Good day, everyone. Welcome to the PBF Energy Inc. fourth quarter 2025 earnings conference call and webcast. If anyone should require operator assistance during the conference, please press 0 on your telephone keypad. 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, Angeline. Good morning, and welcome to today's call. With me today are Matthew C. Lucey, head of refining, and Joseph Marino, our CFO. Our 10-K filing, including supplemental information, is available on our website. Before getting started, I would like to direct your attention to 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 will now turn the call over to Matthew C. 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 are 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 will commence a safe and methodical restart. We expect to be fully operational in early March. We set a high bar for the team, but 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 worked collaboratively along the way. Our team overcame numerous challenges to get us to this point. A safe,…

Thank you, Matt. Good morning, everyone. Before updating on the progress of RBI, I will 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, teamwork. The team has not only overcome these challenges, but they have executed the work so far with industry top-quartile safety performance. My thanks to all involved in the project and all the safe work that 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 a turnaround at Torrance. I am happy to report that the mechanical portion of the turnaround has been completed per plan and the units are in the startup 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 am also happy to report that we are seeing results from our RBI program. By the end of 2025, we achieved our goal of $230,000,000 of annualized run-rate savings. This goal represents $0.50 a barrel, or approximately $160,000,000, reduction in operating expenses against our 2024 benchmark and is incorporated in our 2026 budget. Additionally, we reduced capital and turnaround expenditures by $70,000,000. While our 2026 total capital guidance is higher than 2025 on an absolute basis, this is driven by an increased level of…

Thank you. In a moment, we will open the call to questions. If you would like to ask a question, please press 1 on your telephone keypad. You may press 2 if you would like to remove your question from the queue. Please unmute your handset before pressing the star key. One moment, please, while we queue for questions. Your first question comes from the line of Manav Gupta from UBS Financial. Please go ahead.

Good morning. Congrats on a strong result. My first question is when you look at PBF Energy Inc. as a percentage of total feedstock, you probably use more medium and heavy sours than anybody else out there in the U.S. refining system. Now we are already seeing those diffs widen out, could be a function of additional Venezuela barrels coming in, some of the other stuff, but I am basically trying to understand, you know, Chevron has said they can increase production by 50% from Venezuela. As these additional crude barrels come to the U.S. and maybe hit the global markets, can you help us understand the tailwind it will create for PBF Energy Inc. from this point on?

Manav, thanks for the question, and you are right on point. In regards to PBF Energy Inc.’s ability, and everyone will tout their own numbers and such, but no one on a relative basis consumes or has the ability to consume as much heavy and sour material as PBF Energy Inc., upwards of 55% or 60% of our total throughput capacities. You know, so the famous, you know, who is the best boxer? Well, who is pound-for-pound the best boxer, in regards to relative ability? So you have in our system, it is 200,000,000 barrels a year that we process medium sour or heavy sour barrels. That packs a punch, going back to my boxing, in terms of every dollar you get on crude diffs equates to a $200,000,000 improvement for our business. And as you say, I am 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 taper, and there is going to be a lag to that. We saw that even over the fourth quarter, even before the news on Maduro hit. And then we, 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 U.S. 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 it essentially all being available into the U.S. Gulf Coast and to the U.S. market. So that is very, very positive for the industry and PBF Energy Inc. in particular.

Perfect, sir. My follow-up quickly is on Martinez. I think you have actually listed February 16 as the day when all the construction comes to an end, which is just four days, so not much can go wrong there, but I am just trying to understand, to make an airtight case, what should we be watching between February 16 and probably March 7 to make sure that the refinery actually is able to fully restart by March. I mean, your competitor, which was looking to close the refinery in April, looks like he is closing now. And then the pipelines, they may get there in three years. So you could see much above mid-cycle earnings for three and a half to four years if you can get this project fully up and running. If you could talk a little bit about that. Thank you.

