Good day everyone and welcome to the PBF Energy Fourth Quarter 2022 Earnings Conference Call and Webcast. Please note this conference is being recorded. It's now my pleasure to turn the floor over to Colin Murray of Investor Relations. Sir, you may begin.

Thank you, Kevin. Good morning and welcome to today's call. With me today are Tom Nimbley, our CEO; Matt Lucey, our President; Karen Davis, 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 in our press release and those made on this call 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. There are many factors that could cause actual results to differ from our expectations, including those we described in our filings with the SEC. Consistent with our prior periods, we will discuss our results today, excluding special items. In today's press release, we described the noncash special items included in our quarterly results. The cumulative impact of the special items increased fourth quarter net income by an after-tax amount of approximately $60 million or $0.45 per share related primarily to net changes in fair value of contingent consideration. Additionally, please note that our fourth quarter tax rate was elevated relative to prior quarters as a result of the activities in the quarter and fiscal year adjustments. For modeling purposes, please use 26% as an effective tax rate for 2023. Also included in today's press release is guidance information related to our operations for the year. For any questions on these items or follow-up questions after today's call, please contact Investor Relations. For reconciliations of any non-GAAP measures mentioned on today's call, please refer to the supplemental tables provided in today's press release. I'll now turn the call over to Tom.

Thanks, Colin. Good morning, everyone and thank you for joining our call. Fourth quarter capped off a transformative year for PBF. In 2022, our assets generated almost $3 billion of income and earned over $22 per share. PBF ended the year with cash in excess of debt. The market with its tight supply and demand balance, provided tailwinds and the operations of our refineries enabled us to capitalize on the opportunity. Our operations and the focus on strengthening our balance sheet over the course of 2022, allowed us to begin to generate incremental returns for our investors. In addition to renewing our dividend at $0.20 per share for the third quarter of 2022, we announced a $500 million share repurchase program. Under that program, we have purchased just over 5 million shares for approximately $189 million. With favorable market conditions and a solid operating performance, we expect to be positioned to further reward shareholders with increasing returns. To deliver on these commitments, PBF remains focused on our operations and strengthening our financial position. Our assets require continual reinvestment to sustain high levels of safe and reliable operations to meet demand for our essential products. While remaining committed to our core refining business, we are also investing in and exploring new opportunities to produce low carbon fuels. Refiners follow the markets and respond to the demands of the consumer because we are price takers rather than price makers. In 2022, the market was telling us to provide as much refined products as possible. We did. 2023 has picked up where 2022 left off. We are going through normal seasonal gyrations when it comes to specific product demand across our regions. But overall, the market is continuing to call for refined products and as a result, requires high utilization rates from refiners. Many of the key themes that emerged throughout 2022 are continuing to set the stage for 2023. Global inventories of oil remain low but are gradually building off a very low base. The market needs this to happen but it has been proven difficult for inventories to rise to normal levels in the face of demand keeping pace with supply. This is true on the refining product side as well. Refineries are being called to run at high utilization to meet demand. And in 2023, this will be more of a challenge with higher-than-average industry-wide maintenance activity. Global trade patterns are continuing to adjust to the sanctions on embargoes of Russian crude oil and products. We are seeing the impacts of this on the crude side but have yet to witness how the market will accommodate disruptions on the product side. The prospect of China reopening has led to projections of increasing demand in the Asia Pacific region that will have a knock-on impact globally. We remain constructive on product balances in the Atlantic Basin, especially as we look ahead to peak driving season. Global capacity additions are expected to commence operations throughout 2023, which should help meet rising demand. The cumulative effect of all this is that we are constructive on the refining environment in 2023, notwithstanding the amount of work to be completed in our refining system. With safe and reliable operations, we expect to continue the improvement in our financial position and be in a position to potentially increase shareholder returns. PBF is also pleased to announce a partnership with Eni sustainable mobility and the St. Bernard renewables project. We have been committed to the project from the asset and are proud to have a world-class partner joining us in this venture. Lastly, I want to thank all of our employees. The market demanded a lot from PBF in 2022. In turn, PBF asked a lot from our employees and they delivered. The efforts of our employees to keep our assets running safely and tanks for the products constantly on the move to our customers enabled us to achieve this remarkable transformation. Thank you. And with that, I will turn the call over to Matt.

