PBF Energy (PBF) Q1 2020 Earnings Call Transcript

PBF Energy (PBF 0.49%)
Q1 2020 Earnings Call
May 15, 2020, 8:30 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Good day, everyone, and welcome to the PBF Energy first-quarter 2020 earnings conference call and webcast. [Operator instructions] It is now my pleasure to turn the floor to Colin Murray of investor relations. Sir, you may begin.

Colin Murray -- Investor Relations Manager

Thank you, Bree. Good morning, and welcome to today's call. With me today are Tom Nimbley, our CEO; Matt Lucey, our president; Erik 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 described 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, noncash, lower-of-cost-or-market or LCM and adjustments, change in tax receivable agreement liability and debt extension 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 will 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 1, 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.

Tom Nimbley -- Chief Executive Officer

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 are all experiencing 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 corporate overhead expenses by over $20 million, primarily through temporary salary reductions for more than 50% of our corporate and non-represented 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 through 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 650,000 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 Erik to discuss our current liquidity and financial position.

Erik Young -- Chief Financial Officer

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 $6 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 1 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.

Questions & Answers:

Operator

Certainly. [Operator instructions] And we will go first to Roger Read with Wells Fargo.

Roger Read -- Wells Fargo Securities -- Analyst

Hey, certainly, good morning. Hopefully -- can everybody hear me?

Tom Nimbley -- Chief Executive Officer

Yes, Roger. We can hear you.

Roger Read -- Wells Fargo Securities -- Analyst

OK. Good. I think all of us with this work-from-home thing never really know. Just a quick follow-up there, Erik, 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 $1 billion and have less than $1 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 accounts receivable, accounts payable or most of the working capital is trapped at this point.

Erik Young -- Chief Financial Officer

Roger, the cash balance of $805 million was the balance pre-transaction as of May 1, so then you take the, call it, roughly $1 billion. 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 million-plus, call it, the incremental $1 billion of cash from the bond deal plus the availability under our ABL.

Roger Read -- Wells Fargo Securities -- Analyst

OK. All right. That's helpful. And then on the working capital side, the moving parts there.

Erik Young -- Chief Financial Officer

Yes. 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 to six weeks there.

So in a declining flat price environment, we will ultimately see, right, what we're paying during, for example, the month of April, that we paid for barrels, half of the barrels that we basically price 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. Then as prices start to rebound, it flips and goes the other way. So that's where we believe the working capital side of things because we are in a net payables position, right? We probably carry 10 days' worth of receivables and anywhere from 20 to 30 days' worth of hydrocarbon-related payables.

So in an increasingly flat price environment, everything flips back the other way, we will start to see cash come back into the system.

Roger Read -- Wells Fargo Securities -- Analyst

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 31 versus where they might be on June 30 when we're trying to compute the effect?

Erik Young -- Chief Financial Officer

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 prices, 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.

Roger Read -- Wells Fargo Securities -- Analyst

OK. Great. Thanks. And then, Tom, if I could go back to you.

You mentioned maybe some signs of demand starting to creep back into the market. And it looks like some other indicators, which 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. So I was just curious if there's anything you kind of incrementally help us with there.

Tom Nimbley -- Chief Executive Officer

Yes. 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%, PADD 5 was down 48%, PADD 3 was down 43%, PADD 2 was down 47%, and PADD 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 PADDs 24% from last year's level, up from 5.1 million to 7.5 million barrels a day in the last reported EIAs.

And the improvements have been actually more pronounced in PADD 5. We're now down only 25%. There's a lot more traffic apparently on four or five in California. PADD 3 has moved from 43% in last year to 27%; PADD 2, 47% to 33%.

And PADD 1 is the lag, and 45% and is now down -- has 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.

Roger Read -- Wells Fargo Securities -- Analyst

OK. Great. Thank you.

Operator

We will go next to Manav Gupta with Credit Suisse.

Manav Gupta -- Credit Suisse -- Analyst

Hey, guys. My first question is on Toledo. The gross margin captured 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 Mid-Con? And the broader question is we understand that Mid-Con 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?

Tom Nimbley -- Chief Executive Officer

OK. 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 units 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. And 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 cat cracker that makes gasoline. So that unit has been down.

So 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 have are not quite as strong as you're saying. Hopefully, you will 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 cracks 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 GD knob and turned 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.

Manav Gupta -- Credit Suisse -- Analyst

Yes. Thanks for that, Tom. A quick follow-up. Now you have had Martinez 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 Martinez an asset in a condition in which you expected it to be delivered? Thank you.