Absolutely, Manav, and you are right. We are essentially right up against the finish line here. It has been an incredible process to go through, and I must commend the team out there. And it is not only just the folks in Martinez. You had a large number of PBF Energy Inc. employees that even were not in San Francisco that dedicated the better part of a year and brought 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 have talked a lot about that. And what we have talked about prospectively is now upon us. The competitor in San Francisco that you alluded to by press reports has now been shut down or ceased operations. And so you have got a very, very tight product market, upwards of 250,000 barrels a day of gasoline that needs to be imported. You have got a significant amount of jet fuel, over 50,000 barrels a day of jet fuel. And indeed the state imports an 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 is set up attractively on the product side. But you cannot ignore the crude side as well, where you have got fewer buyers of California crudes. As such, we are seeing our pipeline and all the infrastructure that we have in place being more utilized, which is very good news. And so, we have talked a lot about it. We think California is going to be particularly interesting with the new dynamics, and there have been a lot of shifting dynamics. But in regards to Martinez, as we said, over the next couple days, we will wrap up the work. There will be a methodical restart. We have not run that cat cracker in a year, and we are going to take our time and do it right. And like I said, our full expectation by very early March, we are up and producing products.

Thank you for the detailed response. Looks like 2026 is going to be a much stronger year for you than 2025. Thank you so much.

Thanks, Manav.

Thank you. The next question comes from the line of Ryan M. Todd from Piper Sandler. Please go ahead.

Thanks. Good morning. Maybe to start 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 2026 and beyond?

Yes. Crude differentials is the big story. First of all, it is 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 we are managed, I think I said before, to the degree that crude differentials widen, we get 100% of that. And that is where we get paid for the complexity that we have. So it is 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 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 $200,000,000 on an annual basis.

Thanks. Maybe a follow-up on the refinery business improvement initiatives, RBI, as well. Can you maybe provide a little more color or granularity of, like, of the $230,000,000, the run rate that you have captured to date? Could you bucket where you have 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 $230,000,000, as we said, $160,000,000 of that is in OpEx. Of that OpEx breakdown, it is largely driven by what we call third-party spend. And so things like our procurement practices, how we interact with our vendors or suppliers, service providers, and material suppliers. That is a big piece of it. The other piece is in the area of energy consumption. We have made a lot of strides being able to improve our efficiency across our refineries. On the capital side, it is largely driven by turnaround performance. And this is something that actually started prior to RBI where we have implemented rigor and discipline in our turnaround planning and scope development practices. We have been on this journey, as I said, for over two years where we focused on getting very predictive in our results, but now we are morphing into a phase where we are driving competitiveness. And we are seeing 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. I think about the $120,000,000 going forward in the future, I think improvement in the third-party spend, you probably will see most of that in the area of energy and continued—

The next question comes from Neil Singhvi Mehta from Goldman Sachs. Please go ahead, sir.

Yeah. Good morning, Matt, and good morning, team. Just wanted to build on the balance sheet comments from the opening remarks. You said you are at $1,600,000,000 in net debt. Matt, as you think about the optimal balance sheet, what is 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 talk about the path to get there.

Well, again, what is optimal is a funny question. It sort of depends on the market and what you are operating in. And to the degree you are 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 know, you saw that over the last couple cycles when, coming out of 2022, we got ourselves under-levered. And even in the difficult part of 2024 and part of 2025, where we certainly had headwinds 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, in my personal view, where you are going to allocate capital as you are 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 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 do not spend a lot of time talking about money that we do not have in hand yet. So, as we go through that, we will evaluate step by step. But there is a huge value for us in paying down debt as we enter the cyclically strong period.

Yeah. Matt, 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 have got relative weakness in gasoline, and there is 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. Thomas O’Connor: Hey, Neil. It is Tom. In terms of addressing that comment sort of really around gasoline, I think starting there is, obviously, there is seasonal swoons sort of coming out of the fourth quarter with gasoline stocks rising with very high utilization. You know, we have now entered the maintenance period, past restocks, which were the area probably of the greatest bloating that took place, have started their draw. We are into the seasonalities, and I think it is 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 will 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, sort of changes a little bit of the dynamic—or not a little bit, changes the dynamic—in the Atlantic Basin. Obviously there are flows leaving the Atlantic Basin heading to California. So that will continue to drive the bosuns in terms of that tighter market and be also a little bit underreported, right, just kind of continuous need to be, is that we have seen constant revisions basically to the DOE demand side of the equation from the weeklies. A little bit more on, obviously, focus more on diesel than on gasoline. And on the diesel equation, I think it is a bit of the same kind of story as we saw in gasoline. You saw inventories rise towards the end of the fourth quarter, but PAD 1 over the last two weeks has gone from sort of looking in a moderating space to now we are 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 are certainly constructive.