Thanks, Tom, and Tom is correct. Our operating and financial results for 2022 in the fourth quarter are a direct reflection of the tireless work of our employees. In 2022, we produced more than 340 million barrels of total products, the highest level of production our system has achieved with a utilization of over 92%. Again, a testament to the investments we made and continue making in our refineries and the dedicated workers who make it happen every day. In 2023, consistent with industry peers, we have an above-average maintenance cycle to execute. That work has already started in Toledo, Chalmette and Martinez. The deep freeze in December directly impacted Toledo and Chalmette. But fortuitously, we were able to advance maintenance that had been planned for the first quarter, which will help mitigate the impact of the downtime. We will have these turnaround activities completed at Toledo and Chalmette in the coming weeks. We are currently conducting planned work at Martinez which will be finished by the end of this month and have a turnaround starting soon on the East Coast. We have additional work at Torrance and Toledo in the fall. One of the benefits of our geographically diverse, highly complex refining system is that we're able to strategically plan our maintenance to ensure we remain active in all markets and continue to provide needed products to our customers. Supplying the markets with our essential products is what we do and it was demanded of us by our consumers. Over 80% of the world's energy currently comes from fossil fuels. The energy supply cannot be rapidly changed through policies attempting to force a premature transition without significant costs and supply disruptions. It is the impacts of changing laws, policies and politics that are mandating or incentivizing scarcity in parts of the energy stack. Innovation and transition are good for society when approached deliberately. We should be looking at energy addition rather than a forced transition. All stakeholders need to engage constructively to focus on the goal of providing cleaner fuels while maintaining reliable and affordable energy sources that are the cornerstone of our high quality of life while elevating people into the middle class in developing regions. With that, we are more than pleased to have entered a partnership with Eni in our St. Bernard renewable project. This strategic partnership leverages the complementary experience and expertise of PBF and Eni. PBF brings experience in large capital project execution and fuels manufacturing as well as access to the California renewables market through our existing logistics footprint. Eni brings experience in sustainable feedstock sourcing and renewable fuels manufacturing, coupled with access to international markets beyond PBF's domestic footprint. The joint venture reflects both partners' commitment to deliver sustainable transportation fuels using low-carbon intensity feedstocks. As we have stated previously, we were intent on finding a partner that would add strategic value to the enterprise and we believe we have done just that. We absolutely believe SBR will be even more successful with PBF and Eni working in concert. We have gone to great lengths in structuring the partnership to ensure a proper alignment of interest between the partners. As I've stated, we could not be more pleased in forming this partnership with Eni. In further pursuit of increasing the potential energy options provided by PBF, we are also part of a large consortium referred to as Mach 2, which stands for Mid-Atlantic clean hydrogen hub that is pursuing the development of a clean hydrogen hub in Delaware, Southeastern Pennsylvania and South Jersey. Our footprint in Delaware with established manufacturing and transportation infrastructure provides an opportunity to generate incremental value for diversifying our product line with another fuel of the future, in this case, hydrogen. While this project is in very early stage development, Mach 2 has received the encouraged designation from the Department of Energy and will continue to move the project forward. While the Mach 2 consortium has passed one hurdle, we are now in the process of submitting the application for funding with the DOE. The acceptance of that application will determine any funding allocation from the government and subsequently, the extent of future capital expenses in relation to any potential hydrogen business. While we continue to expand our alternatives, the forward refining market looks very favorable. We expect current volatility to persist but increasing consumer demand will continue to support high refinery utilization. Now for the financial overview, I'd like to introduce and welcome our new full-time CFO, Karen Davis.

