PBF Energy Inc (PBF) 2025 Q4 法說會逐字稿

Good day, everyone, and welcome to the PBF Energy fourth-quarter 2025 earnings conference call and webcast. (Operator Instructions). Please note, this conference is being recorded.

It is now my pleasure to turn the floor over to Colin Murray of Investor Relations. Sir, you may begin.

Thank you, Angelene. Good morning, and welcome to today's call. With me today are Matt Lucey, our President and CEO; Mike Bukowski, our Senior Vice President and Head of Refining; Joe Marino, our CFO; and several other members of our management team. Copies of today's earnings release and our 10-K filing, including supplemental information, are available on our website.

Before getting started, I'd like to direct your attention to the safe harbor statement contained in today's press release. Statements that express 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.

Consistent with our prior periods, we will discuss our results excluding special items, which are described in today's press release. Also included in the press release is forward-looking guidance information. For any questions on these items or other follow-up questions, please contact Investor Relations after today's call.

I'll now turn the call over to Matt Lucey.

Thanks, Colin. Good morning, everyone, and thanks for joining our call. I want to address three key topics. One, status of Martinez. Two, our fourth-quarter performance, and three, the near-term outlook for the market and our company. First, the status of Martinez. Bottom-line is we're on the cusp of restarting the refinery.

All the construction work will be done this weekend. Next week, the plant will be turned over to operations, and we will commence a safe and methodical restart. We expect to be fully operational in early March. We set a high bar for the team that we would not be where we are today without the efforts and ingenuity of all involved.

The Martinez team, a representative workforce, our suppliers and many others who work collaboratively along the way. Our team overcame numerous challenges to get us to this point. And a safe, successful start-up will be the culmination of their efforts. We eagerly look forward to getting back to full operations this quarter and supplying the California market with much-needed fuels.

Point two, Q4 performance. PBF exited '25 on a strong trajectory. Our fourth-quarter results were a sequential improvement over prior quarters and demonstrate the exposure of our system to torque with improving crude differentials. Even with expected seasonality, product cracks remained relatively strong as the quarter progressed.

We directly benefited from improving crude dynamics, increasing supply of heavy and medium crudes improved the light heavy spreads and our predominantly coastal, highly complex refining system directly benefited. Point three, outlook. The market landscape taking shape in '26 is looking very good. Refining fundamentals should remain supported by tight refining balances with demand growth lining up well compared to transportation fuel capacity additions.

Most of the refinery additions are in Asia and have a very high petrochemical yield. Sour crude differentials began widening in the middle of last year with OPEC+ taper and now have additional tailwind in '26 of Venezuela barrels entering the open market. PBF is particularly well suited and highly leveraged to this improving market dynamic.

And in California, with Martinez almost behind us, we look forward to participating in a market that is tighter on products and looser on crude. The near-term outlook for the company is certainly buttressed by the $230 million in achieved efficiencies that we reached in 2025 and are now firmly in place. Incidentally, our RBI effort is not complete.

We have identified an additional $120 million of run rate savings for a total of $350 million that we expect to achieve by the end of this year. PBF remains focused on controlling the aspects of our business that we can control. To be successful and enhance value for our investors, we must operate safely, reliably and responsibly, and we must do it as efficiently as possible.

With a fully restarted Martinez, constructive market dynamics and $230 million of achieved efficiencies, we should have the company set up to be clicking on all cylinders and drive positive results for our shareholders.

And with that, I'll turn the call over to Mike Bukowski.

Thank you, Matt. Good morning, everyone. Before updating on the progress of RBI, I'll provide a few comments on fourth-quarter operations and our Martinez refinery. On the West Coast, I commend the Martinez team and all who have been involved in the rebuild effort. The unplanned nature of the project created a host of challenges that the organization met through creative problem solving, ingenuity and above all, excellent teamwork.

The team has not only overcome these challenges, but they have executed the work so far at an industry top quartile safety performance. My thanks to all involved in the project and all the safe work that has been done -- has been completed to date. Outside of Martinez, aside from a few minor issues, our refineries operated reasonably well in the quarter.

We kicked off a robust 2026 capital program in January, beginning with the turnaround at Torrance. I'm happy to report that the mechanical portion of the turnaround has been completed per plan and the units are in the start-up phase. We have a busy year on the turnaround front in 2026. We previously provided guidance on the locations and total anticipated expenditure for the year.