Thank you.

Thank you. The next question comes from Doug Leggate with Wolfe Research. Please go ahead.

Thanks. Good morning, everybody. Matt, it is great to see Martinez coming back. It has been a long time coming, but I wonder if I could turn my questions to the insurance part of that. What we are 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 have paid out everything and received everything you expect to get. That is my first one. I have 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 do not have a definitive outline of how much we received so far as it relates to capital expenses or BI or other operating costs that we incurred. But we do feel very good from an insurance standpoint that all the property-related capital rebuild costs will be fully covered. And then the BI, to answer your second part of the question, which covers part of that lost opportunity, that is a bit of a nuanced process where we work through with the insurance providers, and we have developed a model indicating how we would have performed if no incident occurred and how, compared to how the market performed, and we 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 is a whole cottage industry around your question—which is there are a lot of nuances, a lot of gray, and 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 has 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 are doing in regards to recovering. Once you get towards the end, there will be haggling and negotiating around the edges. We have been able to cover a lot of ground over this year. The good news, and again, we will come back to the good news, is the work is essentially complete here. And so the event should be behind us, which means in short order thereafter, we should be able to clean up on the insurance side.

Okay. Thank you for that. My follow-up, guys, and Colin and I have gone backwards and forwards on this now. I will tell you honestly, we have removed the liability for RINs from our assessment of your valuation after talking to him, but I wanted to ask the question about your RIN liability and why, if you could articulate for everyone listening, why you believe that would never have the equivalence of net debt and how it may have been impacted by the fact that RIN costs have obviously ballooned significantly since new RVO was proposed at the beginning of the year.

I am sorry. You are going to make my negotiation with Colin—he is going to be requiring more money now. But what was your connection between RVO and net debt? I missed that. I am sorry.

Okay. So you have a RIN obligation, or a liability on your balance sheet. But my understanding is you never expect to pay that. I am assuming that the liability will have gone up as a consequence of what has happened to RIN prices. And what I am 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 equivalence of net debt.

Maybe just to clarify a bit there, we do ultimately have to settle on the RINs obligation, and that is an annual settlement process. But it is 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 are going to be incurring another. So from a cash flow perspective, it is essentially going to be neutral from that standpoint.

Think of it as working capital.

Exactly. It is just like any other working capital accrued obligation.

Alright. I will take it offline with Colin again. But thanks, guys. Appreciate it. And regards to RINs going up, they have gone up.

And the reality is they have gone up. They have essentially doubled since the beginning of last year. The RIN fight is different than it was ten 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 have seen RIN prices double over the last thirteen months. We are working very hard in Washington, not only on the winners and losers part, but also to make sure they understand that if they are not careful, RINs can escalate even further and really impact the price of gasoline. So we have been pretty active on that front.

Appreciate it, guys. Thank you.

Thank you.

Thank you. The next question comes from Phillip Jungwirth from BMO Capital Markets. Please go ahead.

Thanks. Good morning. On the Q1 throughput guidance, East Coast is a bit light versus the annual numbers. There is not any planned turnaround. So is this just the winter storm impact that we are 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 is the confidence in seeing the higher utilization after the first quarter on the coasts to take advantage of what should be a higher margin environment?

