Earnings Call: Q1 2020

May 15, 2020

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. 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 Nimbley, 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. Q1, this is a net $933,000,000 adjustment consisting of after tax non cash lower of cost or market or LCM 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'll be using certain non GAAP measures while describing PBS 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. Thanks, Colin. Good morning, everyone, thank you for joining our call from wherever you may be working. The results for the Q1 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-nineteen pandemic. Through our refining, logistics and commercial operations, we have seen the effects of COVID-nineteen 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 2 $40,000,000 announced in March to an aggregate decrease of $360,000,000 in 20 20 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 $140,000,000 We lowered corporate overhead expenses by over $20,000,000 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 $35,000,000 in cash each quarter to support the balance sheet and through the sale of 5 hydrogen plants located at our Martinez, Torrance and Delaware City refineries, we generated $530,000,000 in cash proceeds and we continue to evaluate various other liquidity and cash flow optimization options. And finally, last week, we raised $1,000,000,000 to a successful bond offering. Our total projected cost reduction measures amount to more than $600,000,000 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 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. 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 Q1 and adjusted EBITDA of negative 3,800,000 dollars These figures include approximately $11,500,000 of transaction related expenses. Consolidated CapEx for the quarter was approximately $139,000,000 which excludes amounts paid in connection with the acquisition of the Martinez refinery. The consolidated CapEx includes $133,000,000 for refining and corporate CapEx and $6,000,000 for PBF Logistics. As a result of the reductions to our 2020 capital budget, we expect to incur roughly $15,000,000 of CapEx per month from May through the end of the year. In addition to the $600,000,000 of cost reductions, we executed 2 strategic transactions to boost liquidity. We completed the sale of 5 hydrogen plants to Air Products for $530,000,000 and issued $1,000,000,000 of senior secured notes last week. As of May 1, 2020, after giving effect to these transactions, our liquidity was approximately $2,000,000,000 based on our estimated $805,000,000 of cash $150,000,000 of additional available borrowing capacity under our asset backed revolving credit facility. When combined with PBF Logistics, our consolidated liquidity is more than $2,200,000,000 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. And we will go first to Roger Read with Wells Fargo. Hey, thank you. Good morning. Hopefully can everybody hear me? Yes, Roger, we can hear you. Okay, good. I think all of us with 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 the what's written in the press release, 858,000,000 dollars after giving effect to the $1,000,000,000 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 $1,000,000,000 and have less than $1,000,000,000 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 $805,000,000 was the balance pretransaction as of May 1. So then you take the, call it, roughly $1,000,000,000 I think the net proceeds were closer to $987,500,000 after all fees and expenses. That's how we're getting to the $2,000,000,000 So the $805,000,000 plus, call it, the incremental $1,000,000,000 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? 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 4 or 6 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 pay 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. 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 days to 30 days' worth of hydrocarbon related payables. So when an increasing flat price environment, everything flips back the other way, we will start to see cash come back into the system. And just as a quick clarification on that, is it 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? 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 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 3 months and then not buy again for another 3 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 2 of the weaker markets. So I'm just curious if there's anything you can kind of incrementally help us with there? 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 III was down 43%, PADD II was down 47% and PADD V 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 5.1000000 to 7.5000000 barrels a day in the last reported EIA. 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 405 in California. PADD 3 has moved from 43% last year to 27%, PADD 2, 47% to 33%. And PADD 1 is the lag and 45% is now down 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 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? Okay. There's 3 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 3 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 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. In fact, we so it was really a prolonged turnaround much more than a couple of weeks longer than what we had expected and planned for. 2nd part, we are seeing demand increase and the numbers I had are not quite as strong as what you are saying. Hopefully, it 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 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 churned the GED 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 SEC, but candidly, we won't be running any more crude, maybe a couple of 1,000 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 hired Martinus for about a quarter. Is it performing up to your expectations? I'm asking this question because when you initially acquired Torrance, you thought 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 1 and absent the impact from the margin side from the pandemic, I will tell you they are it is a 1st class asset, 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 1st 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. Just want to follow-up on the debt issuance like with that $1,000,000,000 private notes offering, like 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 $100,000,000 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 secured 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 gears a little bit back to the CapEx. Your CapEx guidance for 2020 is down another $110,000,000 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. The actual driver on the additional CapEx reduction is predominantly turnarounds, but the turnarounds were that we are pushing out from 2020 into 2021, our 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. Have your views on the turnarounds needed like for the asset for Martinez changed since completing the acquisition 1st year? No, not at all. Thank you. We will go next to Theresa 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 LA possibly being under perpetual lockdown until there is 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 are 