PBF Energy Inc. (NYSE:PBF) Q3 2025 Earnings Call Transcript

PBF Energy Inc. (NYSE:PBF) Q3 2025 Earnings Call Transcript October 30, 2025

PBF Energy Inc. beats earnings expectations. Reported EPS is $-0.52, expectations were $-0.69.

Operator: Good day, everyone, and welcome to the PBF Energy Third 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.

Colin Murray: Thank you, Lilly. Good morning, and welcome to today’s call. With me today are Matt Lucey, our CEO; Mike Bukowski, our Head of Refining; Joe Marino, our CFO, and several other members of our management team. Copies of today’s earnings release and our 10-Q 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’ll 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 following the call. I’ll now turn the call over to Matt Lucey.

Matthew Lucey: Thanks, Colin. Good morning, everyone, and thank you for joining our call. First, I’d like to welcome and introduce Joe Marino as PBF’s new Chief Financial Officer. Many on the call may be familiar with Joe, as he has been with PBF since before our 2012 IPO and has been our Treasurer for the last 5 years. In the same breath, I’d like to thank Karen Davis for her service, and I’m thrilled to welcome her back to the Board of Directors. I want to address three topics: one, the status of Martinez; two, our third quarter performance; and lastly, the near-term outlook. Regarding Martinez, consistent with our call in July, we are on schedule for a December restart. Maintenance teams are scheduled to be turning over the impacted units to operations in early December.

As units get handed over, we will commence a deliberate and sequential restart of the affected units. Our plan is to have Martinez fully operational by the end of the year. The dedication of the Martinez team in this effort continues to be exemplary. While PBF’s third quarter represented a sequential improvement over the prior few quarters, the real news is the sequential improvement that occurred during the quarter. Unquestionably, there was a shift in September, which represented a significant positive step in the right direction. While product cracks were relatively strong throughout the quarter, crude differentials only began to improve towards the end of the quarter. Now as we sit in what is typically the seasonally weaker period, product cracks are quite strong and crude differentials continue to widen.

As we look past the fourth quarter into ’26, refined product supply constraints, coupled with a well-supplied crude market should create a positive theme for domestic and global refining. Global demand continues to outstrip net refining capacity additions, and we expect to see additional capacity rationalizations that will be supportive of tight product balances as we saw this month with the shutdown of another refinery in California. PBF remains focused on controlling the aspects of our business that we can control. We expect to be well positioned to capture favorable market conditions as we move forward. 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.

To that end, we are on track with our commitment to our business improvement initiatives. We are working to improve our performance every day. So to summarize, strong product cracks with improving crude dynamics coupled with the full power of our refining system as Martinez should be up by the end of the year, operating with improved efficiency — thanks to our RBI program, all of which should come together to create a dynamic environment for the company and our shareholders. With that, I’ll turn it over to Mike.

Michael A. Bukowski: Thank you, Matt. Good morning, everyone. Before discussing the progress of our Refining Business Improvement Program, or RBI for short, I’ll provide a few comments on third quarter operations and our Martinez refinery status. On the West Coast, we continue to progress with the full repair and restart of Martinez. We plan to begin transitioning from maintenance to operations in early December. This time, we will execute a methodical sequence start-up plan with its primary focus being the safe and environmentally sound restart of the repaired processing units. Our Martinez team has completed a tremendous amount of work this year. To give you a little bit of an idea as to the scale of this effort, in addition to completing the FCC turnaround, we’re installing 130 tons of new steel, laying over 20,000 feet of pipe and over 200,000 feet of electrical and instrument cabling.

All major equipment components have arrived on site, and we have completed installation of the two major columns that had to be replaced. I commend our Martinez team for continuing to execute the repair work safely. While the team is focused on restoring operations, we will not let time be a constraint from executing the start-up safely. While there has been a lot of focus on Martinez, our team at Torrance successfully and safely completed the hydrocracker turnaround in the third quarter. At Toledo, a mid-summer hydrocracker unplanned outage and pipeline maintenance impacted third quarter throughput. Aside from a few minor issues, the rest of our system operated reasonably well in the quarter, and we have no major turnaround work for the remainder of the year.

