PBF Energy Inc.

Good day, everyone, and welcome to the PBF Energy First Quarter 2020 Earnings Conference Call and Webcast. At this time, all participants have been placed in a listen-only mode, and the floor will be open for your questions following management's prepared remarks. You may register to ask a question at any time by pressing the star and 1 on your touch-tone phone. It is now my pleasure to turn the floor to Colin Murray of Investor Relations. Sir, you may begin.

Thank you, Brie. Good morning, and welcome to today's call. With me today are Tom Nimley, our CEO, Matt Lucey, our president, Eric Young, our CFO, and several other members of our management team. A copy of today's earnings release, including supplemental information, is on our website. Before getting started, I'd like to direct your attention to the safe harbor statement contained in today's press release. In summary, it outlines the statements contained in the press release and on this call, which 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 describe in our filings with the SEC. Consistent with our prior quarters, we will discuss our results excluding special items. For the first quarter, this is a net 933 million adjustment consisting of after-tax, non-cash, lower of cost or market or LCM adjustments, change in tax receivable agreement liability, and debt extinction costs related to the redemption of the 7% notes due in 2023, which were partially offset by a change in the fair value of the earn-out provision included in connection with the Martinez acquisition, which in total decreased our reported net income and earnings per share. As noted in our press release, we'll be using certain non-GAAP measures while describing PBF's operating performance and financial results. For reconciliations of non-GAAP measures to the appropriate GAAP figure, please refer to the supplemental tables provided in today's press release. Also included in the supplemental information provided with today's press release are the consolidated results of our Martinez Refinery, now included in our West Coast system as of February 1st, 2020. If you have any questions about this new information or presentation, please contact Investor Relations after the call. I'll now turn the call over to Tom.

Thanks, Colin. Good morning, everyone, and thank you for joining our call from wherever you may be working. The results for the first quarter seem somewhat inconsequential, given the challenging start to 2020. We all experience our own unique set of circumstances as we manage our daily lives as individuals, families, communities, and companies in the face of the measures necessary to navigate the impacts of the COVID-19 pandemic. Through our refining, logistics, and commercial operations, we have seen the effects of COVID-19 demand destruction on our business firsthand. As a result of the nationwide stay-at-home orders, We estimate demand for gasoline bottomed at around down 50% from last year's level in early April, with demand for other products down as well. In response to the pressures of the pandemic, PBF has taken a number of aggressive steps to protect our business from the virus impacts and resulting demand destruction. We significantly reduced our capital expenditures for the remainder of 2020. We have increased our initial reduction of $240 million announced in March to an aggregate decrease of $360 million in 2020 planned capital expenditures. This represents a 50% reduction to our original guidance. We intend to satisfy all required safety, environmental, and regulatory capital commitments while continuing to explore further opportunities to minimize our near-term capex. We have identified a number of opportunities to lower our 2020 operating expenses by approximately $140 million. We lowered the corporate overhead expenses by over $20 million, primarily through temporary salary reductions for more than 50% of our corporate and nonrepresented workforce and continue to target other areas for savings. We suspended our quarterly dividend, which will preserve approximately $35 million in cash each quarter to support the balance sheet. And through the sale of five hydrogen plants located at our Martinez, Torrance, and Delaware City refineries, we generated $530 million in cash proceeds, and we continue to evaluate various other liquidity and cash flow optimization options. And finally, last week, we raised $1 billion to a successful bond offering. Our total projected cost reduction measures amount to more than $600 million in expected savings in 2020. Some of these measures are temporary, but should result in long-term benefits. We are taking these and other steps to counter the impact of the unprecedented headwinds we are facing. Since late March, we have reduced runs by approximately 30%. to put that into context, coming into 2020 we expected to run approximately 950,000 barrels a day through our refineries and we now expect to be in the 650 to 750,000 barrel a day range. We expect to be in that range until demand improves and we will adjust our operations regionally depending upon market conditions. Across our refining system, Due to the complexity and configuration of our facilities, we have the flexibility to idle certain units and scale back operations to balance our production with prevailing demand. We are not the only company facing these market conditions, and our competitors appear to be responding to the market in a similar fashion. We are also seeing some companies take the harder decision to completely shut down refineries. Two facilities have shut down domestically, and several more facilities have been shut down in the Atlantic Basin as a result of high cost and low margins. The refining sector as a whole has responded to the market conditions and done a good job of aligning product supply with demand. We are taking all the necessary actions to ensure that we emerge from these trials a stronger company and we remain fully committed to our base assumption that complexity matters. Our complex and geographically diverse asset base provides us with a stable platform to build a strong future. Many uncertainties remain with respect to the lasting effects of the pandemic and the impact it has had and will have on our economy. From a hydrocarbon perspective, it certainly appears that we have hit a bottom and we are seeing some signs that demand is returning in some small measure as the states manage their individual recovery paths. Even in these trying times, as always, the health and safety of our employees and our community partners remains our top priority. We will continue to operate our assets in a safe, reliable, and environmentally responsible fashion. Now I'll turn the call over to Eric to discuss our current liquidity and financial position.