Thanks, Matt. As Tom mentioned, 2022 was a transformative year. PBF entered the year looking forward to an above mid-cycle environment and with plans to implement a multiyear process post-pandemic strengthening of the balance sheet. We repaid $2.3 billion of debt in 2022 and have now reduced our debt by more than $3 billion since the pandemic after including our recent redemption of the $525 million notes of PBF Logistics. During the fourth quarter, we also completed the buy-in of PBF Logistics which will capture approximately $40 million of cash that was leading our system annually as distribution while saving approximately $10 million in annual expenses. Additionally, PBF will now recognize 100% of the earnings due to the elimination of the noncontrolling interest related to PBF Logistics. For the fourth quarter, we reported adjusted net income of $4.41 per share and adjusted EBITDA of over $1 billion. Our full year 2022 adjusted EBITDA was $4.7 billion. You should note that our fourth quarter EPS was impacted by a higher tax rate driven by several items. The largest of which related to unwinding the tax valuation allowance and adjustments related to the buy-in of PBF Logistics. We fully released our deferred tax valuation allowance during the first three quarters of the year which had reduced our effective tax rate for those quarters below our normalized rate of 26%. Going forward, we expect our tax rate to return to a more normalized level as provided in our guidance. Consolidated CapEx for the fourth quarter was approximately $327 million which includes $184 million for refining and corporate and just over $140 million related to the continuing development of the St. Bernard renewables facility and $3 billion for PBF Logistics. Over the last three years, we used all available levers to maintain liquidity and demonstrate our commitment to prudent balance sheet management. As we sit here today, PBF's balance sheet is its strongest ever and we are committed to maintaining that position. We have excess cash in excess of debt with sufficient liquidity to serve the needs of the business. Through the pandemic to the present, PBF maintained a level of cash above what is needed to operate the business and ensure sufficient liquidity. As we progress through our punch list of the remaining items we plan to address, we anticipate that over time, our cash should return to more normalized levels in the $750 million to $1 billion range. Our gross debt is now below pre-pandemic levels and at a level that we believe is currently appropriate and sustainable for our business. Our financial performance over the past 1.5 years sets the stage for a re-rating of our future prospects. Quantitatively, we meet or exceed many investment-grade metrics. Our refinery should continue to demonstrate through-cycle earnings power and we are adding diversified earnings streams as we enter the low carbon fuel space. We will continue to exercise balance sheet discipline targeting rating agency-driven metrics. With our balance sheet improving during the fourth quarter, we reinstated our quarterly dividend and implemented an active share repurchase program, returning over $180 million to our shareholders. With the macro backdrop for refining translating into higher mid-cycle financial performance, our highly complex and geographically diverse refining and logistics systems are well positioned to generate significant value and provide increased shareholder returns. Operator, we completed our opening remarks and we'd be pleased to take questions.

Our first question today is coming from Roger Read from Wells Fargo.

Karen, welcome back, I think we get to say to PBF, not just welcome to. Question I'd love to dive into here is the most obvious one which is this joint venture agreement with Eni, recognizing that it's a definitive agreement it hasn't closed I'm just curious when you expect it to close, is it an all-cash transaction up front? And where do you think the product goes? Does this mean it's more likely to go to Europe than to California which I think most of us have assumed from the get-go?

Thank you, Roger. I'm going to turn that over to Matt. He and his team have done unbelievable work in bringing this to fruition but I do want to reaffirm how pleased we are because all along, we had — with the good year we had financially, we knew we could fund this project ourselves if we had to but we had a strategic objective of finding a partner that would bring value to the JV. And as Matt mentioned, that's exactly what we did. So we have the right partnership going forward.

So Roger, I think you asked maybe three different questions and feel free to follow up if there's anything else. But when — look, we have to go through customary approval processes. We signed the agreement just over the last 24 hours. And so there's customary approval processes within our country, whether it's HSR/CFIUS, there may be one or two other jurisdictions outside the U.S. that Eni needs to work through. So I expect it will be a couple of months before closing. It could be a little bit faster, it could be a little bit slower but we do have to go through those sort of approval and regulatory processes. It is all cash — the cash will be paid to PBF, sort of split half and half between signing and — I'm sorry, between closing and when the pretreatment unit becomes operable and so at closing, Eni will contribute to PBF about half of the purchase price. And then once the renewable diesel unit which we expect to come online over the next month, and then once the pretreatment facility comes online, in both our operating in concert, the second payment will be made. In regards to where the products go, this is very important and it was very important in finding a partner where there's alignment of interest, as I mentioned, the products will go to whatever the highest netbacks wherever the markets are calling for the products the most. And so over the course of last year, that's been California. But it's very possible over the course of next year. It could be in Europe; regardless of where it is, the two partners are committed to delivering the products to what will be the highest economic benefit for the entity. And clearly, to the extent that Europe is going for the product, there's no question that Eni will be able to add significant value on our execution of that.

Appreciate that. And yes, I mean, we're all kind of skilled and managed to put three parts in one question. My only follow-up is, Tom, I think you mentioned Atlantic Basin looks still pretty tight on the product side. Just what are your thoughts as we head towards spring and gasoline season, spring and early summer in terms of what may be competing product-wise imports from Europe, things like that.