These activities are weighted to the beginning and end of the year, leaving Q2 and Q3 relatively light from a planned maintenance perspective. I'm also happy to report that we are seeing results from our RBI program. By the end of 2025, we achieved our goal of $230 million of annualized run rate savings. This goal represents $0.50 a barrel or approximately $160 million reduction in operating expenses against our 2024 benchmark and is incorporated in our 2026 budget.

Additionally, we reduced capital and turnaround expenditures by $70 million. While our 2026 total capital guidance is higher than 2025 on an absolute basis, this is driven by an increased level of turnaround activity. The savings reflect comparison against the year with similar scope. We view our system-wide turnaround cycle as being in the five- to seven-year range.

And over time, the savings and efficiencies gained on the capital program will become evident. As you may recall, we started this program with centralized efforts in procurement, capital projects, organizational design, turnarounds and site efforts at our Torrance and Delaware Valley refineries. As of today, all refineries are engaged in RBI and are contributing to the savings goals, and we are also working on a secondary cost initiative.

As part of the overall RBI program, we have identified over 1,300 initiatives focused on improving operational and organizational efficiency. Some of these initiatives are small and some are in the millions of dollars in terms of benefits, but they all sum up to a more competitive and improved cost structure. The average value per initiative is in the $0.5 million range, and we've implemented over 500 initiatives to date.

Outside of our capital and energy initiatives, the biggest opportunity we identified is our procurement practices. We are implementing a centrally led procurement team, which brings value by leveraging our purchasing power across our refineries. Through this initiative alone, we expect to realize over $35 million in annual savings by revamping our procurement model.

While we are improving our maintenance efficiency, reducing energy consumption, our main priority will always be to focus on safe, reliable and responsible operations across our system.

With that, I'll now turn the call over to Joe Marino for our financial overview.

Thanks, Mike. For the fourth-quarter, excluding special items, we reported adjusted net income of $0.49 per share and adjusted EBITDA of $258 million. Our discussion of fourth-quarter results excludes the net effect of special items, including $41 million in incremental OpEx related to Martinez refinery incident. $394 million gain on insurance recoveries, a $313 million LCM inventory adjustment, a $2 million loss related to PBF's 50% share of SBR's LCM adjustment for the quarter and approximately $8 million of charges associated with the RBI initiative as well as other items detailed in the reconciling tables in today's press release.

The $394 million gain on insurance recoveries related to Martinez fire is a result of a third unallocated payment agreed to and received in the fourth-quarter. This brings our total insurance recoveries in 2025 to $894 million, net of our deductibles and retention. Going forward, we will continue to work with our insurance providers for potential additional interim payments.

However, the timing and amount of any agreed-upon future payments will be dependent on the amount of incurred covered expenditures plus calculated business interruption losses. Our Q4 P&L reflects incremental OpEx at Martinez of $41 million, $164 million in total year-to-date that we are reflecting as a special item because it relates to the construction of temporary equipment to restart undamaged units and other fire-related noncapital expenses.

While we anticipate recovering a portion of this amount through insurance, the specific amount will be determined as we finalize the claims process. Shifting back to our normal quarterly results discussion. Also included in our results is a $21 million loss related to PBF equity investment in St. Bernard Renewables. SBR produced an average of 16,700 barrels per day of renewable diesel in the fourth-quarter.

SBR's production was as expected, but results reflect the impact of broader market conditions in the renewable fuel space. While we saw improved pricing on the credit side, much of this was offset by higher feedstock costs. Throughout the year, we've seen impacts from tariffs and regulatory uncertainty cascaded to the feed market and the policy landscape continues to shift, adding volatility to the business.

PBF cash flow from operations for the quarter was $367 million, which includes a working capital draw of approximately $80 million, mainly due to movements in inventory and falling commodity prices. As a preview, we expect first-quarter CapEx and working capital outflows primarily related to the Martinez restart and normal seasonal inventory patterns.

Our Board of Directors approved a regular quarterly dividend of $0.275 per share. Cash dividends paid totaled $126 million in 2025. Cash invested in consolidated CapEx for the fourth-quarter was $124 million, which includes refining, corporate and logistics. This amount excludes fourth-quarter capital expenditures of approximately $273 million related to the Martinez incident.

2025 CapEx, excluding Martinez, was approximately $629 million. On the surface, this figure is lower than expected due primarily to CapEx pools that had not yet been cash settled as of year-end that will flow through this year. Given that and the noise related to the Martinez rebuild, 2025 and 2026 capital programs should be more broadly considered over a two-year period.