Thank you, Tom. Today, PBF reported an adjusted loss of $1.19 per share for the first quarter and adjusted EBITDA of negative $3.8 million. These figures include approximately $11.5 million of transaction-related expenses. Consolidated capex for the quarter was approximately $139 million, which excludes amounts paid in connection with the acquisition of the Martinez refinery. The consolidated capex includes $133 million for refining and corporate capex, and six million for PBF Logistics. As a result of the reductions to our 2020 capital budget, we expect to incur roughly $15 million of CapEx per month from May through the end of the year. In addition to the 600 million of cost reductions, we executed two strategic transactions to boost liquidity. We completed the sale of five hydrogen plants to Air Products for 530 million and issued one billion of senior secured notes last week. As of May 1, 2020, after giving effect to these transactions, our liquidity was approximately $2 billion based on our estimated $805 million of cash and $150 million of additional available borrowing capacity under our asset-backed revolving credit facility. When combined with PBF Logistics, our consolidated liquidity is more than $2.2 billion. Assuming current commodity prices remain relatively constant, we expect our liquidity to improve as working capital continues to normalize in May and our revolving credit facility borrowing base increases. Operator, we've completed our opening remarks and we'd be pleased to take any questions.

Certainly. At this time, if you'd like to ask a question, please press star and one on your touchtone phone. You may withdraw yourself from the question queue by pressing the pound key. Again, that's star and one. And we will go first to Roger Reed with Wells Fargo.

Good morning. Hopefully, can everybody hear me? Yes, Roger, we can hear you. Okay, good. Thank all of us for this work-from-home thing. Never really know. Just a quick follow-up there, Eric, if we could, on your liquidity comments. So if we look at the comment or what's written in the press release, $858 million, after giving effect to the $1 billion secured debt that was issued later in May. Should we presume that you paid back revolving debt? I mean, I'm just trying to understand how you add a billion and have less than a billion in cash on hand, kind of what the moving components were. And then as we think about working capital within that, since inventory numbers that were reported were lower, I'm guessing we're looking at an accounts receivable, accounts payable, where most of the working capital is trapped at this point.

Roger, the cash balance of $805 million was the balance pre-transaction as of May the 1st. So then you take the, call it roughly billion dollars, I think the net proceeds were closer to $987.5 million after all fees and expenses. That's how we're getting to the $2 billion. So the $805 plus, call it, the incremental billion dollars of cash from the bond deal plus the availability under our ABL.

Okay, all right, thanks, that's helpful. And then on the working capital side, the moving parts there?

Yeah, the biggest pieces on the working capital, during the course of the quarter, clearly as prices declined, we did see cash move out of the system through working capital. We do carry, we are essentially long payables when we think about, right, we're paying North American crude payment terms. There's typically a lag of anywhere from four or six weeks there. So in a declining flat price environment, we will ultimately see what we're paying during, for example, the month of April. We paid for barrels, half of the barrels that we basically priced during the month of March. So when you start to see $10, $20 per barrel moves month over month, you will ultimately have a lag there Thank you very much.

And just as a quick clarification on that, should we think of it as an average price in a month or should we think of it as where prices were as of March 31st versus where they might be on June 30th when we're trying to compute the effect?

The easiest way to do it, there's a significant amount of science involved because crude prices, depending on whether it's CMA or individual pricers, The easiest way to think about it, though, is on a CMA basis. There will be fluctuations, though, month over month, because we will end up, right, we're going to run whatever is the most economic crude. Some of that specific crude we may buy for three months and then not buy again for another three months. But I think for what you're doing, ultimately using CMA is probably the easiest way to think about it.

Okay, great. Thanks. And then, Tom, if I could go back to you, just You mentioned maybe some signs of demand starting to creep back into the market, and it looks like some other indicators would show us certainly an improvement over the low parts of April. But you've got more exposure to East Coast and West Coast, which have been two of the weaker markets. I'm just curious if there's anything you can kind of incrementally help us with there.

Yeah, we track this obviously diligently. If you take a look at As I said, gasoline at the trough nationwide was down 48% or close to 50%. Pad 5 was down 48%. Pad 3 was down 43%. Pad 2 was down 47%. And Pad 5 was down 45% from last year's levels. Now, if you look at the last set of reported numbers that I had, now we're down all pads 24%. from last year's level, up from 5.1 to 7.5 million barrels a day in the last reported EIAs. And the improvements have been actually more pronounced in Pad 5. We're now down only 25%. There's a lot more traffic, apparently, on 405 in California. Pad 3 has moved from 43% in the last year to 27%. Pad 2, 47% to 33%. and Pat Warren is the lag and 45 and is now rebounded to only 35 to 35%, I shouldn't say only, less than last year. And again, obviously this area of the country is a little bit slower in opening up than most of the other regions.

Okay, great. Thank you.

We will go next to Manav Gupta with Credit Suisse.

Hey, guys. My first question is on Toledo. The gross margin capture was a little weaker than expected, and I understand there was a big turnaround, and I'm just trying to understand if that was the only reason because of which the gross margin capture was a little weaker, or were there some other factors in MidCon? And the broader question is, we understand that MidCon gasoline demand has recovered the sharpest, In fact, some people are indicating it should be as high as 90 to 95% of normalized levels. So do you plan to run Toledo harder into 2Q versus some of the other assets?