Very good, Roger. And once again, you've demonstrated your ability to get a number of questions in. Congratulations. We are constructive. Obviously, all built on the fact that the inventories while I've been building and I can't make sense of the stat numbers that came out yesterday. I don't know how we built $16 million accrued but I'll leave that aside. The fact is inventories pretty much across the board across the — in the U.S. and across the globe are tight. They remain well below the five-year averages in most cases. And in PAD 1, even though there was a big build in PAD 1 in both gasoline and distillate yesterday, below the five-year averages on gasoline and distillate. So we see — we are constructive. We are also constructive on or believe that we're going to see some tailwinds behind gasoline as we move into the driving season. We're going to obviously be going to low RVP gasoline. We're going to be taking the butanes out of gasoline. We're going to be taking octane away when we do that. because butane has a high octane, so we're going to wind up having some strength likely a widening of the ARPOB/PBOB spread. So overall, we think that things are looking reasonably positive for products and perhaps gasoline will be leading the way there. Tom, would you have anything you would add to that?

I mean I think just to reiterate your point there, I mean, as gasoline's got a constructive setup as we're heading into the driving season. distillate has clearly been the market leader. It's gone through a little bit of a wobble with a mild winter and as we're really trying to work through with the Russian balances of gas oil is going but certainly leadership at this point is — could be moving towards gasoline but the distillate balances still remain constructive as well.

Our next question is coming from Neil Mehta from Goldman Sachs.

Congrats, Karen and congrats on the joint venture. Maybe I'll start on the joint venture, I think on the last call, the team indicated you think of the project as $400 million of normalized EBITDA. Just wanted to get a now cast of that number and remind us how much capital is left to be spent on the project at this point?

So if you look over the last year, EBITDA has ranged between $1 and $1.50 a gallon EBITDA margin. And we're going to be generating or producing just over 300 million gallons a year. So that being said, markets will tighten and loosen at different times. But that's what's happened over the last year and that's sort of what it looks like currently. So we'll stick with that. In regards to how much of the project has been spent on, we have approximately $200 million left to spend, thereabouts. And then obviously, Andy will come in sort of when we close and when we become operable, that will offset the spending for PBF clearly.

Yes, that's really clear. Okay. And then on cash balances, you're at $2.2 billion. Karen, you had indicated you want to get to $750 million to $1 billion of cash over time. Do you have — how should we think about the cadence of how long it takes to get to your normalized cash balance, especially because you got incremental cash coming in associated with the joint venture? And then what is your preferred way of getting that cash down? Is it through buybacks?

Again, multiple questions. But first, a reminder that although we did finish the year with a pretty high cash balance at $2.2 billion, there are a number of calls on that cash. First of all, a reminder that we did redeem $525 million in additional debt just a few weeks ago. Matt mentioned completion of the project about $200 million and we have a very heavy turnaround schedule in addition to repurchasing shares. So there will be a very disproportionate use of cash in the first half year. With respect to return of capital, financial resilience in the balance sheet are always going to come first. We're going to ensure that the base business is sufficiently funded and prepared to weather adverse marketing conditions. And you should also be thinking that included in that we'll be funding our annual capital program which should average in the $600 million to $650 million range over the long term. Like 2023, where we have a heavy turnaround schedule, it will be more other years it will be less. And as the cash generates cash or as the business generates cash beyond that, then we'll expect to be in a position to continue and potentially increase shareholder returns. But given that we just restarted our dividend and approved our first buyback program, we're not in a position to comfortably provide an additional guidance on the pace of returns. Having said that, we believe it's important to maintain a competitive dividend with room to grow and to fund buyback programs when it's appropriate.

Your next question is coming from Doug Leggate from Bank of America.

Karen, congrats on the permanent seat. Now you have to deal with all of us. Forgive me for beating on Neil's question but let me maybe just ask it differently. Why should we not think about the proceeds from the joint venture translating directly to share buybacks? Because your operating cash flow takes care of all the other things you talked about. So are we looking at a 15% buyback with the cash inflow from the JV?

Well, first of all, I'd say we are just delighted to be partnering with Eni and at the moment, just focused on closing the deal.

We would never discourage you to think any way you want. It's a futile — any attempt would be futile. But look, we've been very, very focused on getting the transaction to the point where we are today. The transaction hasn't closed yet and I learned a long, long time ago not to figure out ways to spend money that you don't have in your pocket yet. Clearly, the company will put forward policies that are appropriate at the appropriate time but we have nothing else to add at the moment.