Shifting topics to RBI. We are on track to meet our previously announced goal to implement $230 million of annualized run rate savings by the end of 2025. This goal represents $0.50 per barrel or approximately $160 million reduction in operating expenses against our 2024 benchmark and will be fully realized in 2026. In addition, we expect to reduce sustaining capital and turnaround expenditures by $70 million. 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 the third quarter, all refineries are engaged in RBI and are contributing to the savings goals. One of the recent successes achieved through the RBI program is a 5% cost reduction of our Torrance hydrocracker turnaround through our productivity improvement initiative.

This program uses dedicated resources to identify and eliminate waste and remove barriers to job productivity. Additionally, we’ve achieved approximately $21 million in run rate savings by revamping our procurement model to leverage our spend across the refining circuit. System-wide, we are focusing on improving our maintenance efficiency and reinvesting some of the savings in energy reduction projects while also reducing our maintenance backlogs. The outcome will have the dual effect of improved energy efficiency and reliability. We are providing enhanced performance monitoring tools to our employees and incorporating them into our site work processes across the fleet. The new tools and processes will drive the organization to not only maintain our savings performance and efficiency but drive continuous improvement.

Our main priority will always be to focus on safe, reliable and responsible operations across our system. RBI will help us improve across all areas and result in a sustainable culture of operational excellence and continuous improvement. With that, I’ll now turn the call over to Joe Marino for our financial overview.

Joseph Marino: Thanks, Mike. For the third quarter, we reported an adjusted net loss of $0.52 per share and an adjusted EBITDA of $144.4 million. Our discussion of third quarter results excludes the net effect of special items, including $14.6 million in incremental OpEx related to the Martinez refinery event, a $250 million gain on insurance recovery, a $94 million gain on the sale of terminal assets, an $8.5 million loss relating to PBF’s 50% share of SBR’s LCM inventory adjustment for the quarter and approximately $8 million of charges associated with the RBI initiative. The $250 million gain on insurance recoveries related to Martinez fire is a result of the second unallocated payment agreed to at the end of the third quarter, of which the majority has already been received in Q4.

Going forward, we will continue to work with our insurance providers for potential additional interim payment. However, the timing and amount of any agreed upon future payment will be dependent on the amount of incurred covered expenditures plus calculated business interruption losses. Our Q3 P&L reflects incremental OpEx at Martinez of $14.6 million that we are reflecting as a special item because it relates to construction of temporary equipment to restart undamaged units and other fire-related non-capital expenses. While we anticipate recovering a portion of this amount through insurance, the specific amount will be determined as we progress further into the claims process. Generally speaking, any insurance proceeds we received in future periods will be reflected as gain on insurance recoveries on our income statement and reported as a special item.

Shifting back to our normal quarterly results discussion. Also included in our results is a $19.7 million loss related to PBF’s equity investment in St. Bernard renewables. SBR produced an average of 15,400 barrels per day of renewable diesel in the third quarter. SBR’s production was somewhat below guidance, driven by broader market conditions in renewable fuel space. Throughout the year we’ve seen impacts from tariffs cascade through the market and the policy landscape continue to shift, adding uncertainty and volatility to the business. PBF cash flow from operations for the quarter was approximately $25 million, which includes a working capital draw of approximately $74 million, primarily related to the timing of cash interest payments, movements in inventory and falling commodity prices.

Also included in our cash flow for the quarter are the previously announced tax refunds of $75 million, including interest, and a $175 million received through the sale of Knoxville and Philadelphia terminal asset, excluding commission and closing cost. Cash invested in consolidated CapEx for the third quarter was approximately $132 million, which includes refining, corporate, and logistics. This amount excludes third quarter capital expenses of approximately $128 million related to the Martinez incident. Year-to-date rebuild capital expenses through the end of the third quarter are approximately $260 million. Additionally, our Board of Directors approved a regular quarterly dividend of $0.275 per share. We ended the quarter with $482 million in cash and approximately $1.9 billion of net debt.

Maintaining our financial — our firm financial footing and a resilient balance sheet remain priorities. At quarter end, our net debt to cap was 32% and our current liquidity is approximately $2.1 billion based on current commodity prices, cash and borrowing capacity under our ABL. If you take into consideration the second installment of our insurance proceeds already received in Q4, our liquidity and net debt position has improved versus the prior quarter. As we look ahead, we expect to use periods of strength to focus on deleveraging and preserving the balance sheet. Operator, we’ve completed our opening remarks, and we’d be pleased to take any questions.