Okay, there's three parts to your question. First of all, Toledo, the capture rate in Toledo was impacted not only by the fact that we had a turnaround, but candidly, we had to bring the unit down earlier than we planned to. because the unit had decided it was tired and it was needing some rest. I'm being a little facetious there, but we basically had a number of mechanical problems on some boilers, and so we accelerated the turnaround by three weeks, and that actually impacted the efficiency of getting ready to execute the turnaround. Then when we completed the turnaround, we were sitting there looking at double-digit negative gas cracks, and we said, well, this is not the time to be bringing up a catcracker that makes gasoline. So that unit has been down. In fact, it was really a prolonged turnaround, much more than a couple of weeks longer than what we had expected and planned for. Second part, we are seeing demand increase, and the numbers I had are not quite as strong as what you're saying. Hopefully it'll get there. But we are going to be very, very diligent. We are just not going to do what everybody expects refiners to do. See an improvement in gasoline, crash and say the holy grail, there it is, let's ramp up, let's run. This thing is not over. I'm looking at distillate and what we did across our whole system and everybody else did is to unmake gasoline and unmake jet. We cut runs significantly, but we also turned the and turn gasoline and jet fuel into distillate. And distillate is actually something we're looking at as we go forward, being very careful that we're not building distillate inventory in a manner that is not prudent. So we will likely start up the FCC, but candidly, we won't be running any more crude, maybe a couple of thousand barrels a day more crude in Toledo until we see that we've gotten above the waterline. Thanks for that, Tom.

A quick follow-up. Now, you have hard Martinus for about a quarter. Is it performing up to your expectations? I'm asking this question because when you initially acquired Torrance, you kind of realized it needed a little more work than you initially thought it would. So, is Martinus an asset in a condition in which you expected it to be delivered?

Thank you. Actually, so far, we obviously took it over February 1st, and absent the impact from the margin side from the pandemic, I will tell you it is a first-class asset for the first-class workforce. It is not the Torrance situation. It is not the Chalmette situation that we inherited when we bought those troubled assets. We said that we thought we were buying a first-class facility, and I'm very confident that, in fact, that's the case. These folks are really good oil boilers.

Thank you so much for taking my questions.

We will go next to Prashant Rao with Citi.

Good morning. This is Joe on behalf of Prashant. I just want to follow up on the debt issuance. With that $1 billion private books offering, your net debt to capital ratio would be up quite a bit, right? So just I just want to know what are some of the major covenants should we be aware of besides maintaining $100 million on the revolver?

This was a high yield secured note issuance so from a covenant perspective there are simply different types of incurrence tests that we need to do or need to abide by in the event that we're going to do anything in terms of moving assets out from under the security. So other than that, there's really no incremental covenants. I think the existing covenants that we have dealing with our ABL have stayed in place. We did receive an amendment under our ABL to increase the total secure debt capacity to 20% of total assets. But from a covenant perspective, there are no real financial covenants with the high yield notes.

Okay. Switching a little bit back to the CapEx, Your CapEx guidance for 2020 is down another $110 million versus your original expectation. Could you elaborate a little bit on the drivers for that? And also, have your views changed on your turnarounds or CapEx needed for Martinez since completing the deal? Thank you.

The actual driver on the additional CapEx reduction is predominantly turnarounds, but the turnarounds were that we are pushing out from 2020 into 2021. A crude unit turnaround that was scheduled for Delaware and a turnaround that pre-spent and some turnaround work that was being done in time. So they have been pushed out. Everything else we're going to now move to rebalance, if you will, by looking at 2021 and what we can push out from 2021 into 2022, try to smooth out the curve. That's the way we handle our turnarounds. and I'm sorry, I couldn't get the second part of your question on Martinez.

Have your views on the turnarounds needed like for the asset for Martinez changed since completing the acquisition? No, not at all. Not at all. Thank you.

We will go next to Teresa Chen with Barclays.

Good morning. I wanted to follow up on the demand question just in relation to California and your outlook there. In light of recent comments made by government officials relating to L.A. possibly being under perpetual lockdown until there's a cure and if you think San Francisco would follow suit and how do you think about the evolution of things on the West Coast?

I can tell you the facts are that we are seeing have seen California gasoline demand increase rather nicely. It may be plateauing, we're not sure. We took it down, as I said, if you look at the stats, it was down 48% at the trough and now has recovered to 25%, so it's at 75% of last year's level. As to how quickly it goes from there, We actually expect to see, it's tough to follow California because it depends on which politician you listen to. You know, the governor is saying that he's willing to open up some things, but then the local jurisdictions have it. In L.A., I guess you have the county health supervisor who has come out and said, I think she was the one who said L.A. County is going to be closed for three months, and in May it came out and said, no, that's not the case. So we're always at the risk that the politicians are going to do some things, and that will be what it will be. But our view is that, frankly, California is going to be continuing to recover just as the rest of the country is as the states open up. Got it.

And then on the differential side, clearly it's been a pretty wild ride over the past couple months. Both domestically and globally, I mean, in part, you know, due to bids for storage and key hubs and on the water and now with production shutting in, Tom, how do you see all of this playing out in the next couple of quarters and in 2021? In your mind, is there any sort of logical path forward? I mean, what do you think has to happen for us to, I guess, get back to some sort of, you know, normalized environment where differentials are, again, anchored by transportation economics and quality?