Terrific outcome regardless. Guys, my second question is kind of a micro question but a little nuanced. At the end of last year, folks were getting pretty agitated about the heating oil position in the Northeast. And it seemed to us that was like the first normal winter without — since COVID without Philadelphia Energy Solutions refinery in place which there's clearly a change in dynamics of the East Coast market. So I guess my question is, what are your expectations for where I say the first normal driving season in the Northeast which is obviously your backyard. Do you think the dynamics of that market have permanently shifted but perhaps not become fully apparent yet given we've had three years of COVID since that refinery shut? I'm just curious for your opinion.

That's a great question, Doug. I'll tell you my view. I am sorry. Roger has already had his turn. I'm sorry, he does. Actually, I believe what you said is correct. We should go back to the fact that there's a couple of things that work in all benefit. But PES going down was a big deal. We — that was obviously the largest refinery in PAD 1. The pipelines are pretty much coming up from the Gulf Coast. So when you get — and that was certainly the case with the distillate situation, as people were concerned that we would not be able to fill in the market. In addition to PES, we had come by chance go offline as a result of the pandemic. So PAD 1 has gone into a situation where chronically, it was always been you all know this. It's a dumping ground for Europe to move gasoline in. Now we've got a different situation in Europe and we have a significantly different situation in PAD 1 and in fact, in the U.S. and of course, globally because of the amount of capacity that's been rationalized. So, I think it's got the potential to be a structurally short market. And when you see — we'll see, we're going to demonstrate it right now. Bayway FCC is going through a turnaround. That's a big gasoline producer, obviously very large cat cracker. But we saw that manifest itself. We've seen it manifest itself in spiking jet prices and distillate prices where there was a concern about supplying the market. We're not going to see what we had last year, I don't believe. But in fact, I do think that is a strategic shift in capacity utilization. And we're going to have to run off or hard to meet the product demand in the country, in the world and in PAD 1.

Our next question is coming from John Royall from JPMorgan.

I just had a question on the $8 to $8.50 per barrel OpEx guidance in 2023. It looks like a top fair amount from '22 which is already elevated despite lower natural gas. So has this increase all on maintenance? Or are there other drivers you should be thinking about?

Certainly, there are other drivers. And that right now, obviously, Henry Hub on gas prices but that's not necessarily the true for the other regions in the country. So we've got some increases in energy cost but we also are seeing inflationary pressures in a lot of the business that have resulted from the fact that inflation is high. So — and the other thing we've got is the increase in turnarounds that obviously there's — that's capital cost but there were some other additional maintenance costs that go along with that.

Great. That's helpful. And then I think, Tom, you mentioned in the opener, you've spoken about the Europe sanctions the February 5 date has come and gone, so far, it felt like a nonevent but still very early days. And so how do you expect those actions to impact the market as we get deeper into the year?

Well, it's going to be — I'll ask Tom O'Connor to add value on this but it's a work in progress right now. Obviously, Russia came out last Thursday and said they are going to decrease crude production by 500,000 barrels a day. And they said that was because of their payback on the sanctions that have been put on them. Some people have said that they think that's because of the fact that the export ban on products went into place or the caps that in fact, they have to start to shed runs because they're starting to build inventory. Recognize that Russia pumped a bunch of diesel into Europe in January in advance of the February 5 date. And in fact, that has had an impact on the marketplace. It's just simply too early in my mind for us to see whether or not which way this is going to go. I think there's some chance that it could be like crude. They're going to find ways to get trade flows done and they are going to sell more barrels to Africa, that's clear. But whether or not they can sell all of the barrels that are being displaced because they can supply the European market is something that remains to be seen.

Yes. I mean I think what adds to that is the front-loading, as you Tom described, is really important to talk about at this point. I mean Europe really did front-load an awful lot of demand in December and January. And now we got to find a home for the marketplace needs to find a home for, just call it, 600,000 barrels a day of diesel that had been going into Europe. We've seen so far, about half of that seems to have found some homes, whether it's been in South America or in West Africa. The other half is less observed at this point. So I mean, to call it a nonevent, I think we don't really know the outcome of the event. I think what we can say is prices have come off but I think that's kind of the combination of the buildup and in front of it. And then also once again getting back to the mild winter. But I think, as Tom said, really kind of over the next several months, we'll have a little bit more transparency in terms of the data that we can see where those trade patterns have adjusted which would include Europe at that point, taking more product from the U.S. or from east of Suez to satisfy the supply that they've lost.