Q&A Session

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

Manav Gupta: Would like to first welcome Joe in his new role and wish him all the luck in his role. Matt, maybe for you or somebody else. But just — I mean, you made some positive comments about Martinz restart. I think there’s a lot of focus on that given the capacity closures that are happening. And yes, some new pipelines might get built, but that could take 2, 3 years. So the key here is to get that refinery up and running. And I’m just trying to understand your confidence level in getting this thing across the line. I understand sometimes there could be regulatory delays, but it looks like the government wants you to get this up and running. So help us understand where we are in the process and your confidence level in getting this asset up and running by year-end.

Matthew Lucey: Thanks, Manav. I don’t anticipate any regulatory issues, to be clear. We have all our permits, and we’ve had a good working relationship with the state. And as you said, I think they’re very, very interested in getting the refinery back up and running. I have tremendous confidence in our team. They have done amazing work to get us to this point. It is a major lift. As Mike Mikowski can detail, any project that a refinery does usually has years of advanced work done. And when you have an unplanned incident like we had, it creates a much more difficult environment to execute because there is no preplanning. And so our team has just distinguished themselves. And indeed, we have — that requires us doing everything as safely and reliably as we can.

If there’s a moment in time when we need to take a breath or introduce a bit more time, there’s always time for safety. But I have complete confidence in the team. We have all our permits in place. And so I think we just need to let it play out over the next couple of months.

Manav Gupta: Perfect, sir. All the best for that. And I have come back to one of the comments you made on the call earlier where you said, look, the dips really started to widen out towards the end of the quarter. So just trying to understand the outlook for the heavy light differentials. I think we all acknowledge PBF is one of the most levered to that trend. If that dip does widen, it will lead to material increase in your capture rates. So help us understand what you’re seeing out there. Are there heavier discounted barrels now showing up on the Gulf Coast, which was — or other parts of your system, which was not the case even 2 or 3 quarters ago? If you could help us talk through that.

Matthew Lucey: Absolutely. I’m going to make a couple of comments and turn it over to Tom. Look, the market has been constrained if you go back starting over 4 years ago when barrels started getting pulled off the market. So when OPEC made its deliberate shift going back 6 months ago, there’s simply a lag. And now obviously, they made their shift at a moment in time where you’re going into peak runs and you’re also going into crude burn in the Middle East. And so demand is sort of at its highest. In any scenario, there’s going to be a lag. Considering the seasonal time that the tapering began, there was probably even more of a lag, one that was a bit frustrating to us. But indeed, we are now seeing crude loosen as a result of the OPEC moves. Tom?

Thomas D. O’Malley: Yes. Thanks, Manav. I mean — trying to just go in a little bit further, I mean I think Matt summarized that well in terms of the peak run environment and the crude burn and obviously OPEC is pivoting in terms of where they’ve been in terms of their policies. That certainly has shifted the dynamics. As we look at this year, right, I mean, this has been a year where crude stocks have been building, but they’ve been building in the non-OECD and the Western Basin or the Atlantic Basin has been tight in comparison, right? Stocks are low. But we now have seen at this juncture, right, there’s enormous amounts of oil that have been pushed out on water. Freight is very expensive. A lot of the oil going on water is clearly something related around some of the sanctions.

But inevitably, that oil then needs to come back onshore. And when that comes onshore, that sort of is a little bit more of the sustaining aspect of what we’ve been seeing in the near term in terms of the widening of differentials because you got cheap tanks available in the U.S. Cushing and PADD 3 are certainly available to be built at far more economic numbers than putting it on a ship at multiyear highs in terms of freight. And then I think the last kind of couple of comments in terms of barrels that were getting pulled out of the Atlantic Basin to the Pacific, particularly some LatAm barrels. I mean we are seeing the wells and we are buying barrels that we have not bought in several years. And that’s coming into our system. I think one of the larger things also to kind of comment is if we were talking about the market a year ago, we would have been talking about, obviously, the taper and all the different effects, but we would have been talking about underperformance at Brazil.