That's a great question. I will start by saying I think the volatility in the marketplace has been obvious to everybody. We're reacting to things that we've never had to react to before. All of a sudden, you wind up with a negative TI price of minus $32 or whatever it was. And a lot of that was storage related. A lot of it might have been the length and the derivatives on this thing. but our belief is that as we start to see the pickup in demand and as the state starts opening up, the market is in the process of rebalancing. And if you just, a couple days doesn't a trend make, but if you take a look at the spread between ICE and David Brent, that had blown out five or six bucks. Mars is still distorted versus LLS and is actually selling over Brent. A lot of that is storage. A lot of that is where you can put your crude. But we believe that the market is in the process of rebalancing on a crude side and ultimately we'll get back to the differentials. Why do I say that? It's really the story about the product side. It is demand. And as demand improves, obviously utilization will go up. And then ultimately you'll wind up bringing some of the crude that is being cut back into the system, and that incremental crude will be likely the sour mediums that are being backed out of the marketplace by OPEC Plus. I say this on occasion. I think one of the things we should really learn from what we've seen here is, and I'm not sure we will, crude has no value unless it can find its way inside a refinery. The only way crude has value is if you get it to a refinery and the refinery takes it and turns it into products that the nation and the world needs. So we remain confident that with our complex kit that ultimately we'll return to some type of a normal, more normal, I can't say normal, but more normal situation and be rewarded. How long it'll take? I suspect certainly we're not going to get there until after the second quarter as demand is in the process of recovering and it may take a little bit long in that but the trends do seem to be moving in the right direction.

Thank you. We'll go next to Doug Legate with Bank of America.

Thanks. Excuse me. Good morning everybody. Eric, I wonder if I could take you back to the liquidity question just for a second. Obviously you've taken a lot of steps here to to bolster your cash position as you walk through with Roger. I'm just curious how you see the levers that you can pull if we ended up with an extended period of weakness in terms of demand. What do you expect your cash, what are you planning for by way of a cash burn? What would your priorities be for use of free cash if and when we get back there? I believe where you were going on the front end of your question, Doug, was if we have a sustained demand issue, and I would say from a cash burn perspective, then

were probably no different than other refining companies that we would need to evaluate, do we need to idle any assets? From our perspective, there is zero point in operating to lose money. So when we think about what it costs to actually maintain our system, from May through the end of the year, we'll probably have an incremental $120 to $130 million of CapEx that we need to incur. That's essentially, call it roughly $15 million per month. That does not include turnarounds, right? So a portion of what we've done in terms of reducing our CapEx burn is ultimately push out turnaround. So that's one of the biggest levers that you have overall from a CapEx reduction standpoint. So reduce CapEx, then ultimately do you idle any plants, right? I think on average our refineries cost roughly $25 million per month to operate in terms of operating expenses. In a shutdown scenario, you're probably spending $5 to $10 million a month per plant. Clearly, some of the assets out on the West Coast are a bit more expensive to operate versus some of our legacy assets, but on average, those are general numbers. And quite frankly, then I think you also evaluate what you do with inventory. We do carry 30 to 35 million barrels of inventory at any point in time if you have an idle asset. Does it make sense to do something with that inventory? We do have an intermediation agreement with Jay Aaron. We think there are levers associated with that inventory if we're thinking about a true draconian scenario. I think we're probably going the other direction at this point though and we are starting to see demand not so much rebound but we are starting to see green shoots here. We're seeing more cars on the road. We're seeing more barrels run across all of our various racks. so ultimately I think we are we're not planning to get back to where things were prior to the pandemic but I do believe at this point we are starting to see green shoots related to a recovery and as states start to reopen I think we go the other the other direction I know it's a tricky one to navigate the scenarios but you bottom line you think you've done enough with the steps you've taken at this point to navigate through this We do, absolutely. You hit the nail on the head. What we just did is absolutely a necessary step. It was extremely prudent for us. The incremental $90-plus million of interest expense a year is not something that we take lightly. I think we've talked about we run our business for cash, as we expect everyone else in our industry to do. and quite frankly, our goal at this point is to generate enough free cash flow so that at the end of the two-year no-call period, these notes go away and we can really get back to business as usual. But I think our view was we have different levers that we ultimately pulled back during the month of March for asset sales and clearly reducing our cost structure. I think Tom mentioned on the front end, there are a variety of things that we believe longer term our business will be more optimized as a result of these cost reductions. Some of them are going to be temporary, but quite frankly, some of those will be permanent as we go forward. And so I think our view right now is this gives us a clear runway to optimize the business the way that we feel we need to do. And on a go-forward basis, we have $2 billion worth of liquidity today, and that's something that is extremely important to us.

I appreciate the lengthy answer. The demand question has been flogged to death already, but Tom, forgive me, I'm going to flog it a little bit more because you pointed to gasoline, and Eric just obviously talked about that as well, but I'm curious what you're seeing on the distillate side. And let me preface my question like this. As we look at all the demand data that we can get our hands on, it seems to us that things like mass transit, for example, is flatlining, whereas gasoline seems to be recovering. So we're trying to figure out if we're seeing a behavioural change here, not just here in the US, but globally. but more importantly, on the freight side, it seems that some of the third-party consultants that we use actually think things are holding up there a little bit better as well. So I wonder if you could sort of segregate down or, you know, get into a little bit more detail in terms of how you see the different demand trends between the different products. So I know it's a bit tricky, but any color you could offer would be appreciated.