One thing we can definitively say is as a result, both on the crude side and on the product side as a result of the trade patterns being dislocated. The cost of transportation to get to the marketplace is going up. Freight is going on. And that will ultimately put a foundation about — as an advantage if you are in a trip area where you are producing your products and not having to put them on a boat and selling them into a marketplace.

Next question is coming from Matthew Blair from TPH.

First one, could you talk about the dynamics in the East Coast jet market? What's been pushing cracks up? And are you capitalizing at Del City in Paulsboro.

Well, supply and demand is the answer to your question. We've had recovery in Jet, and we are continuing to see recoveries in Jet worldwide. By the way, China is showing some significant increase in their flights. But Jet is — appears to be on the move up in 2023 and, in fact, likely could be back to pre-pandemic levels. As I said and I'm going to ask Paul Davis to comment on this but we've got relatively tight inventories. Obviously, we've had a situation where diesel distillate was very strong. So you were making a lot of distillate mainly out of gasoline but — then all of a sudden, we get to the point that Jet starts to spike because the amount of imports coming in on jet into the country have been relatively low, extremely low. In fact, because there's demand in other parts of the world. So it gets back to the point that Doug and others have asked about the PAD 1 region has got less capacity, refining capacity than it has under the normal demand environment. that was masked by the fact that we didn't have a normal demand environment. As we recover, all of a sudden, the capacity that's been taken offline is becoming a fact that when you look at the conveyance and pipelines being filled from the Gulf. Paul, would you add anything to that?

Yes. I mean one of the contributing factors to the Jet run-up is the winter storms that we had in the Gulf Coast and as we ended the year as we started maintenance in the Gulf. The lack of jet production from Asia has been closed on Jet since early fall and it's just the supply and demand balancing act and eventually that type is coming off, as you said.

Great. And then where are you at on the outstanding environmental obligations for RINs and AB32? I think the previous number was around like $1.2 billion. And then what's the cadence for paying that down in 2023 and 2024?

Matt, the environmental credit was approximately $1.4 billion at year-end and RINs was $1.1 billion of that. We have extended our RINs payables as part of our overall working capital management while managing our program to be compliant with all of its deadlines. We turned in the 2020 vintage in December. We have the 2021 vintage secured and ready to be turned in, in March, and we're managing the 2022 vintage towards its due date in September. Remember that the renewable diesel facility is expected to produce about $500 million RINs annually and we're going to be able to incorporate that production into our RINs management strategy when that's up and going. So you'll see the liability reducing, especially as the renewable diesel unit comes online and as we approach compliance deadlines later in the year.

Your next question is coming from Paul Sankey from Sankey Research.

Welcome, Karen. Guys, could you just talk a bit more about people, I guess, I should say. Can you talk a bit more about turnarounds as you see it? I mean you made some very interesting comments about the structural reduction in global refining capacity — on a small cyclical basis, can you talk about your own outlook for turnarounds and also how you see the industry? I noted, Tom, there were some comments about the industry having been running very hard and having to turn around more. And I just wondered if you could help us think about 2023.

Sure. Thank you, Paul. By the way, the industry has got a very heavy turnaround cycle going on right now. and it is because with the demand pull in 2022. And obviously, the attractive margin environment, it was an incentive, obviously, to figure out how to safely and reliably continue to run your equipment and that meant that we were pushing out some turnarounds or doing scats instead of doing a full turnaround to get capacity back. But the units require maintenance. And what we're seeing that right now in the country is there's a very, very high turnaround period here in the first quarter and going into the second quarter in the U.S. And we are not immune to that. But we obviously, as Matt mentioned, we had scheduled turnarounds at Toledo and Chalmette for later in the first quarter but with the Christmas bomb that hit taking off some equipment we wound up — and it's not the right — not perfect but we wound up advancing those turnarounds and in fact, we're about to wrap them up, both at Chalmette and Toledo here by the end of this month or early into the next month. We had a scheduled turnaround, a rather significant turnaround in Martinez that is underway, that's on the flexi-coker block, as we call it. That's a big turnaround. But that one also is going along reasonably well right now. And we would expect to have that turnaround behind us by the end of the month, early next month. And that leaves us with — for the balance of the first half, one significant turnaround and that is in Delaware where we're going to take the fluid coker down and the coker block down. After that, the second half is going to be relatively benign for us. But it is a very, very heavy turnaround period for the industry. as we effectively repay the equipment and keeping a good work in order as we go forward. And I think that will be constructive obviously because there's going to be lower utilization in the first half of the year.