Guyana was just getting its sort of feet under itself. We’ve had prolific finds and gains in those areas that are certainly contributing to the dynamics where the crude market dynamics certainly look a little bit better or a lot better, excuse me, in terms of their availabilities, particularly to the coastal regions.

Operator: Your next question comes from Ryan Todd from Piper Sandler.

Ryan Todd: Maybe — this might be hard to answer, but maybe it’s great news on the approval of another $250 million installment of the insurance proceeds. Is there a way to think about this from a time line point of view in terms of what it covers or what is — kind of what is included in the installments up to this point? Does it cover cost and losses implied through year-end under the current plan or through the end of third quarter? I guess as part of it, like how should we think about the possibility of further meaningful installments in the future?

Matthew Lucey: Yes. Happy to address that to some degree, we don’t want — we’re not going to get into the detailed accounting over the dissection of it. Here’s how I would describe it. In the third quarter, we got a $250 million payment shortly after the quarter. So it wasn’t in the results. So if you look at the third quarter and you take credit for that $250 million that came in just after September 30, we’re a little bit in arrears. So if you pull out more broadly and look at the third quarter, — and we had an asset sale of $175 million — and you take that out, but then you solve for the insurance payment that came in right after the quarter and you account for us being in a bit of arrears in some insurance collections through the quarter, I look at our operations on a pro forma basis for Q3 as being cash flow positive to the tune of between $100 million and $200 million.

In regards to going forward, all I can say is we’ve had a tremendous relationship with the insurance markets, with the underwriters. I don’t know if that can always be said for other companies and other industries and other incidents. But we’ve had a long standing relationship with our insurance underwriters. I was along with our team over in London, meeting with the insurance markets over there. We hosted the group here in New Jersey for the U.S. underwriters, and we continue to really value the relationship we have with them. There will be some payments that are in arrears, but it’s very, very manageable.

Ryan Todd: Congratulations on the progress that you’ve made up to this point. Can you provide a little more color on maybe how much you’ve been able to capture to date on your OpEx per barrel reduction targets or CapEx run rate targets? What are the big buckets left to achieve as you work towards 2026 kind of target completion on that plan?

Michael A. Bukowski: So thanks for the question, Ryan. This is Mike. So as I said, we’re on target for the $230 million. I think as of today, we’re close to about $210 million of implemented savings on a run rate basis throughout the course of the year. That’s cash. So that’s not just all OpEx. And so roughly think about that, as I said before, 70% on the OpEx, 30% CapEx. And so we look real good to finish up the year to hit our goal of $230 million. When we look across the system, remember, we just started this in two refineries back in January. And so there’s kind of a time basis of this. But I think across the course of the year up to the third quarter, probably captured order of magnitude about $30 million to $40 million of OpEx and then another $10 million to $15 million of turnaround savings.

One thing you may want to take a look at in our earnings release is the third quarter performance of the Delaware City refinery. You’ll see that in an era where we had some headwinds on energy prices, utilization was about the same quarter-to-quarter, and we’re showing a reduction in OpEx. So we’re starting to see it get to the bottom line.

Ryan Todd: Do you think that there’s — is there another leg to this process as you think beyond kind of the 2026 completion now that you’ve — I mean, you’re not that far into this process. Is there kind of a second leg in tranche that might be visible at this point that it’s more upside in the future?

Michael A. Bukowski: Yes, definitely. I tend not to think of this as legs or tranches. I tend to think of this as a continuous improvement journey that never really ends. But as I said in my prepared remarks, we added the other refineries in the third quarter to the program. And so initially, it was just Torrance in Delaware City, and then we’re bringing on these other refineries. So a large impact in that $210 million has been through the central and just those two refineries. So additional savings will be coming online from the refineries that we added to the program. And then the way we’re doing this, this is not just deferring expenses. This is finding waste, driving efficiency and eliminating costs. And so we will spend the time next year going through another what we call brainstorming or ideation process at all the facilities, one, to ensure we sustain what we have, but also to drive improvement going forward.

So as I look towards the end of 2026, I see that run rate savings going up to over $350 million.

Operator: Your next question comes from Doug Leggate from Wolfe Research.