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 is willing to open up some things, but then the local jurisdictions have it in LA, I guess you have was it the county health supervisor who has come out and said, I think she was the one who said, it's going to LA County is going to be closed for 3 months and the Mayor 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 of months, both domestically and globally. I mean, in part 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 normalized environment where differentials are again anchored by transportation economics and quality? That's a great question. I will say start by saying, I think the volatility in the marketplace has been obvious to everybody. We are 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 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 of days doesn't the trend make, but if you take a look at the spread between ICE and David Brent had blown out $5 or $6 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 the crude side and ultimately we'll get back to the differentials. But 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 sour mediums that are being backed out in 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 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, but more normal situation and be rewarded. How long it will take? I suspect certainly we're not going to get there until after the Q2 as demand is going to is in the process of recovering and it may take a little bit longer than that, but the trends do seem to be moving in the right direction. Thank you. We'll go next to Doug Leggate with Bank of America. Thanks. 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 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'm just trying to get a feel for it because you 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? 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 0 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 $120,000,000 to $130,000,000 of CapEx that we need to incur. That's essentially, call it roughly $15,000,000 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 reduced CapEx, then ultimately do you idle any plants, right? I think on average, our refineries costs roughly $25,000,000 per month to operate in terms of operating expenses. In a shutdown scenario, you're probably spending $5,000,000 to $10,000,000 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 30,000,000 to 35,000,000 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. 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 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 direction. 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? 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 1,000,000 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 2 year no call period, these notes go away and we can really get back to business as usual. But I think we are 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 $2,000,000,000 worth of liquidity today and that's something that is extremely important to us. I appreciate the lengthy answer. Look, the demand question has been flogged to death already. But Tom, forgive me, I'm going to flog out 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 we're seeing a behavioral change here, not just here in the U. US, but globally. But more importantly, on the freight side, it seems that some of the 3rd 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? So I know it's a bit tricky, but any color you could offer would be appreciated. Certainly. And 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. 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 are down to about 8 and we basically only make jet in 2 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 we've talked about the gasoline and the same story exists there because of the cuts and runs ourselves in the whole industry and turning knobs from gasoline to distillate, we're in within the supply demand curves. Demand creeped up to last week to 7,500,000 barrels a day per the stats, Gasoline production was 7,500,000 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 the cat crackers to turn it into gasoline, not increasing runs, we're shifting product from distillate to gasoline because we're a little concerned on the distillate side of the Siam 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 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 headwinds, 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 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 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 $650,000,000 to $700,000,000 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 how to our 2021 CapEx and the expectation is that we will get continue to have a CapEx spend rate in that $650,000,000 to $700,000,000 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 are 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 that we're looking at a $15,000,000 CapEx spend and that's basically we said we cut total CapEx by $360,000,000 but the fact is that we spent a lot of that money already in Toledo because that was the biggest thing we spent over $130,000,000 on a Toledo turnaround. So we are going to sustain the $15,000,000 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 if we and it will be most likely in the turnaround area where 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, a high percentage of turnarounds, we ultimately could get into a situation where we'll have to take the 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. 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 to Toledo, but any more color than that? Thanks. 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 or 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. We will go next to Phil Gresh with JPMorgan. 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 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? 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 $530,000,000 of gross proceeds. Incremental EBITDA, basically will be about $65,000,000 to $70,000,000 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 $55,000,000 of interest expense at PBF Logistics is probably going to be in the $275,000,000 to $300,000,000 range. That includes everything. That is the new $1,000,000,000 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 2 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 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 playing out in kind of near term with the OPEC cuts just starting to kick in versus more intermediate term? You were talking a little bit about timing of OPEC barrels coming back, but just a little bit further elaboration on that. Thanks. Yes. Certainly, we've seen with Meyer has moved in significantly. It's no longer competitive. The Saudi barrels was their focus on the Asia and even the European markets. They appear to be less interested in trying to be 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, 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 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 dips 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 and we will do that. In that situation, what 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, that is going to be some consequences on that for 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. Interesting. Okay. Thank you. We will go next to Paul Cheng with Scotiabank. Hey guys, good morning. Good morning. Number of questions, so hopefully that short answer in each one. Tom, just curious that at some point the pandemic is going to be behind us. So after 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 Shenzhen project or M and 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, yes. 