Tom Nimbley -- Chief Executive Officer

Actually, so far, we obviously took it over February 1. And absent the impact from the margin side from the pandemic, I will tell you, it is a first-class asset with a first-class workforce. It is not a 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 have really good oil boilers.

Manav Gupta -- Credit Suisse -- Analyst

Thank you so much for taking my questions.

Operator

We will go next to Prashant Rao with Citi.

Unknown speaker

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

Erik Young -- Chief Financial Officer

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 secured debt capacity to 20% of total assets. But from a covenant perspective, there are no real financial covenants with the high-yield notes.

Unknown speaker

OK. Switching gear 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, like have your views changed on your turnarounds or capex needed for Martinez like since completing the deal? Thank you.

Tom Nimbley -- Chief Executive Officer

Yes, the actual driver on the additional capex reduction is predominantly turnarounds, but the turnarounds that we are pushing out from 2020 into 2021 are accrued unit turnaround that was scheduled for Delaware and a turnaround that pre-spend 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.

Unknown speaker

Have your views on the turnaround or capex needed like for the asset -- for Martinez changed since completing the acquisition first year?

Tom Nimbley -- Chief Executive Officer

No, not at all.

Unknown speaker

Not at all. Thank you.

Operator

We will go next to Theresa Chen with Barclays.

Theresa Chen -- Barclays -- Analyst

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?

Tom Nimbley -- Chief Executive Officer

Well, 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. 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 with the county health supervisor, who has come out and said -- I think she was the one who said it's kind of – L.A.

County is going to be closed for three months and, in May, 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.

Theresa Chen -- Barclays -- Analyst

Got it. And then on the differential side, clearly, it's been a pretty wild ride over the past couple of months, both domestically and globally, I mean, in part bids for stores 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 normalized environment where differentials are again anchored by transportation economics and quality?

Tom Nimbley -- Chief Executive Officer

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 in the derivatives saw in 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 a couple of days doesn't a trend make, but if you take a look at the spread between ICE and daily Brent that's blown out $5 to $6, Mars – it's 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 the 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 solid mediums that are being backed out in the marketplace by OPEC, OPEC+. 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 into 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, more normal situation and be rewarded. How long it will take? Certainly, we're not going to get there until after the second quarter as demand is going to -- is in the process of recovering, and it may take a little bit long than that.

But the trends do seem to be moving in the right direction.

Theresa Chen -- Barclays -- Analyst

Thank you.

Operator

We'll go next to Doug Leggate with Bank of America.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Thanks. Excuse me. Good morning, everybody. Erik, 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 bolster your cash position as you walked 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'm just trying to get a feel for it because obviously, the cost of the debt is pretty onerous. I'm just wondering if there's flexibility over the next several years to try and reset that lower at some point.

Just walk us through how you're thinking about that, please?

Erik Young -- Chief Financial Officer

So 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 we're 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 million 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 million 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 million 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 J. Aron. 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'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'd go the other direction.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

I know it's a tricky one to navigate the scenarios. But bottom line, you think you've done enough with the steps you've taken at this point to navigate through this?

Erik Young -- Chief Financial Officer

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.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

I appreciate the lengthy answer. Look, 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 Erik 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 behavioral change here, not just here in the U.S. 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 get into a little bit more detail in terms of how you see the different demand trends between the different products late. So I know it's a bit tricky, but any color you could offer would be appreciated.

Tom Nimbley -- Chief Executive Officer

Doug, certainly. And we start with 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 or in that area. Actually, production is down the same.

So 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 and just 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 8,000. And we basically only made jet in two refineries in small amount. And we've gotten within the supply demand curve on jet even with that low-demand environment, so we don't think we're going to 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've talked about gasoline. And same story exists there because of the cuts in runs ourselves and the whole industry and turning knobs from gasoline to distillate, we're in within the supply demand curves. The demand crept 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. 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 that in a cat crack is to turn it into gasoline, not increasing runs. We're just shifting product from distillate to gasoline because we're a little concerned on the distillate side that we saw. And that is mainly being driven by the fact that the pandemic is now hitting South America pretty hard and the ability to export the barrels out of the Gulf Coast of the United States into South America is being impacted.

That being said, it does appear as though distillate demand continues to hold up better. On your question in terms of behavioral shifts, yes, 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 decide or going to decide that I'm not going to take the bus. The safest form of transportation that 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.

Operator

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

Brad Heffern -- RBC Capital Markets -- Analyst

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 million 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 gets 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?

Tom Nimbley -- Chief Executive Officer

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 get -- continue to have a capex spend rate in that $650 million to $700 million range. We'll do that, but 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 the fit. We've already made the commitment. We're looking at a $15 million capex spend, and that's basically, we said we cut total capex by $360 million. But the fact is that we spend 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, where I've mentioned earlier that in Toledo, the unit was talking to us, and it's 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 there, 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.