Well, certainly, and we... You start where the immediate and most draconian impact was, obviously, and that would be jet fuel. And when you take a look at jet itself, demand is down 85% or something like that in that area. Actually, production is down the same. We don't expect jet demand to come roaring back anytime soon. There obviously is going to be most likely reticence on the part of some people to get on a plane and take a vacation to Europe and do those things. But the thing with jet is we have basically done a terrific job in PBF. We have actually reduced our jet production. What we were expecting to make was 90,000 barrels a day. We're down to about eight. And we've basically only made jet and two refineries in small amounts. And we've gotten within the supply-demand curve on jet, even with that low-demand environment. So we don't think we're gonna have an inventory issue. Now move to gasoline. and of course that was the one that everybody worked on first because JET we got under control, then we went to gasoline and then we talked about the gasoline and the same story exists there because of the cuts and runs ourselves and the whole industry and turning knobs from gasoline to distillate. We're within the supply-demand curves. Demand creeped up last week to 7.5 million barrels a day per the stats. Gasoline production was 7.5 million barrels a day. and is continuing to come up. And I'm going to come back to, I think, one of your questions, part of your question on gasoline in a moment. Now, distillate is holding up. I mean, it's, but we obviously increased production of distillate by taking gasoline and jet fuel and putting it into distillate. We're actually starting to reverse that step some. We're cracking some distillate, which is a step in a cat-crack is to turn it into gasoline, not increasing runs, we're just shifting Thank you very much. Your question in terms of behavioral shifts, yeah, I think we believe that there's likely going to be some tailwinds, particularly on gasoline, because people are going to be not willing to get on subways. They're not going to get on a cruise ship and go on vacations. They're not going to get on an airplane. They may not even Uber. There's going to be a lot of people who are going to decide that I'm not going to take the bus. The safest form of transportation I have is to drive my own automobile. In fact, I'd probably want to drive it with only me in the car unless it's a family member. So I think some of the analysts have written that perhaps we could have a little bit of an upside or some significant upside from gasoline. And I think there's the potential for that to occur.

We will go next to Brad Heffern with RBC Capital Markets.

Hey, good morning, everyone. I wanted to go back to an earlier answer about CapEx. So you talked about deferring some of the turnaround expenditures into 2021 or 2022. I think in the past you talked about sort of an annual average CapEx for the system of like 650 to 700 million. Post recovery, should we expect the number to be significantly larger than that? Or would ultimately sort of the whole turnaround picture get pushed out? and it sort of stays level. And then sort of within that question, can you also talk about how long you think you can spend at these levels before you end up having some sort of impact on reliability?

Good question. The short answer to the first part of the question is we are already starting to work the issue on our 2021 CapEx. and the expectation is that we will continue to have a capex spend rate in that $650 to $700 million range. We'll do that to a large extent. We have optionality on bumping out the turnarounds. We don't like to do too many turnarounds in any given year. They're lumpy in the base case, but we certainly would like to have it be smoothed out for obvious reasons, the amount of throughput that you lose. So the expectation is that we're not going to have an increase on 2021 or beyond this. We'll just manage that. We certainly can handle, we've already made the commitment that we're looking at a $15 million capex spend and that's basically we said we cut total capex by 360 but the fact is that we spent a lot of that money already in Toledo because that was the biggest thing. We spent over $130 million on a Toledo turnaround. So we are going to sustain the $15 million range until the end of the year for sure unless we see something really significant in a faster recovery and then maybe we might add some things back but even then I'm somewhat suspicious. At some point, your question is correct. And it will be most likely in the turnaround area. I mentioned earlier that in Toledo, the unit was talking to us and finally said, it's time to shut down. Well, if we continue to defer all the turnarounds or a high percentage of turnarounds, we ultimately could get into a situation where we'll have to take a unit down because it's the end of run. And we won't run in an unsafe condition. But Again, I don't think we're anywhere there right now, and the rest of the year we're going to stay at these levels, and then we expect to go right back to that range that you talked about.

Okay, thank you for that. And then just a question on Contango. I know it can be complicated with the waterborne barrels about whether it's possible to capture Contango profitability, so can you walk through how it looks in the system? I would assume you get some of it at Toledo, but any more color than that? Thanks.

probably Toledo is probably the only area but you know the system is so volatile if you take a look at what's happened in the last couple of days we don't have anywhere near the contango that we had before so I wouldn't think that that is going to have a huge effect or take steps that we're going to try to focus that as being an area we tend to just take the market as it comes

We will go next to Phil Gresh with JP Morgan.

Hi, yes, good morning. A couple of questions for Eric. First, just on the new run rate interest expense, what would that look like after all these decisions you've made? And then with the hydrogen plant sale, what would be the last EBITDA there? And then finally, With the CARES Act and your tax situation, is there any type of benefit you'd expect to see?

So, Phil, we'll take those in reverse order. At this point, we're still combing through various components of the CARES Act, but we do not anticipate having anything material coming at us from a tax standpoint as a result of the CARES Act. Our tax team has been pretty efficient to date, so we don't have anything that we believe we will be able to carry back against. In terms of the hydrogen plant, so we did receive $530 million of gross proceeds. Incremental EBITDA basically will be about $65 to $70 million that will ultimately hit EBITDA. That will obviously be split between the West Coast and the East Coast. Easy way to think about that is it's probably, call it 80%, is going to hit the West Coast simply because that's where the bulk of the assets are. and those will be costs, incremental costs every year that ultimately will be above the line so they will reduce EBITDA on a go-forward basis. And then from an interest expense standpoint, I think our current general run rate for interest expense on a consolidated basis, so this includes roughly $55 million of interest expense at PBF Logistics is probably going to be in the $275 to $300 million range. That includes everything. That is the new billion-dollar notes issuance that we did back in January. We clearly redeemed a portion, or I'm sorry, all of the 7% notes that were outstanding and then we did just do this incremental bill and so it includes the incremental interest expense from those two new issuances and then has reduced the interest expense that we no longer will have to cover for the redeemed notes. Okay, great. Thanks.

And then second question would just be for Tom. I know there's already a question on different rentals but maybe more specifically just on Light Heavy Differentials, you know, Pemex did tighten the K factor again last night. So I guess it's a little bit more about how do you see things playing out in kind of near term with the OPEC cuts just starting to kick in versus more intermediate term. You know, you were talking a little bit about timing of OPEC barrels coming back, but just a little bit further elaboration on that. Thanks.