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 may 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 has 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 down, turned the 2nd 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 and to capitalize on to improve our overall efficiency. As we look as to the M and 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 V. 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 delevering the balance sheet. And I'll let Eric just comment further on that. 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. It just 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 Q1 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 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 6 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'd 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 Q4 of 2018 and the industry does what it oftentimes does, started cranking up to take try to capture those margins and watch gasoline build enormously through the Q4. And I have said before, if you are running your business and you are banking on the fact that you're going to get what's in a curve 3 months out, but you're running and you're not selling your product, you're not getting cash for your product and you're building an inventory, sooner or later that is going to cost you big time. So we are going to be very cognizant of and even now watching it as we look at this right we are 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 reasonable price and if it's not there, throttle back. Yes, I hope that everyone is going to take the same attitude. Tom, is there I know that I mean that we have some flexibility to push from gasoline into this and 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, 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, 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 a flash as you know. But we actually think we could use the hydrocrackers if we wanted 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. We're right in balance on 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 the refinery, you have 2 runs of the 1 February margin is at least the first 3 weeks was good and then was quite horrible in March. So is that new refinery make money at all in the Q1? So that's the first question. 2nd, when you talk about the hydrogen, the EBITDA impact $65,000,000 to $70,000,000 is that showing up when you reported the second one to show up in the gross margin or it's going to show up in the OpEx? And then finally, the RMB140 1,000,000 of the target savings, have you achieved any of them in the Q1? And how is the runway is going to progress throughout the year? Let's take those in reverse order, Paul. The $140,000,000 of savings is probably going to be recognized more second, third and fourth quarter. Again, these were all announced during the Q1. 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 Q2. 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 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 and 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 this 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? Well, let me say that the we're not going to give you specific numbers, but back several months ago to get into a price war with Russia and maybe go after shale. I don't know, you 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 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 lubes 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 Saudi barrels are not very attractively priced as you work through that one wave that had, which was almost a 1 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 PADD 3 or even other areas. And we were less than 1,000,000 barrels. I think it was significantly less than 1,000,000 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 in at least stabilized in the U. S, but we're definitely seeing a much lower demand for the export power in South America. Great. Thanks for the insights. We will go next to Jason Gabelman with Cowen. 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 in the global you've had slack global capacity and so refiners have ramped up at the first line of margin improvements and that's going to 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 are doing it on variable cost and you are not you have already covered your fixed cost and you wind up, as I said earlier, storing the barrel in the 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 are 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 increased 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 one of 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 for 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 4th largest independent refiner and if you take a look at MPC, Valero, P66 and PBF, there's over 8,000,000 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 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 are going to be very tempered in 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 then just maybe for Eric 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 30,000,000 barrels times whatever average crude and product price is. So ultimately, just for example, we had the $150,000,000 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 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 Mehta with Goldman Sachs. Hey guys, I recognize we're in overtime 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 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 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 didn't understand that if there is 100,000,000 barrels of crude demand, if we get back to that level, if it's less than that, it's got to be carved up in a way and that's what they're trying to do with the OPEC Plus. 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 10,000,000, 11,000,000 barrels of shale, but notch 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 crews that we still can get that are good crews 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 15,000,000, 16,000,000 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 precedents to bring idled assets back. This industry has demonstrated that idled 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 the structural change. The second part of your or other part of your question, okay, if you've just throttled back, it's kind of a 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 cut everything to save operating minimums and then we said we're going to shut down 2 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 are 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 the refinery, even though you are 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, etcetera. 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 Nimbley 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.