Thank you, Tom. I missed the chance to make my Roger Leggett joke but I would.

I would have been disappointed if you didn't do that.

Yes. Well, the whole call is at me thinking about follow-up questions, a number of questions and everything else. The follow-up, Tom, would be just we are struggling, obviously, with this DOE number yesterday, you mentioned it yourself. And I just wonder if that turnaround I mean I think we all know that the inventory data in theory is the good part of the data, right? So I just wondered if you could further think about quite what's going on and whether it is related to turnarounds that we would see such an enormous build as you mentioned.

Actually, I looked at it when the stats came out and did my own little research, not the net that you folks do but I don't think it's a concern around I don't because the actual refinery utilization was down a couple of hundred thousand barrels a day. So a couple of hundred thousand barrels a day times a build of crude. I just can't make the crude number work. I was actually not concerned about the product side of the equation. We obviously had a drawer in distillate which is addressing and we had built and gasoline but it's the crude side that is. So I regret to tell you I have no great insight on it. I could not find a reason why it would be anywhere near the level of build that we had.

Your next question is coming from Paul Cheng from Scotia.

A couple of questions. First, I think on — go back to the joint venture. Can you maybe discuss about the division of labor between the two partners? You say definitive way each partner is going to be in charge of something or that this is going to run differently. And also that what the PBF accounting-wise is going to consolidate the result and have a minority interest or that you guys are going to use equity accounting here? The second question is, when I'm looking at the fourth quarter result, I'm not sure why kind of on the margin capture is so bad. I mean, Gulf Coast, at least the margin capture that maybe is because of the high sulfide or low sulfide diesel defense but I'm not sure why canine margin capture is so bad. And also in the mid-con to let even taking into consideration of the downtime, it seems like the utilization is really low Yes, is the January that you're running at, say, 20,000, 30,000 barrels a day that low.

All right. Well, you just book the record.

Let me handle the question on the West Coast on capture rate. The fact is that two things happened on the West Coast that were rather important and impacted the West Coast. One is the fact that cracks actually came off rather substantially in the month of December. But more importantly, particularly in Northern California but even throughout California, natural gas pricing rooted in the month of December and in fact continued to be elevated in the month of January is only now correct. So we had very high operating costs and Martin has much more than we would expect to have going forward or have had in the past, totally associated with elevated natural gas pricing. So there's a real explanation for why the capture rate was what it was in the West Coast. By the way, the capture rate in Chalmette is lower than what we perhaps would normally see but that's because we took downtime in October which is the strongest month of the quarter. And Toledo was impacted by some downtime even in advance of the ban on at Christmas time.

In regards to the JV and the division of labor, as you referred to it, the joint venture will be its own platform, PBF and Chalmette refinery will be the operator of the equipment. But the St. Bernard renewable effort will have its own team, a dedicated team in executing the business of the renewable diesel business here. And we currently have a general manager in place as we've been developing and working on sort of standing up the business for some time. Both parties will contribute members to the team and both parties will rely on each other's expertise to provide services. And so we've got semblance of the early part of the management team but that will be augmented with expertise from Eni which we're looking forward to. So it's — partnerships can be structured in different ways. This partnership is set up as its own company. We'll have a board with two different partners that have board seats on it, PBF and Eni. And we'll have a management team responsible for executing the business. And that will include people from PBF. It will include people from Eni, it'll include people that have been hired specifically for the role outside of both organizations. We've already identified specific roles that specific partners can add. And so it's been very constructive up until this point. In regards to the forensic accounting, I'll give that to Karen.

Sure. Paul. The determination of whether or not we consolidate the JV or whether or not we account for it under the equity method is yet to be determined. We're still evaluating that. But we are committed, regardless of how that comes out to provide fulsome financial and operating details. So you'll be able to model and fully understand how it contributes to PBF.

Your next question is coming from Jason Gabelman from Cowen & Company.