It is highly confident. Look, Martinez, we do have a 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 is nothing extraordinary that stands out. That is 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 OPEC hitting the pause, new complex refinery startups at year-end? Or do you think there is enough tailwind here with Venezuela rising, Canadian crude production, where this can be the new normal? Just trying to understand what is seasonal versus structural here on crude diffs in your view. Thomas O’Connor: Yes, Phillip, it is Tom. I think you raised a great question in terms of the sort of structural seasonal aspects. But I think the way that we are looking at this is that in some aspects, you had effectively a barrel which has not been able to trade freely. And that is something that has been going on in the marketplace for quite some time, whether it is tied up by sanctions or different aspects of predominantly Russia, Iranian, Venezuelan, 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 are 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 are going to be at a scenario where if the U.S. continues on its growth in terms of the imports that are coming from there, it is going to eventually start to tax the ability for coking capacity in the U.S. and we will start to fill that out. I do not think we are there yet. But I think the other thing that is important to note through this whole thing when we are talking about the crude differential situation is that what we are starting to see at this point is sort of persistent improvement in the light side of the barrel. We are not sitting here this year talking about prolific growth in the U.S. market for shale. We have gone through a situation—certainly a little bit more seasonal—but we have seen very, very strong strength in Dated Brent, and that has 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 push and a pull when it really kind of translates to the crude differentials, and I certainly see from our seats that we are not missing anything that also in the U.S. is going to show up and having grown a million barrels year-over-year with enough of the information that we see in the marketplace.

Yes. Strong Canadian growth, strong American growth, maybe sort of under the radar as well, barrels coming into the marketplace. These are dynamics—and relatively flat shale—these are dynamics that we have not seen in a long time.

It does seem that you have shown 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 2026 that you think that you will have enough initiative 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 is the first question. And the second question is that—

Oh, okay. Please go ahead, Joe. Sorry, I did not mean to cut you off there. But just to answer the first question, yes, the RBI savings that we have put forth out there are net of inflation. And so if you are looking at the 2026 guidance on OpEx versus what we have done in 2024, 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 would see that the savings for RBI are baked in for 2026.

And, Joe, you are 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 is the impact to your cost structure?

Generally, a dollar increase will equal about a $100,000,000.

I am sorry. A $1 would equal a $100,000,000 increase. A $100,000,000? Okay.

$100,000,000.

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

No. Not anything one-off. I mean, it speaks to the same thing we have been talking about across the system, which is running reliably, running more efficiently, and then lowered crude cost is the driver. Nothing more complex than that.

Yeah. But the industry margin actually was down, but your capture or your actual realization was up quite meaningfully. And your operation, you said, was not that much different with Martinez. It is still under repair. So, I mean, yes, our operation, we need—can you tell us, give us some idea how the operation has improved in the fourth quarter versus the third quarter that led to such a big improvement in your capture?

I, again, draw you to the cost of crude. I am not sure the industry margin that you are looking at. I stick with my answer. Reliable, efficient operations, and the cost of crude are going to be the driver. And indeed, I serve you California as a microcosm of our broader business, where you have got a tight product market and a looser crude market. California is its own unique little market with its own dynamics, and obviously it has had closures there which have made the product market much, much tighter. But you also have a dynamic crude market in California that you are unable to export California crude. So as refiners come off and there are fewer buyers of crude, your crude differentials are set to improve. Now going forward, in terms of getting out of the third quarter to fourth quarter prospectively, and clearly with Martinez up and running, we view it as an incredibly dynamic and attractive market for us on the lookout. Again, we are 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 are going to have a very tight market and a loosening crude market.

Alright. Will do. Thank you.

Thank you. The next question comes from Jason Daniel Gabelman with TD Cowen. Please go ahead.

Good morning. Thanks for taking my questions. I wanted to ask on CapEx because 2025–2026 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 is more active and throughput should expand in future years?

I will make a comment and 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 are doing this year over last year. And by the way, I know it is hard to reconcile RBI, but you see a higher turnaround number for this year, but the man-hours have gone up 30% and our cost went up 10%. So if you look closely, and we can help you sort of dissect it, you will see the benefits of our RBI program. This year is a particularly heavy turnaround year, as this is what our business is. It is not ratable in that regard. But we absolutely will normalize going out over the years after.

I would look at 2027, 2028, 2029 to be more, in terms of the scope, more indicative of what we had in 2024–2025 kind of averaged together. It is going to come down off the high that we have in 2026.

Great. And my follow-up is just going back to the insurance proceeds. And I know you have 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 do we not look at it that way?

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

Alright. Thanks, all.

Leave it there. Thank you.

We have reached the end of the question and answer session and will now turn the call over to Matthew C. 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.