Douglas George Blyth Leggate: I wonder, Matt, if I could hit on the lower turnaround expenses. And I’m wondering, as part of your efficiency drive, do we basically get — you referenced Delaware in your remarks just there in the last question. Do we think about higher utilization being a new normal, I guess, for PBF going forward? It seems to us that the whole industry has managed to shift up its utilization. Obviously, that resets our view of mid-cycle free cash flow. We’re just wondering if that also applies to you guys.

Michael A. Bukowski: We — so our turnaround program is set up a couple of different ways. And in the past, we haven’t been happy with our performance on cost and schedule. And then also, we have an opportunity to optimize our intervals. And so we think we’ll see a lengthening of intervals for one thing. So that will allow more run time. We are working with a third-party benchmarking firm to really set our turnaround budgets and schedules going forward, and that’s how we’re going to drive the savings. And so we would expect to see somewhat shorter duration turnarounds and much more effective turnarounds, which ultimately will turn into higher utilization while the units are up.

Matthew Lucey: In regards to utilization broadly, I sort of think of it maybe in a simplified manner. I think you have a confluence of a number of events. One is if you have a winterless winter or if you have a stormless summer, it certainly makes the operating environment easier to operate if you don’t have disruptions. And then we’ve seen that over the last number of seasons where there’s been minimal impact, whether it’s from storms or from harsh winters. And then you have, obviously, some creep, whether it’s capacity creep, debottlenecking, some increases in throughput. And so numerators may be a bit dated. And then you have this pursuit of operational excellence where everyone is trying to become more efficient and become the best operators they can. And in so doing, you’re able to increase your reliability and increase your throughput. We are on that journey, and we expect it to pay dividends for sure.

Douglas George Blyth Leggate: That’s — it seems to be applying. I observed that Phillips and Valero that between them, they replace Lyondell Houston basically with their better utilization. But anyway, I’m grateful for the input. My follow-up, I’ll add my welcome to Joe and ask him maybe to earn his crust a little bit today. Joe, I don’t know if this is something you can do. But if we try to simplify all the moving parts on the cost, the money going out the door for the repairs, the insurance proceeds coming in, — obviously, you took out the short-term loan to navigate through this — if we normalize the balance sheet, when all is said and done, where do you think your net debt would sit? I’m not talking about contributions from future quarters and so on. When you normalize for the money out and the money in, what would your net debt be if you hadn’t had this event?

Joseph Marino: That’s an interesting question. Obviously, there will be a lot of different factors playing into the market and how our results would be if the event didn’t happen. And part of the issuing of that additional notes earlier this year was in advance of the potential market that we were looking at, at that point. So some of that was outside of purely just Martinez related. So I think hard to specifically answer that question to down to a fine detail, but it would be less than it is today, but probably more than, from a net debt standpoint, than entering the year.

Douglas George Blyth Leggate: I know it’s a tough one to answer. Just to clarify what I’m asking. I’m not looking for the lost opportunity cost. I’m looking at for the extraordinary costs and the extraordinary cash inflows from insurance, if those were all taken out, is that a net debt lower number? Or can you put a magnitude on that or no? We’re just trying to figure out how much did we deduct in our DCF with pure net debt on a normalized basis.

Joseph Marino: Yes. I’d say again, it’s hard to put a fine point on that. Obviously, the cost, as we’ve said before, of actual repair costs are going to be substantially covered by our insurance. So that really won’t have a meaningful impact on our overall net debt whether you look at it on a pro forma or go-forward basis. There’s impact to the business and our net debt profile from the downtime for sure. And we think a good deal of that will be offset by BI insurance when everything is all said and done. But we don’t have an exact impact of what that would look like at this point.

Operator: The next question comes from Neil Mehta from Goldman Sachs.

Neil Mehta: There’s been a lot of talk about moving product into the West Coast as some of your competitors retire capacity with 3 independent projects talked about either to the Southwest or even into California. Just your perspective on whether that can alleviate some of the pressure on PADD 5? And how do you think about timing and potential impacts of that?

Matthew Lucey: Yes. Thanks, Neil. Good to hear from you. In regards to some of the announced projects, I’m not going to speculate in regards to which, if any, are going to get to the finish line. I would just say in the base case — in the base case, we’re going to be very, very expensive. In the base case, you’re going to take a lot of time. And as an observer of the market and as a participant in the market, my guess is that the base case may be aspirational in regards to time and money in regard — I probably tend to take the over on time as nothing is easy. As a result, it’s costing us money, I’d probably take the over. Regardless of how long it takes, there will be substantial tariffs on any new pipes that are built. And so we continue to think our in-state manufacturing facilities will be the low-cost producer.