Certainly we've seen with Maya, Maya has moved in significantly. It's no longer competitive. The sortie barrels was their focus on the Asia and even the European markets. They appear to be less interested in trying to protect markets here in the U.S. right now. And then, of course, you've got the situation with China. WCS in Canada which is that's a tough business for those folks right now given the lack of demand. So we've seen these differentials narrow in significantly in some cases and being completely distorted and as I said earlier I think that's a function of not fundamentals and ultimately we'll clear that and get back to fundamentals but until the demand picks up you're probably going to have tighter dips Light Heavy Diffs. And we'll react to that. We're going to actually have the capability of running Light Oven Sweet or Crude if we want to. And if it's more economic, then we will do that. And that situation will remain until demand picks up. And then when demand picks up, I don't think you're going to see a rapid increase in domestic production. In fact, there's going to be some consequences on that some period of time. The incremental barrel that will be needed to supply incremental demand is going to be the medium heavy barrel and that will directionally widen those different rentals.

Interesting. Okay. Thank you.

We will go next to Paul Cheng with Scotiabank.

Hey, guys. Good morning. Good morning. A number of questions, so hopefully that answers each one. Tom, just curious that at some point the pandemic is going to be behind us. So at that point, is this experience, whether it's from how you run your operation, how you're looking at your balance sheet, and how you're looking at projects in terms of the Ascension project or M&A, how that may have changed the way that how you're going to run your business, if that's any?

That's a great question, Paul. First of all, I would say, yeah. Out of necessity is the mother of invention. We've had to take very interesting steps and aggressive steps in all the areas that we've already talked about. But one of the things that we're looking at is, hey, we've actually been able to decrease our runs and get our throughput down lower than we ever would have imagined. And I'll just point out that, for example, The people in Martinez and people in Chalmette have reduced the safe operating minimums on the catcrackers in those facilities. So if we get into a situation where the pandemic is gone and margins are good or demand is good, fine. But if we get into a situation where we have some dislocations, there's some other tools that we've now got at our disposal. We've actually turned the second stage hydrocrackers at Martinez and Torrance and shut them down and basically turned those into distillate machines instead of gasoline machines. There's a number of other steps that we think we're going to be able to continue to capitalize on to improve our overall efficiency. As we look as to the M&A side and project side, I think we were very clear that we felt like Martina's acquisition was an important acquisition for us to balance and have a second operation in Pad 5. But having done that acquisition, our focus now is, and now more than ever, since we've had to layer up some debt here, is to focus on de-levering

I think that's absolutely the case. Near term, it is, as I mentioned before, running this business for cash. We are firm believers that there is no point in continuing to operate a business that ultimately is going to lose money at the gross margin level. And I believe we have seen this not only as a result of what we just went through with the first the beginning phases of this pandemic but we also we saw similar activity from the refining sector in the first quarter of 2019 where ultimately when when margins reach a point that become untenable ultimately there will be responses in the market and so I think from our standpoint as we go forward it will clearly be how do we ultimately where there are some things we can do mechanically that ultimately help us match the demand side of things if gasoline is more attractive from a profitability standpoint for us versus distillate. So there's a combination of operational or mechanical changes but also just a sheer volume of we are managing this business to ultimately de-lever and again we talked a little bit about optimization but now is the time for us to really take advantage of having six refineries, getting some economies of scale here There are a lot of things that we believe we can do with this business on a go-forward basis.

And, Paul, I just add something to what Eric just said. If you look at the 2019 situation, what really happened there is, well, we had very good distillate margins in the fourth quarter of 2018, and the industry does what it oftentimes does, started cranking up to try to capture those margins and watch gasoline prices build enormously through the fourth quarter. And I've said before, if you are running your business and you're banking on the fact that you're going to get what's going to occur three months out, but you're running and you're not selling your product, you're not getting cash for your product, and you are building an inventory, sooner or later that is going to cost you big time. So we're going to be very cognizant of, and even now watching it as we look at this right now, we're watching it very carefully, To reinforce what Eric said, it makes no sense to me to run and just build inventory or run and not make money. So I think one of the key learnings, and I hope the whole industry gets it, is that the only way you can really make money is you sell your products at a reasonable price, and if it's not there, throttle back.

I hope that everyone is going to take the same attitude. Tom, is that... I know that I mean that we have some flexibility to push from gasoline into distillate, distillate get back to gasoline. And we also have reasonable flexibility between jet fuel to diesel. The problem is that if everything is done, is there really any flexibility that we can push those light products outside those light products into other products? because I mean, yeah, I mean, now we have a concern, so you're trying to push it back to gasoline, but if that's the case, gasoline may become a problem. So is there any other option or the only option is that we need to maintain the overall run to be low?

Very good question. We're giving this a lot of thought. There are some additional flexibilities that we think we've got that we've discovered, and again, it's around hydrocrackers because we can actually Say jet fuel takes a year to recover. Well, you can only put so much jet fuel into gasoline or into distillate before you run into quality limits, whether it be sulfur or flash, as you know. But we actually think we could use the hydrocrackers if we wanted to. to turn jet fuel into gasoline. So there's some flexibility there, but sooner or later, because of the limits, and I'll go back to the issue, and it ultimately could be a constraint on the industry increase in runs, is if demand doesn't increase, and particularly if it doesn't, let's take jet, for example. Right in balance on jet production and jet demand, and the tanks are pretty full, So if indeed we've exhausted the ability to take jet fuel and turn it into distillate because we run into a quality limit and then distillate remains long and distillate is building, I think you're going to have a constraint on how quickly you can increase your runs and it will impact utilization.