I wanted to ask a follow-up on the renewable diesel project and joint venture you announced today. Can you discuss, one, when the unit is starting up because you mentioned — the second payment is contingent on that. And then if there's any structure to paying out the cash that the joint venture generates does well, preferred return upfront. Or is it kind of split evenly as the cash is generated from the joint venture? And then my second question is just on the macro outlook, specifically related to heavy light diffs, on the crude side, they remain very wide. I think some had expected those to narrow when the SBR releases ended. What are you seeing in the market that's resulting in those differentials staying wide? And do you expect them to stay wide looking out through the year? Or do you expect them to narrow as new global refining capacity comes online?

I'm going to take the last part of your question. The last question you had and give you my views on it. There's an old expression in horse racing that there are certain horses that are right for the cost and certain courses that are right for the horses you have in your stable. Where am I going with this? Well, we obviously have a very complex refining kit and as we were coming into 2020 with IMO on the horizon, we felt like we were being rewarded for that. Prior to that IMO, obviously, we were not being rewarded for our complexity because, frankly, of the shale oil boom. And then we went into COVID and demand got crushed. So there was, again, headwinds against it. Those headwinds are gone. I am is real. It's, in fact, in place. Clean dirty spread differential between high sulfur fuel oil and ULSD or even now as the ULSD market has contracted quite a bit, are running at $50 to $55 a barrel in the Gulf Coast and on the East Coast. So in fact, we are seeing benefits from a widening of not only the light heavy spreads but also the clean dirty spreads but we are seeing — it's going to come back. I mean there's no doubt about it as more production comes online. But the fact that Venezuela is actually starting to supply some barrels in the marketplace is a positive for us. So, I personally — and I'll ask you to Tom, Paul, if they want to add anything on that — but I think that this is an environment that is going to be beneficial for the kick that we've got.

Yes. I mean just — I mean adding on to what Tom was saying, I mean, certainly in 2022, we can certainly say that upgrading capacity was stretched to its limits. I don't think we've seen anything in the near term that has changed that. So that certainly is a positive nature for wide — light heavy differentials. I think the wideness that we are currently seeing or saw in the fourth quarter only is contributed by the winter storm and the heavy turnaround activity. So on a medium to longer term, certainly in the wider than mid-cycle differentials. And then as we get further down the curve and we've got new capacity additions, that's probably just a little bit beyond our runway right now to be speculating as to where dips are going to be in '24 or '25. But in the near term, certainly wider than mid-cycle.

And in regards to renewable diesel and the timing, the project comes on in two stages. You have what was the hydrocrackers now, the renewable diesel unit. That will come on first and we'll actually line out that unit with vegetable oils because we don't have the pretreated facility up and running. And then the pretreatment unit will come on or is scheduled to come on mid-second quarter. And with that, you have the expectation that—or at least some chance that the joint venture will probably close in the middle, if you say it takes 45 or 75 days to close the transaction, there's a reasonable chance that the closing of the partnership will be after we start up the renewable diesel same but prior to the pretreatment facility being lined out. And as I said earlier, the dollars will flow. I'm not going to get into the specifics of what you guys can— I think we're making all the appropriate filings but it's about half will be paid at closing—and then the other half will be paid once the pretreatment facility is up and running. And then, you do have an incremental $50 million which is not based on stretch goals but it's based on us meeting our timing expectations as well as the unit performing the volume standpoint, we expect it to operate that will flow in sort of as those thresholds are met. So it's pretty straightforward. I would just make one caveat. This is nothing to do with your question but I'll mention it is just a reality of entering the renewable diesel business because so much of the business is on the back of regulatory credits. Your first 6, 9 months of operations are impacted financially by arbitrary carbon scores, meaning it takes a while for the regulatory agencies to confirm all of the low carbon intensity fuels that you may be running. So for a period of time, your—as I said, your carbon intensity score is a fixed number. And then, as you work with the agencies and everything gets embedded, it becomes straight away. But that's just a lining out issue that will occur from start-up going out 6 to 9 months.

Great. And then can you comment on the payout structure, if there's anything out of the ordinary of people putting cash?

It couldn't be more simple. They pay cash, cash.

We've reached the end of our question-and-answer session. I'd like to turn the floor back over to Tom Nimbley for closing remarks.

Thank you very much, everyone, for joining the call. We look forward to updating you further at the end of the — when we do the first quarter call. Have a great day.

Thank you. This concludes today's conference. You may disconnect your lines at this time. We thank you for your participation today.