The state is going to require imports, whether it comes from the water or from pipe, that will be higher-priced imports. And so I think with the sort of rebalancing that has happened within California refining, we’re very, very well positioned from a product standpoint, but also from a crude standpoint. If you have one refinery just came down, one refinery is still scheduled to come down, but you then also have less demand on local crudes as a result. So I think our position in California is particularly attractive and interesting going forward regardless of the potential pipes when they come on, how they come on, they will be coming on because it’s a product short market.

Neil Mehta: All right. Good color. And then early thoughts on 2026 CapEx, recognizing we’re going to get a little bit more color in Q4, and you guys have done a good job keeping a lid on spend this year. But how do you think about some of the moving pieces as you move into ’26? And is there a soft number that we should be thinking about penciling and recognizing we’re going to get a harder number on the Q4 call?

Matthew Lucey: Yes. I would keep to our schedule on that. We do have a heavy turnaround season next year, but we’ll get into that in normal course, Neil.

Operator: The next question comes from Phillip Jungwirth from BMO.

Phillip Jungwirth: I was hoping you could just talk to what you’re seeing this month in the SoCal market, just given the moving pieces with Phillips L.A. closing down two weeks ago. Are you seeing any benefit here? And obviously, we had the unplanned downtime, which really helped get along with other product prices.

Michael A. Bukowski: Well, I would say it’s hard to tell what the impact of Phillips is this — there’s [ tensions ] because there is a tremendous amount of unplanned outages that are going on currently. So as you highlighted, the market is quite dynamic, there’s tensions on everything, gasoline, jet fuels and distillates. So hard to judge these tensions as to what impact the overall markets have with just Phillips going down by itself. But there’s a fair amount of planned and unplanned events going on, on the West Coast, this tension. So it is what we call an all-bid market.

Matthew Lucey: Yes. In regards to just pulling yourself out of like the prompt screen, it is hugely impactful. There’s going to be 100,000 barrels a day less of gasoline produced in the L.A. region. That now has to be imported from outside the state. And obviously, a significant amount of California crudes are no longer going to be procured by that refinery. And those crudes only home is with California refineries. So it will play out. The refinery is literally shut, I think, 2 weeks ago, and there’s been lots of sort of activity in the marketplace, not related to the shutdown. So hard to unpack exactly. But over time, I think our position in California will prove out to be pretty compelling.

Phillip Jungwirth: With California now at least trying to stem the decline of local crude production, issuing permits, how optimistic are you that this could be a benefit to PBF and in-state refiners or at least no longer a headwind with declining production?

Matthew Lucey: Yes. My old joke is, as a refining business, we’re all big boys and we — generally, we don’t ask for help. You simply ask to stop bashing us in the head with a shovel. And so systematically shutting in crude production was a significant headwind. I think with all that’s going on in California, there’s a recognition that that wasn’t the single greatest policy to have in place and fixes have been put in place. So I think it’s a removal of a headwind. It will allow certainly the valley in California to stem declines. And so my other thing as you find yourself in a hole, the first thing you do is stop digging. So hopefully, we can have declines arrested. Whether the valley grows, I can’t comment on. But simply, it’s a very, very positive step to get that legislation through.

We work very, very closely with all the parties in Sacramento. It is hugely beneficial to have it in place because the alternative was very poor. And so our team has worked unbelievably and has worked in concert with a number of constituents in Sacramento, whether it’s the CEC, the governor’s office, with legislators. I think everyone appreciates the importance of supplying reliable, deliverable, affordable energy to the people of California, and they desperately need gasoline and diesel and jet fuel at affordable prices.

Operator: The next question comes from Matthew Blair from TPH.

Matthew Blair: Could you talk about your outlook for refining capture in the fourth quarter? It seems like it could take a big step up. I think you already mentioned that crude diffs are trending a little bit wider, but it seems like other factors might be moving in your favor, less maintenance, less turnaround expense, better market structure, better jet versus diesel spreads, lower RINs. I mean, pretty much everything across the board seems to be moving in your favor. I think you’re in the mid-30% range on capture in Q3. Do you think something north of 40% is realistic for the fourth quarter?