Once the Martinez insurance claim is settled, we will be able to provide additional clarity. We ended the quarter with $528 million in cash and approximately $1.6 billion of net debt. At quarter end, our net debt to cap was 28%, and our current liquidity is approximately $2.3 billion based on current commodity prices, cash and borrowing capacity under our ABL. Maintaining our firm financial footing and a resilient balance sheet remain priorities. As we look ahead, we expect to use periods of strength to focus on reducing both our gross and net debt.

Operator, we completed our opening remarks, and we'd be pleased to take any questions.

(Operator Instructions) Manav Gupta, UBS Financial.

Congrats on the strong result. My first question is when we look at PBF as a percentage of total feedstock, you probably use more medium and heavy SBRs than anybody else out there in the US refining system. Now we are already seeing those dips widen out, could be a function of additional Venezuela barrels coming in and other stuff.

But I'm basically trying to understand, Chevron has said they can increase production by 50% from Venezuela. As these additional crude barrels come to US and maybe hit the global markets, can you help us understand the tailwind it will create from PBF from this point on?

Manav, thanks for the question. And you're right on point in regards to PBF's ability and everyone will tout their own numbers and as such. But no one on a relative basis consumes or has the ability to consume as much heavy and sour material as PBF upwards of 55% or 60% of our total throughput capacity. So the famous who's the best boxer? Well, who's the pound for pound the best boxer in regards to relative ability.

So you have -- in our system, it's 200 million barrels a year that we process medium sour or heavy sour barrels. That packs a punch going back to my boxy analogy in terms of every dollar you get on crude diff equates to a $200 million improvement for our business. And as you say, I'm not sure anyone is as levered as we are in that regard.

And so as we see incremental barrels come on, and this started back in the spring, OPEC, OPEC+ started to taper, and there's going to be a lag to that. We saw that and even over the fourth-quarter, even before the news on the Duro pit. And then we -- in a number of weeks ago, with Venezuela coming online, that just is more supply into our marketplace.

And the reality is the impact to the US refining system with those sanctions being lifted is instantaneous. Yes, there will be many, many years of investment and potential growth in Venezuela. But overnight, essentially, the market has been opened up from where it was fairly curtailed under the Chevron program prior to essentially all being available into the US Gulf Coast and into the US market. So that's very, very positive for the industry and PBF in particular.

Perfect, sir. My follow-up quickly is on Martinez. I think you actually listed 16th February is the day when all the construction comes to an end, which is just four-days, which -- so not much can go wrong there, but I'm just trying to understand to make an airtight case, what should we be watching between 16th February and probably March 7 to make sure that the refinery actually is able to fully restart by the first week of March.

I mean your competitor, which was looking to close the refinery in April looks like he's closing now. And then the pipelines, they may get there in three-years. So you could see much above mid-cycle earnings for 3.5 to 4-years if you can get this project fully up and running. If you could talk a little bit about that.

Absolutely, Manav. And you're right. We're essentially right up against the finish line here. It's been an incredible a process to go through. And I must commend the team out there. And it's not only just the local Martinez team, you've had a large number of PBF employees that even weren't in San Francisco that have dedicated the better part of a year in bringing this facility up much faster, mind you.

Than outside consultants were saying. But the marketplace in California, I think, is going to be particularly interesting. You have a much tighter product market. We've talked a lot about that. And that -- what we've talked about prospectively is now upon us. The competitor in San Francisco that you alluded to by press reports, that has now been shut down or ceased operations.

And so you've got a very, very tight product market, upwards of 250,000 barrels a day of gasoline that is -- needs to be imported. You've got a significant amount of jet fuel, over 50,000 barrels a day of jet fuel. And indeed, the state imports additional 50,000 barrels a day of RD into the state. And so the logistics constraints just associated with that amount every day, putting aside the floor that is in place that needs to attract those barrels into the market, we think it's set up attractively on the product side.

But you can't ignore the crude side as well, where you've got less buyers of California crudes. As such, we're seeing our pipeline and all the infrastructure that we have in place being more utilization going through that, which is very, very good news. And so we've talked a lot about it. We think California is going to be particularly interesting with the new dynamics, and there's been a lot of shifting dynamics.

But in regards to Martinez, as we said, over the next couple of days, we'll wrap up the work. It will be a methodical restart. We haven't run that cat cracker in a year, and we're going to take our time and do it right. And like I said, our full expectation by very early March, we're up and producing products.