Brad Heffern -- RBC Capital Markets -- Analyst

OK. 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.

Tom Nimbley -- Chief Executive Officer

Yes, probably Toledo is probably the only area, but 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 on what we're going to 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.

Operator

We will go next to Phil Gresh with JP Morgan.

Phil Gresh -- J.P. Morgan -- Analyst

Hi, yes, good morning. A couple of questions for Erik. 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 lost EBITDA there? And then finally, with the CARES Act and your tax situation, is there any type of benefit you'd expect to see?

Erik Young -- Chief Financial Officer

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 million 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, it's probably going to be in the $275 million to $300 million range. That includes everything. That is the new $1 billion 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 though, 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.

Phil Gresh -- J.P. Morgan -- Analyst

OK. Great. Thanks. And then second question would just be for Tom.

I know there's already a question on differentials, but maybe more specifically just on light/heavy differentials. Pemex did tighten the K factor again last night. So I guess it's a little bit more about how do you see things play out in kind of the near term with the OPEC cuts just starting to kick in versus more intermediate term. You're talking a little bit about timing of OPEC barrels coming back, but just a little bit further elaboration on that.

Thanks.

Tom Nimbley -- Chief Executive Officer

Yes. Certainly, we've seen with Maya. Maya has moved insignificantly. It's no longer competitive.

The Saudi barrels was -- they're focused on the Asia and even the European markets. They appear to be less interested in trying to protect market share in the U.S. right now. So we are seeing -- and then, of course, you've got the situation with WCS in Canada.

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 diffs, light/heavy diffs, and we'll react to that. We're going to actually have the capability of running lighter and sweeter 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 differentials.

Phil Gresh -- J.P. Morgan -- Analyst

Interesting. OK. Thank you.

Operator

We will go next to Paul Cheng with Scotiabank.

Paul Cheng -- Scotiabank -- Analyst

Hey, guys, good morning.

Tom Nimbley -- Chief Executive Officer

Good morning, Paul.

Erik Young -- Chief Financial Officer

Good morning.

Paul Cheng -- Scotiabank -- Analyst

There are number of questions. So hopefully I get that short answer in 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 your -- how you won your operation, how you're looking at your balance sheet and how you're looking at projects in terms of the extension project or M&A, how that may have changed the way that how you're going to run your business if that's ending?

Tom Nimbley -- Chief Executive Officer

That's a great question, Paul. First of all, I would say yes. 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 have actually been able to decrease our runs and get our throughput down lower than we ever would imagine. 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 cat crackers 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 had some dislocations, there are 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 turn 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 at the M&A side and project side, I think we were very clear that we felt like the Martinez acquisition was an important acquisition for us to balance and have a second operation in PADD 5. But having done that acquisition, our focus now is -- and it's now more than ever since we've had to layer up some deck here, is to focus on delevering the balance sheet.

And I'll let Erik just comment further on that.

Erik Young -- Chief Financial Officer

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 beginning phases of this pandemic, but we saw similar activity from the refining sector in the first quarter of 2019, where ultimately, 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 delever. 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.

Tom Nimbley -- Chief Executive Officer

And Paul, I'll just add something to what Erik 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. It was 2018. And the industry does what it oftentimes does, started cranking up to try to capture those margins and watch gasoline 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 in a curve 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 Erik 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.

Paul Cheng -- Scotiabank -- Analyst

Yes. And 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, yes, I mean, distillate, 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 is we need to maintain the overall run to be low?

Tom Nimbley -- Chief Executive Officer

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, some of this is 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.

If demand doesn't increase and if -- particularly if it doesn't, let's take jet, for example, we're 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.

Paul Cheng -- Scotiabank -- Analyst

Yes. Thank you. Erik, can I have a couple quick questions on the finance side. For Martinez Refinery, you had two runs of the one factory, margin is at least at the first three weeks was good and then was quite horrible in March.

So does that mean we finally 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 million to $70 million, is that showing up -- when you report, is that going to show up in the gross margin? Or it's 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 is the runway going to progress throughout the year?

Erik Young -- Chief Financial Officer

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 toward -- 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 ratable. However, it's probably a bit more back end-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 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.

Operator

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

Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst

Hey, good morning, everyone. I'm 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 delivery diffs for May were extremely favorable.

So we're wondering, is PBF part of this? Are you looking to ramp Saudi barrels in the second quarter? And if so, could you give us any idea on the numbers here?

Tom Nimbley -- Chief Executive Officer

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 motives were.