Thank you. Eric, can I have a couple quick questions on the finance side? For McKinsey, We find that you have two runs of the run. February margin is at least at the first three weeks was good and then was quite horrible in March. So is that new refinery make money at all in the first quarter? So that's the first question. Second, when you talk about the hydrogen, the EBITDA impact 65 to 70 million, is that showing up when you report it? Is that going to show up in the gross margin or is it going to show up in the OPEX? And then finally, the $140 million of the target savings, have you achieved any of them in the first quarter? And how's the runway is going to progress throughout the year?

Let's take those in reverse order, Paul. The $140 million of savings is probably going to be recognized more second, third, and fourth quarter. Again, these were all announced during the first quarter. So we were starting to take steps associated with those reductions, but ultimately we'll start to see the benefits as we go. And it's probably a bit more geared towards you're going to start to see it in the second quarter. And for now, let's assume that it's going to be generally rateable. However, it's probably a bit more back and weighted for the year. In terms of the gross margin versus operating expense, where will the hydrogen plant costs be captured? At this point, we're still working through some accounting issues here, but we do know that it will ultimately be included in EBITDA, so it will be above the line, and we'll provide some more color as we have a full quarter of that for the next quarter or second quarter earnings call. And from a Martinez standpoint, look, I think we've never given specific guidance or detail around what each refinery is doing on a daily basis but ultimately Martinez when the market was better in California absolutely has made money but clearly what we've seen is that the market has been a bit volatile out there so I think directionally you should assume though that the consolidated West Coast numbers ultimately you will see the benefit of Martinez hitting that P&L.

We will go next to Matthew Blair with Tudor Pickering and Holt. Please go ahead.

Hey, good morning, everyone. Glad to hear you are all safe and sound here. Tom, you touched briefly on OPEC. There's reports of quite a few Saudi cargoes headed to the U.S., and at least on paper, it looks like delivered diffs for May were extremely favorable. So we're wondering, is PBF part of this, or are you looking to ramp Saudi barrels in the second quarter? And if so, could you give us any idea on the numbers here?

Well, let me say that we're not going to give you specific numbers, but just the way this has played out has been somewhat strange. There was obviously a decision made by the Saudis back several months ago. to get into a price war with Russia and maybe go after shale. I don't know. You'll have to ask them exactly what their motors were. And for a period of time indicating that the K-factors effectively would be attractive, and they were going to put a whole bunch of crude on the water, and they did put some crude on the water. We were running some. We obviously have a contract with them, and we run it in Paulsboro with the Lubez crude, So we had some benefits there. But that went away as fast as it came. And then all of a sudden, they decided they had to do something, they being OPEC Plus, because of the pandemic. And in fact, as I said earlier, as we look at the situation right now, the sortie barrels are not very attractively priced as you work through that one wave that had, which was almost a one-month phenomenon almost. So We're going to have to wait and see how the demand side is going to have to lead out of this. And that's all I can really say on that.

Okay, sounds good. And then, Tom, you also mentioned that distillate exports to Latin America were starting to be impacted. We can start to see that in the DOE data here. I was hoping you could just contrast just overall export demand versus domestic U.S. demand and which at the current moment is holding up a little bit better.

Well, I think the U.S. demand is actually holding up, certainly versus, say, the export market into South America. And we are seeing that. But the fact is, we actually, both on gasoline, we were a net importer on gasoline in the last stats. That's because we weren't clearing barrels and coming out of Pad 3 or even other areas. and we were less than a million barrels. I think it was significantly less than a million barrels of exports on distillate. And that is directly attributable to demand disruptions and distillate being impacted pretty significantly as the wave, the pandemic wave, apparently is now moving south and they're becoming more impacted by it than what the U.S. has, even though the U.S. has been tremendously impacted by it. and as you see, Europe showing some green shoots, if you will, and opening up. We're seeing some recovery there. You're seeing that at least stabilized in the U.S., but we're definitely seeing much lower demand for the export power in South America.

Great. Thanks for the insights.

We will go next to Jason Gableman with Cohen.

Hey, morning. I just wanted to ask about the margin outlook and your comments on not reacting the way refineries typically react to margin improvements. So in terms of PBF, what are you guys watching to give you the signal to ramp up rates? And do you expect The rest of the industry to be watching too in a manner that they don't respond to higher margins in the same way that they have historically and this kind of gets at the point that out of Periods of economic weakness, you've seen refining margins kind of stay subdued because you've had slack in the global, you've had slack global capacity. And so refiners have ramped up at the first sign of margin improvements. And that's kind of keep margins depressed. So do you see that playing out differently this time around?