It looks like 2026 is going to be a much stronger year for you than 2025.

Ryan Todd, Piper Sandler.

Maybe starting on the refining side on margin capture improved significantly in the fourth-quarter. Can you talk about some of the drivers of the improvement and how some of these trends, including things like crude differentials might remain a tailwind for the first-quarter of '26 and beyond?

Yes. The crude differentials is the big story. First of all, it's running reliably and nothing beats reliable operations. But in terms of impacts, widening crude differentials, you will simply see our capture rate go up. And when -- I think I said before, to the degree that crude differentials widen, we get 100% of that. And that's where we get paid for the complexity that we have. So it's across our system.

Obviously, Toledo has its own dynamics being a Mid-Con refiner. But all of our other refineries being coastal complex refiners, as cost of crude improves on a relative basis to other benchmarks, our capture rate is set to increase. And as I said before, every dollar of improvement equates to $200 million on an annual basis.

Maybe a follow-up on the refinery business improvement initiative, the RBI as well. Can you maybe provide a little more color or granularity of the $230 million the run rate that you've captured to date, could you bucket kind of where you've seen those improvements? What have been the biggest drivers? And as we look forward towards the incremental improvements expected over the course of this year, kind of where should those improvements show up? And how should we see them flow through the results?

Okay. This is Mike. Thanks for the question. For the $230 million, as we said, $160 million of that is in OpEx. Of that OpEx breakdown, it's largely driven by what we call third-party spend. And so things like our procurement practices, how we interact with our vendors, our suppliers, service providers and material suppliers. That's a big piece of it. The other piece is in the area of energy consumption.

We've made a lot of strides in being able to improve our efficiency across our refineries. On the capital side, it's largely driven by turnaround performance. And this is something that actually we started prior to RBI, where we've implemented rigor and discipline in our turnaround planning and scope development practices. And we've been on this journey, as I said, for over two-years, where we focused on getting very predictive in our results, but now we're morphing into a phase where we're driving competitiveness.

And we're seeing our improvement -- our expected improvement as we move through different benchmark quartiles. We are also working on our sustaining capital, which is essentially any capital required for regulatory requirements and/or capacity maintenance and to be as efficient as possible in how that spend is allocated.

When I think about the $120 million going forward in the future, I think you probably will see most of that in the area of energy and continued improvement in the third-party spend area, not so much in -- on the capital side, mainly because I think from a turnaround perspective, we are pushing towards the boundaries there in terms of first quartile performance.

We don't want to be very, very top quartile. We want to make sure we're spending appropriately and maintaining our units, but we also want to maintain competitiveness with those others in the industry.

Mehta Neil, Goldman Sachs.

Just wanted to build on the balance sheet comments from the opening remarks. I think you said you're at $1.6 billion in net debt. Matt, as you think about the optimal balance sheet, what's the right level of net debt as you think about it either as a percentage of your capital structure or on an absolute basis? And then talk about the path to get there.

Well, what's optimal is a funny question. It sort of depends on the market in which you're operating in. And to the degree you're in a very, very strong market, you need to take that opportunity to not only delever, but somewhat get under levered just because of the cyclicality of our business.

And you saw that over the last couple of cycles when coming out of '22, we got ourselves under levered. And even in the difficult part of '24 and part of '25, where we certainly had headwinds on -- from a crude perspective, we never got to an uncomfortable place in regards to leverage as we took on some net debt as a result of that marketplace.

So the capital structure and debt is my personal view, where you're going to allocate capital as you're entering what looks like a very, very constructive marketplace. You start to blend debt repayment with returning cash to shareholders because as we reduce net debt, we should see a dollar-for-dollar essentially return for shareholders as you move value, your enterprise value from debt to equity.

So our near-term focus for sure, as we generate cash will be to reduce debt. And then we don't spend a lot of time talking about money that we don't have in hand yet. So we'll -- as we go through that, we'll value it step by step. But there's a huge value for us in paying down debt as we enter a cyclically strong period.

Yes. Matt, that's the follow-up, which is as I think about the product markets going into this year, we have really good strength in the curve on the distillate heating oil side, and then you've got relative weakness in gasoline and there's some seasonality to that as well. But just as you think about the spread between those two products, do you see a scenario where gasoline catches up through the year? And just your thoughts on the fundamentals of the underlying products.