And for a period of time indicating that the K factors effectively would be attractive and they're going to put a whole bunch of crude on to water and did put some crude on to water. We were running some -- we obviously have a contract with them, and we run it in Paulsboro as a lube's 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+, because of the pandemic, and in fact, as I said earlier, as we look at the situation right now, the Saudi barrels are not very attractively priced as you work through that one wave that had, which was what I call is a one-month phenomenon almost. So we're going to have to wait and see how the demand side is going to have to leap out of this. On that side, that's all I can really say on that.

Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst

OK. 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.

Tom Nimbley -- Chief Executive Officer

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 carrying barrels coming out of PADD 3 or even other areas.

And we were less than 1 million barrels. I think it was significantly less than 1 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 stabilize in the U.S., but we're definitely seeing much lower demand for the export barrel in South America.

Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst

Great. Thanks for the insights.

Operator

We will go next to Jason Gabelman with Cowen.

Jason Gabelman -- Cowen and Company -- Analyst

Hey, good 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 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?

Tom Nimbley -- Chief Executive Officer

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 cost, and you've already covered your fixed cost, and you wind up, as I said earlier, storing a 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 asked 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 that we're going to go ahead and 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 distillate or vice versa. One of the first things that I think everybody has to look at, and I think it's on top of everybody's mind right now is, OK, 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 just 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 8 million barrels a day of capacity. And then when you throw Delek, CVI, Holly in there, others, we are, by far, a majority of the crude 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 in making sure that any recovery in demand is sustainable before they increase runs. So I'm, perhaps, a little bit more confident than I typically am that the industry will respond in a correct manner.

Jason Gabelman -- Cowen and Company -- Analyst

Thanks. I appreciate that insight. And then just maybe for Erik 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?

Erik Young -- Chief Financial Officer

The easy math is under ABL availability. Just the quick math is take roughly 30 million barrels times whatever average crude and product prices. 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 in 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.

Jason Gabelman -- Cowen and Company -- Analyst

Super thanks.

Operator

We will go next to Neil Mehta with Goldman Sachs.

Neil Mehta -- Goldman Sachs -- Analyst

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 flat price levels on which shut-in production could return?

Tom Nimbley -- Chief Executive Officer

Well, I'm not an expert on the production side, but from everything we've read, it depends, of course. The Saudis 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 and if it's sustained to increase production, whether it be domestic or foreign or Canadian. That being said, I think this is structural, Neil. I think if anybody hasn't realized -- all the things I say about the refining business and chasing the incremental barrel is going to apply to the production business. And if anybody doesn'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 got to be called up in a way.

And that's what they're trying to do with OPEC+. And I don't see a way that the Saudi's -- 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 million or 11 million barrels of shale but not 13 million 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 gets 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, 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 our pipelines and new offshore water port, so you can export and get up to 15 million, 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.

Neil Mehta -- Goldman Sachs -- Analyst

OK. 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 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?

Tom Nimbley -- Chief Executive Officer

Well, there's certainly precedents to bring idled assets back. This industry has demonstrated that. The idled refineries have been characterized as zombies. They always come back from the dead if the margins are there.

I don't think you're going to see that right now because, again, this is going to result in the structural change. The second part of your -- other parts of your question, OK, if you've just throttled back a -- it's kind of sequential. If you throttle 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 can do it pretty quickly.

If in a case like we have done, we've got a hybrid, we've got everything to safe operating minimums. And then we said, we're going to shut down two FCCs in the system, cat crackers. So we shut the Toledo one. We started up after the turnaround.

And we shut the cat cracker in Paulsboro. They're being kept warm. They can come back up. But it will 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 will 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 Saudi and 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.

Neil Mehta -- Goldman Sachs -- Analyst

OK. Thank you so much, Tom.

Tom Nimbley -- Chief Executive Officer

All right.

Operator

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

Tom Nimbley -- Chief Executive Officer

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

Operator

[Operator signoff]

Duration: 70 minutes

Call participants:

Colin Murray -- Investor Relations Manager

Tom Nimbley -- Chief Executive Officer

Erik Young -- Chief Financial Officer

Roger Read -- Wells Fargo Securities -- Analyst

Manav Gupta -- Credit Suisse -- Analyst

Unknown speaker

Theresa Chen -- Barclays -- Analyst

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Brad Heffern -- RBC Capital Markets -- Analyst

Phil Gresh -- J.P. Morgan -- Analyst

Paul Cheng -- Scotiabank -- Analyst

Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst

Jason Gabelman -- Cowen and Company -- Analyst

Neil Mehta -- Goldman Sachs -- Analyst

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