and aligns well with our producer customers. We expect EBITDA to grow in 2026 as we bring a follow-on amine treating plant online, which will elevate our EBITDA to its anticipated run rate by the end of that year, contributing incrementally into 2026 and beyond. We have also increased our ownership in the BANGL project by an additional 55%, which will further boost EBITDA in 2026. Moreover, we will realize the full-year benefits from our Preakness II plant, and our new Secretariat processing plant, which will enhance our processing capabilities to 1.4, is set to come online by the end of this year, adding incremental value. Looking further ahead, we are planning two fractionation projects and an LPG export dock, expected to launch in 2028 and 2029, also contributing to incremental EBITDA in those years. Considering the demand for natural gas and NGLs, particularly the growth of NGL and gas-to-oil ratios, we anticipate strong long-term support from our producer customers in the region. This growth will enable us to increase the MPLX distribution, allowing us to return approximately $2.8 billion this year, supporting MPC's commitment to leading in capital returns. Our goal remains to excel in returning capital throughout all phases of this cycle, and we believe we are well positioned to achieve that. Let me know if I have addressed your question.

All right. With that, thank you for your interest in MPC. Should you have more questions or want clarifications on topics discussed this morning, please contact us. Our team will be available to take your calls. Thank you for joining us this morning.