Neil, it's Tom. In terms of addressing that comment sort of really around gasoline, I think starting there is -- obviously, there is seasonal swim sort of coming out of the fourth-quarter with gasoline stocks rising with very high utilization. We've now entered the maintenance period, PADD 3 stocks, which were the area probably of the greatest bloating that took place have started their draw. We're into the seasonalities.

And I think it's really kind of coming around the changing dynamic, which has been taking place for the last year or so in the Atlantic Basin and obviously, now the effects of what we'll see on the West Coast, which will -- as Matt was talking about in terms of the 250 a day of gasoline, which needs to be imported there. So that sort of changes a little bit of the dynamic or not a little bit changes the dynamic in the Atlantic Basin, where obviously, there are flows leaving the Atlantic Basin heading to California.

So that will be -- sort of continue to sort of drive the bus in terms of that tighter market. And probably also a little bit underreported, right, just kind of continuous need to be is that we've seen constant revisions basically to the DOE demand side of the equation from the week lease. A little bit more on -- obviously focused more on diesel than on gasoline.

And on the diesel equation, I think it's a bit of the same kind of story as gas that we saw in gasoline. You saw inventories rise towards the end of the fourth-quarter. But PADD 1 over the last two-weeks has gone from sort of looking at a moderating space to now we're basically at or below the five-year in quite some time -- in a very short amount of time, excuse me.

So the incentives are going to continue to be there. I mean we see the refining balances tight. And the additions which are coming this year are more in the second half of the year and very high in the petrochemical side. So the outlook for products, we're certainly constructive.

Doug Leggate, Wolfe Research.

Matt, it's great to see Martinez coming back. It's been a long time coming. But I wonder if I could turn my questions to the insurance part of that. What we're trying to figure out is how much of the insurance proceeds that have come in so far have still to be paid out in terms of repairs? And I guess related, how do you even begin to quantify the lost opportunity cost given that margins were obviously distorted by the fact that Martinez was offline.

So trying to get an idea how the net cash balance normalizes when you've paid out everything and received everything you expect to get? That's my first one. I've got a follow-up, please.

Sure. From an insurance standpoint, the proceeds we received so far have been unallocated, and they will be unallocated likely through the end of the claim. So we don't have a definitive outline of how much we received so far as it relates to capital expenses, RBI or other operating costs that we incurred. So -- but we do feel very good from an insurance standpoint that the -- all the property-related capital rebuild costs will be fully covered.

And then the BI, I think to answer your second part of the question, which covers part of that loss opportunity, that's a bit of a nuanced process where we work through with the insurance and providers, and we have developed a model indicating how we would have performed if no incident occurred and compared to how the market performed and will be paid out accordingly to recover a good portion of the losses during that period.

The reality is on the BI side, and Doug, there's a whole cottage industry around your question, which is there's a lot of nuances, a lot of gray. There is a lot of science and math as well, and it all sort of blends together. Bottom line is I believe we have an extraordinary relationship with the underwriters in terms of something that's been developed over many, many years.

I think performance to date in regards to recovering insurance is far better than your sort of average events such as this in regards to how we're doing in regards to recovering. Once you get towards the end, there will be haggling and negotiating around the edges. We've been able to cover a lot of ground over this year. The good news, and again, we'll come back to the good news is the work is essentially complete here.

And so the event should be behind us, which means and then short order thereafter, we should be able to clean up on the insurance side.

Okay. My follow-up, guys, Colin and I have gone backwards and forwards on this, and I'll tell you, honestly, we've removed the liability for RINs from our assessment of your valuation after talking to him. But I wanted to ask a question about your RIN liability -- and why -- if you could articulate for everyone listening, why you believe you would -- that would never have the equivalence of net debt.

And how it might have been impacted by the fact that RIN costs have obviously ballooned significantly since the new RVO was proposed at the beginning of the year.

I'm sorry, you're going to make my negotiation with Colin's. He's going to be requiring more money now. But what was your connection between RVO and net debt? I missed that, I'm sorry.

Okay. So you have a RIN obligation, a liability on your balance sheet. But my understanding is you never expect to pay that. I'm assuming that the liability will have gone up as a consequence of what's happened to RIN prices. And what I'm asking is, why should we assume that, that is never an actual liability in terms of something you have to pay out, and therefore, it does not have the equivalent of net debt?