I sure hope so. We're going to do that, I will assure you. Incremental economics is the bane of existence of the refining industry. You chase an incremental barrel because you think you're doing it on variable costs and you've already covered your fixed costs. And you wind up, as I said earlier, storing the barrel in a tank and that just predicates lower margins because what do you look at? Well, you look at demand, you look at inventories. So if you're building inventories, Somebody better ask a really good question as to what are we headed for. And so we are going to do that. That's just our base mantra. That doesn't mean that when margins improve, if we think they're stable and systemic, we are going to go ahead and improve, increase throughput, but we don't want to do it by then creating something that kills the golden goose, if you will, running to make gasoline to kill and then killing or vice versa. One of the first things that I think everybody has to look at, and I think it's on everybody's mind right now, is okay, we're starting to open up states in this country. We're not out of the pandemic yet. So we certainly hope we don't see a second wave. And if we can open up this country, even if it takes a little while, but don't see a repeat. I don't know who's right in forecasting these things, and certainly we can't do it, but we obviously hope and want to see that we're not going to have a lingering problem with the virus. As to the question of do we think the rest of the industry will follow, I can only speak, or I would only speak for the independents, and this is an important point. If you take a look at just, we're the fourth largest independent refiner, and if you take a look at MPC, Valero, P66, and PBF, there's over eight million barrels a day of capacity. And then when you throw Dellex, CVI, Holley in there, others, we are by far a majority of the crude capacity, throughput capacity in the country, and our competitors in their calls have recognized and acknowledged that they are not going to swallow the bait. They're going to be very tempered, and making sure that any recovery in demand is sustainable before they increase run. So I'm perhaps a little bit more confident than I typically am that the industry will respond in a correct manner.

Thanks. I appreciate that insight. And just maybe for on the comments around liquidity improving if prices stay here. Can you give us an indication of the magnitude of that liquidity improvement or maybe the working capital benefit you could see in 2Q if prices remain stable?

The easy math is under ABL availability. Just the quick math is take roughly 30 million barrels times whatever average crude and product price is. So ultimately just For example, we had the $150 million that we pointed to in the press release and on the call today assumed roughly $25 per barrel average price for crude and products, and we get 80% advance rate against that. So ultimately, every dollar move ultimately will result in a pretty significant swing upward in terms of availability, which obviously increases our liquidity.

Super. Thanks.

We will go next to Neil Meadow with Goldman Sachs.

Hey, guys. I recognize we're over time here, so I'll be quick. But the first question is just on the U.S. production profile, oil production profile. Tom, you made some comments that you think that what we're seeing now could have structural impacts in terms of the shape of U.S. supply. So can you talk about your volume outlook and also your thoughts on that? Flat price levels at which shut-in production could return.

Well, I'm not an expert on the production side, but from everything we've read, it depends. Of course, the sorties are the easiest ones to resume. The Canadians may have a more difficult problem resuming. West Coast, some of that could be, if it gets shut-in, could be more difficult. from what we've read and believe is if demand recovers and prices get up into the $40 to $45 level, then there will be some economic incentive, if it's sustained, to increase production, whether it be domestic or foreign or Canadian. That being said, I think this is structural, Neal. I think if anybody hasn't realized, all the things I say about the refining business and chasing the incremental barrel is gonna apply to the production business. And if anybody didn't understand that, if there's 100 million barrels of crude demand, if we get back to that level, if it's less than that, it's gotta be carved up in a way, and that's what they're trying to do with OPEC+. and I don't see a way that the Saudis, they've already told everybody and so the Russians are going to let the United States try to go ahead and capture market share. They're going to defend their position. So they may be content to let the U.S. producers produce 10, 11 million barrels of shale but not 13 and no efforts to go up because they're going to defend that and we'll be back into some type of price wars. As it impacts us, The domestic production, most of that is going to be obviously shale that cuts back. We don't participate in the shale very much at all. There's plenty of crude that we can get our hands on, and of course we run more mediums and heavies if they're economic, and there's quite a few crudes that we still can get that are good crudes for us to run. So we're not going to have a problem, but I do think it is a structural change that's going to be, it's no longer just build up pipelines and new offshore water ports so you can export and get up to 15, 16 million barrels a day of U.S. production being exported around the world or produced and being exported around the world. I don't see that happening.

Okay. Thanks, Tom. And a related question is on the refining side, utilization is 67% in the U.S. right now. How hard is it going to be to ramp supply back online for the U.S. system or is it relatively easy and a corollary to that is if we do get into a situation where refiners will have to idle assets, do you think that will result in capacity potentially structurally being taken offline or is there precedent for us to bring idled assets back to full capacity?

There's certainly precedence to bring idled assets back. This industry has demonstrated that Idle refineries have been characterized as zombies. They always come back from the dead. I don't think you're going to see that right now because, again, this is going to result in a structural change. The other part of your question, if you've just throttled back, it's kind of sequential. If you've throttled back all your units to safe operating minimums, but they're all running, then it's going to be relatively easy to bring them back up. You know, you can do it pretty quickly. If in a case like we have done, we've got a hybrid, we've cut everything to safe operating minimums, and then we said we're going to shut down two FCCs in the system, catcrackers. So we shut the Toledo one, we started up after the turnaround, and we shut the catcracker in Paulsboro. They're being kept warm. They can come back up, but it'll take a little longer, but not materially longer. to get them back up. In the case where you idle a refinery, even though you're keeping it warm or trying to, that is a little bit more problematic. It'll take more time to bring those refineries back. So we'll see. Now the other question is, I can make a case that there may have to be some rationalization in this business. And the United States has the strongest kit, by and large, in the world, with the exception of the sortie Middle East and Asian refineries, Reliance, etc. So we should be competitively advantaged, but there are even some refineries in North America that are going to be under pressure if indeed we don't have demand come back to the levels that we had before.

Thank you so much, Tom.

All right.

There are no further questions, so I'll turn it back to Tom Nimley for any closing remarks.

Well, thank you very much, everybody. I hope you stay safe, healthy, and take care of your families. And we'll look forward to a more optimistic call next quarter.

This does conclude today's program. We appreciate your participation, and you may now disconnect.