Matthew Lucey: We agree with everything you said — bringing on staff. Look, I think it’s very constructive to look ahead. Crude diffs is the single largest thing. There’s no question about it. And I think they’re set to continually improve over the quarter. RINs is a tough one in regards to — they have been relatively stable in regards to RIN prices. RIN prices are eventually going to have to move up. But of course, that goes to the cost to import as well. And if you look at the marketplace at the moment, it’s pretty interesting. European gasoline is pricing higher than the U.S., not only for today, but out on the strip. And that’s true for Asia as well. And so it sets up a constructive environment whereas either European prices have to come down, and we don’t see that in the short term, or North America, Atlantic Basin PADD 1 prices have to increase to attract those imports. But everything you said, we agree with in regards to an improved marketplace.

Matthew Blair: Sounds good. And then earlier, you mentioned some of the challenges in the renewable diesel space. One of your competitors just threw in the towel on RD. Do you have any thoughts to shutting down your RD plant? Or what’s the thinking there?

Matthew Lucey: Our thinking is that it has been a challenging market. But unlike others, we view our asset as a top quartile asset. And I think there’s a lot to juggle in regards to RD. And you’ve had an administration change where the whole focus of the program has shifted from a low carbon intensity incentive to reduce low-carbon fuels to the new administration, which is really focused on increasing soybean production and use. That change is more than a subtle one, and it’s going to put a number of assets in the pickle. And you couple that with the new rules where imported feeds have a penalty, imported RD doesn’t get the producer’s tax credit, there’s a lot to play out. Much of it points most likely to higher RIN prices. And by the way, higher RIN prices not only because you need to create an environment that makes it economic to manufacture renewable diesel, but also as supply comes off, you have an RVL that’s going to — that’s not going to decline.

And so I do think RIN prices — there’s a risk to higher RIN prices. And hopefully, the administration understands that they’re taking comment now on reallocation and such. But where we sit, it’s no doubt been a very difficult market, but our location and the capabilities that we have at our plant, I think, sets us apart from another — a number of the other participants.

Operator: Your final question comes from Connor Fitzpatrick from PBF (sic) [ Bank of America].

Connor Fitzpatrick: Might have been a mix up there. I apologize if some of this has been touched on before, but we’re hearing that the vessels that need to be installed at Martinez have a 60-day time frame to install and construct. Have those been — have those arrived at the Martinez site yet? We think they also need to be inspected and blessed by Bay Area Air Quality Management, EPA and OSHA. Can federal sign-off be done during the government shutdown? I know you mentioned permitting before, but should there be any further issues as it relates to shutdown and oversight? I guess, more broadly, can you break down the time line of equipment left to be received, authority to construct and shutdown impacts on that and time to place all the equipment into service?

Matthew Lucey: All right. Look, I’m aware, maybe there was some fake news or stories. I would suggest everyone focus on what the company’s official comments are. I’m not entirely sure where you’re getting some of your information. But as I said, we have all of our permits to construct. We have a very good relationship with not only the state, but with the county in regards to get us to the finish line. And we have our plan, again, to commence restart in December, which takes into consideration everything that is required. We’re certainly not going to get into explicit details despite you being in-house as a PBF person, you’re not a PBF employee. We’re not going to get into explicit details on exactly what equipment is being restarted when. But we have a very thoughtful and deliberate plan to restart the equipment, and we’ll have all the approvals necessary to do that.

Connor Fitzpatrick: That’s very clear. I guess I should correct and say that I’m from Bank of America. I think there was a mix up, if you couldn’t tell. I don’t know. That’s the only question I had.

Matthew Lucey: Well, I appreciate the question. And hopefully, there shouldn’t be any confusion in regards to it. And as Mike stated, we’ll always make time for safety, but we’ve got a very, very good plan to get the plant up and running. With that — I believe that concludes our questions. So I greatly appreciate everyone’s time and attention and look forward to very constructive markets looking forward. Thank you.

Operator: This concludes today’s conference. You may now disconnect your lines at this time. Thank you for your participation.