Maybe just to clarify a bit there, we do ultimately have to settle on the RINs obligation, and that's an annual settlement process. But it's a rolling liability. In other words, we continue to incur it as we operate our business. So to the extent you settle one period, you're going to be incurring another. So from a cash flow perspective, it's essentially going to be neutral from that standpoint.

Think of it as working capital.

Exactly. It's like any other working capital accrued obligation.

In regards to RINs going up, they have gone up. And the reality is they've gone up. They've essentially doubled since beginning of last year. The RIN fight is different than it was 10 years ago. Obviously, we have SBR, which buttresses our exposure and the market has evolved. It is not perfectly efficient. And so therefore, there are still winners and losers.

So you have that aspect and you also have the potential for rising RIN prices, which go into the price of gasoline. And so we've seen RIN prices double over the last 13 months. We're working very hard, obviously, in Washington, not only on the winners and losers part, but also to make sure they understand that if they're not careful, RINs can escalate even further and really impact the price of gasoline. So we've been pretty active on that front.

Phillip Jungwirth, BMO Capital Markets.

On the 1Q throughput guidance, East Coast is a bit light versus the annual numbers. There isn't any planned turnaround. So is this just the winter storm impact that we're seeing? And then West Coast would be implied to run mid-90% utilization for the rest of the year after the Torrance turnaround and Martinez startup. So what's the confidence in seeing the higher utilization after the first-quarter on the coast to take advantage of what should be a higher margin environment?

So I'm highly confident. Look, Martinez, we do have hydrocracker turnaround in Q2, but Torrance is finishing up work now and is essentially clean for the rest of the year. Martinez will be thereafter. In regards to the East Coast, there's nothing extraordinary that stands out. That's for sure.

Okay. Great. And then coming back to the wider crude diff conversation, is this something that you think can be sustained midyear or into the second half just as we see higher summer demand, Canadian turnaround, OPEC hitting the pause, new complex refinery startups at year-end? Or do you think there's enough tailwinds here with Venezuela rising Canadian crude production where this can be the new normal? Just trying to understand what's seasonal versus structural here on crude dips in your view.

Yes, Philip, it's Tom. I mean I think you raised a great question in terms of the sort of structural versus seasonal aspects. But I mean, I think the way that we're looking at this is that in some aspects, you've had effectively a barrel which has not been able to trade freely. And that's something that's been going on in the marketplace for quite some time, whether it's tied up by sanctions or different aspects.

So predominantly Russia, Iranian, Venezuela and you basically have distorted those markets and have effectively forced them and pushed them to the Pacific Basin for consumption. So I think in that aspect, from everything that we're seeing here today from the Venezuela sort of liberation of their crude market, I think that takes that to putting it sort of into the structural camp as opposed to being seasonal.

Because in some aspects, we're going to be in a scenario where if the US continues on its growth in terms of the imports that are coming from there, it's going to eventually start to tax the ability for coking capacity in the US, and we'll start to fill that out. I do not think we're there yet. But I think the other thing that's important to note through this whole thing when we're talking about the crude differential situation is that what we are starting to see at this point is a sort of persistent improvement in the light side of the barrel, right?

I mean we're not sitting here this year talking about prolific growth in the US market for shale. We've gone through a situation over showing from a -- a little bit more seasonal, but we've seen very, very strong strength in dated Brent, and that's been coming from the disruptions that have been taking place in the Black Sea with CPC.

You also had freeze-offs in the United States, but you sort of have a little bit of a -- you got a push and a pull when it really kind of translates to the crude differentials. And I certainly see from our seat that we're not sort of -- I don't think we're missing anything that all of a sudden the US is going to show up and having grown 1 million barrels year-over-year with enough of the information that we see in the marketplace.

Strong Canadian growth, strong America growth that may be sort of under the radar, Venezuela barrels coming into the marketplace. These are dynamics and relatively flat shale. These are dynamics that we haven't seen in a long time.

Paul Cheng, Scotia.

The first question, I think, is maybe for Joe or Mike. With the RBI, the continued benefit and all that, it does look like 2025, your OpEx is down about $100 million versus the 2024. So it does seems like you have shown up some benefit in here. Can you tell us that with the inflation, higher natural gas price, but continued benefit from the RBI, how should we expect in the 2026?

Is that you think that you will have enough initiatives that to offset the increase from the higher throughput because Martinez is coming back, the inflation and also the higher natural gas price or that may not be able to fully offset yet? So that's the first question. And the second question is that -- okay. Please go ahead, Joe.

Sorry, I don't mean to cut you off there. But from a -- just to answer the first question, yes, the RBI savings that we put forth out there are net of inflation. And so if you're looking at the 2026 guidance on OpEx versus what we've done in '24, I think one of the key things to point out because the RBI savings are embedded in that guidance is that we are using a natural gas price assumption that if you look compared to what natural gas prices were back in 2024, that is going to be an increase. But if you normalize for that, you'd see that the savings for RBI are baked in for 2026.

Joe, you're saying that a lot of work has been done on the energy intensity. So what is now the sensitivity for every $1 move in natural gas price? What's the impact to your cost structure?

Generally, $1 increase will equal about $100 million.

I'm sorry, $100 --

$1 equal $100 million increase.

$100 million. Okay.

$100 million.

All right. Great. And the second question is that sequentially from the third to the fourth-quarter, the West Coast margin jumped significantly and that the industry margin actually gone down. So trying to understand that, and you are still in the process of fixing Martinez. So what's causing that big improvement in the margin capture in the fourth-quarter? And is there any one-off benefit that we should be aware?

No, not anything one. I mean it speaks to the same thing we've been talking about across the system, which is running reliably, running more efficiently and then lower crude costs is the driver, nothing more complex than that.

Yes. But that the industry margin actually was down and -- but that you capture or that your actual realization up quite meaningfully. And your operation, is it really that much different with Martinez is still under repair. So I mean, is our operation really -- I mean, can you tell us that give us some idea that how the operations have improved in the fourth-quarter versus the third-quarter that lead to such a big improvement in your capture?

Again, I draw you to the cost of crude. I'm not sure the industry margin that you're looking at. I stick with my answer, reliable efficient operations and the cost of crude are going to be the drivers. And indeed, I sort of view California as a microcosm of our broader business, where you've got a tight product market and a loosening crude market. California is its own unique little market with its own dynamics.

And obviously, it's had closures there, which have made the product market much, much tighter. But you also have a dynamic crude market in California that you're unable to export California crude. So as crude -- as refiners come off and there's less buyers of crude, your crude differentials are set to improve. Now going forward, in terms of getting out of the third-quarter to the fourth-quarter prospectively.

And clearly, with Martinez sort of up and running, we view it as an incredibly dynamic and attractive market for us on the look at. Again, we're going to have a clean run rate on Torrance. Martinez does have a hydrocracker turnaround in Q2, but then it will be a clean run there. And you're going to have a very tight market and a loosening crude market.

Jason Gabelman, TD Cowen.

I wanted to ask on CapEx because '25 and '26 turnarounds, as you mentioned, are a bit active. How do you see kind of the turnaround schedule trending after this? Should we take kind of last year and this year as a normalized cadence? Or do you think it's more active and throughput should expand in future years?

I'll make a comment and then hand it over to Mike. This year is particularly large. We have, I think, close to 30%, 28%, I think, was the number I saw, more man hours with all the work we're doing this year over last year. And by the way, I know it's hard to reconcile RBI, but you see a higher turnaround number for this year. But the man hours have gone up 30% and our costs went up 10%.

So if you look closely, and we can help you sort of dissect it, you'll see the benefits of our RBI program. This year is a particularly heavy turnaround year as this is what our business is. It's not ratable in that regard. But we absolutely -- it will normalize going out over the years after, Mike?

Yes. I would look at '27, '28 and '29 to be more in terms of the scope, more indicative to what we had in '24, '25 kind of average together. It's going to come down also that high that we had -- we have in 2026.

Great. And my follow-up is just going back to the insurance proceeds. And I know you've tried to steer us away from trying to break out those proceeds from business interruption insurance and then the cost to fix Martinez. But I noticed in your financials, you do attribute part of it in cash flow from ops and then part of it in cash flow from investing. So is that split indicative of the interruption insurance versus the insurance to fix the equipment? Or should we not look at it that way?

I think at the moment, that's an accounting convention that we've elected to present that. That's not necessarily indicative of where it's going to end out when the claim is settled. So when the claim is settled, that's when the final kind of allocation will be available.

We have reached the end of the question-and-answer session. And we'll now turn the call over to Matt Lucey for closing remarks. Please go ahead.

Thank you very much for participating. And as I said, we look forward to very positive results in the quarters to come. Have a pleasant weekend. Talk to you soon.

Thank you. This concludes today's conference, and you may now disconnect your lines at this time. Thank you for your participation.